ITEM 1 - BUSINESS
GENERAL
The Company is an independent exploration and production company operating in the shallow waters of the central and western Gulf of Mexico. The Company is the principal operating subsidiary of Petsec Energy Ltd, "Parent Company," an Australian public company with ADRs listed on The Nasdaq Stock MarketSM (symbol: PSALY). Since establishing its Gulf of Mexico operations in 1990, the Company has employed a focused, integrated strategy of exploration and development to generate substantial increases in reserves, production and cash flow.
As of December 31, 1997, the Company's estimated net proved reserves were 186.0 Bcfe (approximately 66% of which were attributable to natural gas), with a PV10 of approximately $256 million.
The Company has a significant base of operations consisting of 100% working interests in 33 lease blocks and a 43.33% working interest in another lease block covering a total of 111,334 acres. Currently producing from only 18 of its lease blocks, the Company has in excess of 40 prospects on its existing acreage that it intends to drill in the next three to four years. At the March 18, 1998 OCS Louisiana offshore sale the Company was high bidder on seven lease blocks, five of which are in close proximity to the Company's existing producing leases.
COMPANY STRENGTHS AND BUSINESS STRATEGY
The Company believes that it is well positioned to continue to grow its reserves, production and cash flow by capitalizing on strengths developed since inception. These strengths include the experience of its personnel, its large inventory of drilling prospects defined by 3-D seismic data and the operating flexibility achieved through 100% ownership of leases. The Company's team of geologists, geophysicists and engineers has developed an extensive base of knowledge regarding geophysical processing and interpretation of data, as well as field operating practices in the Gulf of Mexico, and the Company believes it is well positioned to evaluate, explore and develop properties in this area.
The Company has developed a focused, integrated business strategy, which it believes capitalizes on its strengths and which incorporates the following elements:
FOCUS ON THE SHALLOW WATERS OF THE GULF OF MEXICO. Each year from the start of its operations in the Gulf of Mexico, the Company has achieved significant growth in production and reserves by concentrating its exploration and development efforts in the shallow federal and state waters (400 feet or less) in the region. The Company believes that focusing its drilling activities on properties in a relatively concentrated area in the Gulf of Mexico permits it to utilize its base of geological, engineering, and production experience in the region to enhance its drilling results and to minimize finding and development costs.
CONTROL OF OPERATIONS AND COSTS. Through a strict control over operations and costs the Company has consistently been able to lower lease operating expenses and general and administrative expense per unit of production, concurrent with increases in production. The Company holds 100% working interests in all but one of its Gulf of Mexico properties, unlike many other independent energy companies that conduct business through fractional working interests and non-operated joint ventures. Ownership of large working interests enables the Company to effectively control expenses, capital allocation, and the timing and method of exploration and development of its properties. The geographic focus of the Company allows it to manage a large asset base with a relatively small number of employees
APPLICATION OF ADVANCED TECHNOLOGIES. The Company relies significantly on advanced exploration technologies, such as 3-D seismic and time depth migration, in its lease acquisition assessment and its exploration and development activities. The Company's geotechnical staff has substantial experience in analyzing 3-D seismic data, which has enabled the Company to identify multiple exploration and development prospects in both mature producing fields where advanced technology has not previously been applied and in unexplored areas.
EXPANSION OF EXPLORATION AND DEVELOPMENT PROSPECTS. The Company intends to continue to expand its inventory of exploration and development prospects through an active lease acquisition and exploitation program. The Company actively participates in OCS and state lease sales to build its inventory of lease blocks. While the Company intends that competitive lease sales will continue to be its primary method of building its inventory of lease blocks, it will also evaluate other opportunities to acquire properties that will complement the Company's existing reserve base and meet its economic and investment criteria.
OIL AND GAS RESERVES
The following table sets forth estimated net proved oil and gas reserves of the Company, the estimated future net revenues before income taxes and the present value of estimated future net revenues before income taxes related to such reserves as of June 30, 1994, and 1995 and December 31, 1995, 1996 and 1997. In 1996, the Company changed its fiscal year end from June 30 to December 31, and consequently, the reserves presented below reflect the periods for which the Company has reserve reports. All information in this Annual Report relating to estimated net proved oil and gas reserves and the estimated future net cash flows attributable thereto is based upon reports by Ryder Scott Company, Petroleum Engineers. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the Securities and Exchange Commission, and, except as otherwise indicated, give no effect to federal or
state income taxes otherwise attributable to estimated future net revenues from the sale of oil and gas. The present value of estimated future net revenues has been calculated using a discount factor of 10% per annum.
(1) The present value of estimated future net revenues attributable to the Company's reserves was prepared using constant prices as of the calculation date, discounted at 10% per annum on a pre-tax basis. (2) The December 31, 1997 amount was calculated using an average oil price of $17.00 per barrel and an average gas price of $2.39 per Mcf, which include adjustments to reflect the effect of hedging. Prices received subsequent to year end are lower than those used in the calculation. (3) The standardized measure of discounted future net cash flows represents the present value of estimated future net revenues after income tax discounted at 10% per annum.
There are numerous uncertainties inherent in estimating quantities of proved reserves, future rates of production and the timing of development expenditures, including many factors beyond the control of the Company. The reserve data set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and 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, engineering and geological interpretation and judgment and the existence of development plans. As a result, estimates of reserves made by different engineers for the same property will often vary. Results of drilling, testing and production subsequent to the date of an estimate may justify a revision of such estimates. Accordingly, reserve estimates generally differ from the quantities of oil and gas ultimately produced. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geological success, prices, future production levels and costs that may not prove to be correct. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of such estimates depends on the accuracy of the assumptions upon which they are based.
ACQUISITION,PRODUCTION AND DRILLING ACTIVITY
Acquisition and Development Costs. The following table sets forth certain information regarding the costs incurred by the Company in its acquisition, exploration and development activities:
Years Ended December 31 --------------------------------- 1995 1996 1997 ---- ---- ---- (In thousands)
Acquisition costs $ 2,930 $ 6,699 $ 8,437 Exploration costs 34,786 71,490 115,523 Development costs 12,925 14,187 31,327 -------- -------- ---------
Total costs incurred $50,641 $92,376 $155,287 ======= ======= ========
Productive Well and Acreage Data. The following table sets forth certain statistics for the Company regarding the number of productive wells and developed and undeveloped acreage in the Gulf of Mexico as of December 31, 1997:
Gross Net ---------- ----------- Productive Wells(1): Oil(2) 16 16.0 Gas(3) 30 28.7 ---------- ------------ Total 46 44.7 ========== ============ Developed Acreage(1) 46,654 43,804 Undeveloped Acreage(1)(4) 64,680 64,680 ---------- ------------ Total 111,334 108,484 ========== ============
(1) Productive wells consist of producing wells and wells capable of production, including gas wells waiting on pipeline connections. Wells that are completed in more than one producing horizon are counted as one well. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres expressed as whole numbers and fractions thereof. (2) Two gross wells each have dual completions. (3) Nine gross wells each have dual completions (4) Leases covering 15% of the Company's undeveloped acreage will expire in 1998, approximately 8% in 1999, 23% in 2000, 37% in 2001, and 17% in 2002.
Drilling Activity. The following table sets forth the Company's drilling activity for the periods indicated.
Years Ended December 31, ------------------------------------------------
1995 1996 1997 ---- ---- ---- Gross Net Gross Net Gross Net Gulf of Mexico Exploratory wells 4 4 1 1 13 13.0 Development wells 3 3 7 7 4 4.0 Dry holes 0 0 0 0 3 2.4 --- --- --- --- --- -----
Total 7 7 8 8 20 19.4 === === === === === ====
OIL AND GAS MARKETING
All of the Company's natural gas, oil and condensate production was sold at market prices under short-term contracts providing for variable or market sensitive prices. The Company has not experienced any difficulties in marketing its oil or gas.
There are a variety of factors which affect the market for oil and gas, including the extent of domestic production and imports of oil and gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and gas, the marketing of competitive fuels and the effects of state and federal regulations of oil and gas production and sales. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual customers.
From time to time, the Company has utilized hedging transactions with respect to a portion of its oil and gas production to achieve more predictable cash flows, as well as to reduce its exposure to fluctuations in oil and gas prices. The Company restricts the time and quantity of the aggregate oil and gas production covered by such transactions. See "Management's Discussion and Analysis of Financial Condition and Results of Operations --Hedging Transactions."
Despite the measures taken by the Company to attempt to control price risk, the Company remains subject to price fluctuations for oil and natural gas sold in the spot market due primarily to seasonality of demand and other factors beyond the Company's control. Domestic oil prices generally follow worldwide oil prices, which are subject to price fluctuations resulting from changes in world supply and demand. The Company continues to evaluate the potential for reducing these risks, and expects to enter into additional hedge transactions in future years. In addition, the Company also may close out any portion of the existing, or yet to be entered into, hedges as determined to be appropriate by management.
PRODUCTION SALES CONTRACTS
The Company markets all of the oil and gas production from its properties. All of the Company's crude oil and gas production is sold to a variety of purchasers under short-term (less than twelve months) contracts or thirty-day spot purchase contracts. Natural gas and crude oil sales contracts are based upon field posted prices plus negotiated bonuses. During calendar 1997, Duke Energy Trading & Marketing , L.L.C. (formerly Pan Energy Trading and Market Services, L.L.C.), P G & E Energy Trading Corporation, and Natural Gas Clearinghouse each purchased in excess of 10% of the gas sold by the Company and Vision Resources, Inc. purchased in excess of 10% of the oil sold by the Company. Based upon current demand for oil and gas, the Company does not believe the loss of any of these purchasers would have a material adverse effect on the Company.
Most of the Company's oil and all of the Company's gas is transported through gathering systems and pipelines that are not owned by the Company. Transportation space on such gathering systems and pipelines is occasionally limited, and at times unavailable, due to repairs or improvements being made to such facilities or due to such space being utilized by other oil or gas shippers with priority transportation agreements. While the Company has not experienced any inability to market its natural gas and oil, if transportation space is restricted or unavailable, the Company's cash flow could be adversely impacted.
COMPETITION
The oil and gas industry is highly competitive. The Company competes for the acquisition of oil and gas properties with numerous other entities, including major oil companies, other independent oil and gas concerns and individual producers and operators. Many of these competitors have financial, technical and other resources substantially greater than those of the Company. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
REGULATION
The oil and gas industry is regulated extensively by federal, state and local authorities. In particular, oil and gas production operations and economics are affected by price controls, environmental protection statutes and regulations, tax statutes and other laws relating to the petroleum industry, as well as changes in such laws, changing administrative regulations and the interpretations and application of such laws, rules and regulations. In October 1992, comprehensive national energy legislation was enacted which focuses on electric power, renewable energy sources and conservation. This legislation, among other things, guarantees equal treatment of domestic and imported natural gas supplies, mandates expanded use of natural gas and other alternative fuel vehicles, funds natural gas research and development, permits continued offshore drilling and use of natural gas for electric generation and adopts various conservation measures designed to reduce consumption of imported oil. The legislation may be viewed as generally intended to encourage the development and use of natural gas. Oil and gas industry legislation and agency regulation is under constant review for amendment and expansion for a variety of political, economic and other reasons.
Regulation of Natural Gas and Oil Exploration and Production. The Company's operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled in, and the unitization or pooling of oil and gas properties. In this regard, some states (such as Oklahoma) allow the forced pooling or integration of tracts to facilitate exploration while other states (such as Texas) rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas the Company can produce from its wells and may
limit the number of wells or the locations at which the Company can drill. The regulatory burden on the oil and gas industry increases the Company's costs of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations.
The Company has operations located on federal oil and gas leases, which are administered by the MMS. Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA") (which are subject to change by the MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency (the "EPA")), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS proposed additional safety-related regulations concerning the design and operating procedures for OCS production platforms and pipelines. These proposed regulations were withdrawn pending further discussions among interested federal agencies. The MMS also has regulations restricting the flaring or venting of natural gas, liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases. Under certain circumstances, the MMS may require Company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations.
The MMS issued a notice of proposed rulemaking in which it proposed to amend its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. The proposed rule would modify the valuation procedures for both arm's length and non-arm's length crude oil transactions to decrease reliance on posted prices and assign a value to crude oil that better reflects market value, establish a new MMS form for collecting value differential data, and amend the valuation procedure for the sale of federal royalty oil. The Company cannot predict at this stage of the rulemaking proceeding how it might be affected by this amendment to the MMS' regulations.
In April 1997, after two years of study, the MMS withdrew proposed changes to the way it values natural gas for royalty payments. These proposed changes would have established an alternative market-based method to calculate royalties on certain natural gas sold to affiliates or pursuant to non-arm's length sales contracts.
Natural Gas and Oil Marketing and Transportation. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the past, the federal government has regulated the prices at which oil and gas could be sold. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended the NGPA to remove both price and non-price controls from natural gas sold in "first sales" as of January 1, 1993. While sales by
producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
Several major regulatory changes have been implemented by the FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, which remain subject to the FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purposes of many of these regulatory changes is to promote competition among the various sectors of the gas industry. The ultimate impact of these complex and overlapping rules and regulations, many of which are repeatedly subjected to judicial challenge and interpretation, cannot be predicted.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C (collectively, "Order No. 636"), which, among other things, require interstate pipelines to "restructure" to provide transportation separate, or "unbundled," from the pipelines' sales of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas supplies. Order No. 636 has been implemented as a result of FERC orders in individual pipeline service restructuring proceedings. In many instances, the result of the Order No. 636 and related initiatives have been to substantially reduce or bring to an end the interstate pipelines' traditional roles as wholesalers of natural gas in favor of providing only storage and transportation services. The FERC has issued final orders in virtually all pipeline restructuring proceedings, and has completed a series of one year reviews to determine whether refinements are required regarding individual pipeline implementations of Order No. 636.
Although Order No. 636 does not directly regulate natural gas producers such as the Company, the FERC has stated that Order No. 636 is intended to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Company and its natural gas marketing efforts. The United States Court of Appeals for the District of Columbia Circuit (the "Court") recently issued its decision in the appeals of Order No. 636. The Court largely upheld the basic tenets of Order No. 636, including the requirements that interstate pipelines "unbundle" their sales of gas from transportation and that pipelines provide open-access transportation on a basis that is equal for all gas suppliers. The Court remanded several relatively narrow issues for further explanation by the FERC. In doing so, the Court made it clear that the FERC's existing rules on the remanded issues would remain in effect pending further consideration. The Company believes that the issues remanded for further action do not appear to materially affect it. The United States Supreme Court has decided not to review the Court's decision regarding Order No. 636. In February 1997, the FERC issued Order No. 636-C, its order on remand from the Court. Order 636-C is currently pending on rehearing before the FERC. Although Order No. 636 could provide the Company with additional market access and more fairly applied transportation service rates, terms and conditions, it could also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violations of those tolerances. The Company does not believe, however, that it will be affected by any action taken with respect to Order No. 636 materially differently than other natural gas producers and marketers with which it competes.
The FERC has issued a statement of policy and a request for comments concerning alternatives to its traditional cost-of-service rate making methodology. This policy statement articulates the criteria that the FERC will use to evaluate proposals to charge market-based rates for the transportation of natural gas. The policy statement also provides that the FERC will consider proposals for negotiated rates for individual shippers of natural gas, so long
as a cost-of-service-based rate is available as a recourse rate. The FERC also has requested comments on whether it should allow gas pipelines the flexibility to negotiate the terms and conditions of transportation service with prospective shippers. The Company cannot predict what further action the FERC will take on these matters, however, the Company does not believe that it will be affected by any action taken materially differently than other natural gas producers and marketers with which it competes.
The FERC has announced its intention to reexamine certain of its transportation-related policies, including the manner in which interstate pipeline shippers may release interstate pipeline capacity under Order No. 636 for resale in the secondary market. While any resulting FERC action would affect the Company only indirectly, the FERC's current rules and policies may have the effect of enhancing competition in natural gas markets by, among other things, encouraging non-producer natural gas marketers to engage in certain purchase and sale transactions. The Company cannot predict what action the FERC will take on these matters, nor can it accurately predict whether the FERC's actions will achieve the goal of increasing competition in markets in which the Company's natural gas is sold. However, the Company does not believe that it will be affected by any action taken materially differently than other natural gas producers and marketers with which it competes.
The FERC has issued a policy statement on how interstate natural gas pipelines can recover the costs of new pipeline facilities. While the FERC's policy statement on new construction cost recovery affects the Company only indirectly, in its present form, the new policy should enhance competition in natural gas markets and facilitate construction of gas supply laterals. The FERC has denied requests for rehearing of this policy statement. The FERC has issued numerous orders approving the spin-down or spin-off by interstate pipelines of their gathering facilities. A "spin-off" is a FERC-approved sale of gathering facilities to a non-affiliate. A "spin-down" is a transfer of gathering facilities to an affiliate. These approvals were given despite the strong protests of a number of producers concerned that any diminution in FERC's oversight of interstate pipeline-related gathering services might result in a denial of open access or otherwise enhance the pipeline's monopoly power. While the FERC has stated that it will retain limited jurisdiction over such gathering facilities and will hear complaints concerning any denial of access, it is unclear what effect the FERC's gathering policy will have on producers such as the Company and the Company cannot predict what further action the FERC will take on these matters.
Commencing in October 1993, the FERC issued a series of rules (Order Nos. 561 and 561-A) establishing an indexing system under which oil pipelines will be able to change their transportation rates, subject to prescribed ceiling levels. The indexing system, which allows or may require pipelines to make rate changes to track changes in the Producer Price Index for Finished Goods, minus one percent, became effective January 1, 1995. The FERC's decision in this matter was recently affirmed by the Court. The Company is not able at this time to predict the effects of Order Nos. 561 and 561-A, if any, on the transportation costs associated with oil production from the Company's oil producing operations.
Additional proposals and proceedings that might affect the oil and gas industry are pending before the FERC and the courts. The Company cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by the FERC will continue indefinitely. Notwithstanding the foregoing, the Company does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of the Company.
Environmental Regulation. Activities of the Company with respect to the exploration, development and production of oil and natural gas are subject to stringent environmental regulation by state and federal authorities including the EPA. Such regulation has increased the cost of planning, designing, drilling, operating and in some instances, abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products and waste created by water and air pollution control procedures. Although the Company believes that compliance with environmental regulations will not have a material adverse effect on operations or earnings, the risks of substantial costs and liabilities are inherent in oil and gas operations, and there can be no assurance that significant costs and liabilities, including criminal penalties, will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or person resulting from the Company's operations could result in substantial costs and liabilities.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include the owner and operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at such site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The Company generates wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA and various state agencies have limited the disposal options for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by the Company's oil and natural gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements.
The Company currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Company's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While
liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. For tank vessels, including mobile offshore drilling rigs, the OPA imposes on owners, operators and charterers of the vessels, an obligation to maintain evidence of financial responsibility of up to $10 million depending on gross tonnage. With respect to offshore facilities, proof of greater levels of financial responsibility may be applicable. For offshore facilities that have a worst case oil spill potential of more than 1,000 barrels (which includes many of the Company's offshore producing facilities), certain amendments to the OPA that were enacted in 1996 provide that the amount of financial responsibility that must be demonstrated by most facilities range from $10 million in specified state waters to $35 million in federal OCS waters, with higher amounts, up to $150 million in certain limited circumstances where the MMS believes such a level is justified by the risks posed by the quantity or quality of oil that is handled by the facility. On March 25, 1997, the MMS promulgated a proposed rule implementing these OPA financial responsibility requirements. Under the proposed rule, the amount of financial responsibility required for a facility would depend on the "worst case" oil spill discharge volume calculated for the facility. For oil and gas producers such as the Company operating offshore facilities in OCS waters, worst case discharge volumes of up to 35,000 barrels will require a financial responsibility demonstration of $35 million, while worst case discharge volumes in excess of 35,000 barrels will require demonstrations ranging from $70 million to $150 million.
The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities at no significant increase in expense over recent prior years. However, the Company cannot predict whether these financial responsibility requirements under the OPA amendments or proposed rule will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico. OPA also imposes other requirements on facility operators, such as the preparation of an oil spill contingency plan. The Company has such plans in place. The failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or even criminal liability.
OPERATING HAZARDS AND INSURANCE
Oil and gas drilling and production activities are subject to numerous risks, many of which are beyond the Company's control. These risks include the risk that no commercially productive oil or natural gas reservoirs will be encountered, that operations may be curtailed, delayed or canceled as a result of title problems, weather conditions, compliance with governmental requirements, mechanical difficulties or shortages or delays in the delivery of equipment and that the availability or capacity of gathering systems, pipelines or processing facilities may limit the Company's ability to market its production. 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 natural gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.
In addition, the Company's properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. Industry operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, 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. Additionally, the Company's oil and gas operations are located in an area that is subject to tropical weather disturbances, some of which can be severe enough to cause substantial damage to facilities and possibly interrupt production.
The MMS requires lessees of OCS properties to post performance bonds in connection with the plugging and abandonment of wells located offshore and the removal of all production facilities. The Company has posted an area wide bond meeting MMS requirements and has obtained additional supplemental bonding on its offshore leases as required by the MMS.
The Company maintains customary oil and gas related third party liability coverage, which it must renew annually, that insures the Company against certain sudden and accidental risks associated with drilling, completing and operating its wells. There can be no assurance that this insurance will be adequate to cover any losses or exposure to liability or that the Company will be able to renew its coverage annually. The Company carries workers' compensation insurance in all states in which it operates. While the Company believes this coverage is customary in the industry, it does not provide complete coverage against all operating risks.
EMPLOYEES
The Company presently has 53 full-time employees, primarily professionals, including geologists, geophysicists and engineers. The Company also relies on the services of certain consultants for technical and operational guidance. The Company believes that its relationships with its employees and consultants are satisfactory and has entered into employment and consulting contracts with its executives and agreements with certain technical personnel and consultants whom it considers particularly important to the operations of the Company. There can be no assurance that such individuals will remain with the Company for the immediate or foreseeable future. None of the Company's employees are covered by a collective bargaining agreement. From time to time, the Company also utilizes the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well site surveillance, permitting and environmental assessment. Field and on-site production operation services, such as maintenance, dispatching, inspection and testing, are generally provided by independent contractors supervised by Company employees.
FORWARD-LOOKING STATEMENTS
This Annual Report includes "forward-looking statements" within the meaning of Section 27A of 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 in this Annual Report, including without limitation statements under "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 1 - Business" regarding the planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled in 1998 and thereafter, 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, it can give no assurance that such expectations will prove to have been correct. There are numerous risks and uncertainties that can affect the outcome of certain events including many factors beyond the control of the Company. These factors include but are not limited to the matters that are described below. 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.
SUBSTANTIAL LEVERAGE
As of December 31, 1997, the Company's long-term debt was $136.9 million, of which $99.6 million was senior subordinated notes and $37.3 million was a subordinated shareholder loan. As of December 31, 1997, the Company had $50 million committed but undrawn under the Company's Bank credit facility.
The Company's level of indebtedness will have several important effects on its operations, including (i) a substantial portion of the Company's cash flow from operations will be dedicated to the payment of interest on its indebtedness and will not be available for other purposes, (ii) the covenants contained in the indenture governing the Senior Subordinated Notes limit its ability to borrow additional funds or to dispose of assets and may affect the Company's flexibility in planning for, and reacting to, changes in business conditions and (iii) the Company's ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired. Moreover, future acquisition or development activities may require the Company to alter its capitalization significantly. These changes in capitalization may significantly alter the leverage of the Company. The Company's ability to meet its debt service obligations and to reduce its total indebtedness will be dependent upon the Company's future performance, which will be subject to general economic conditions and to financial, business and other factors affecting the operations of the Company, many of which are beyond its control. There can be no assurance that the Company's future performance will not be adversely affected by such economic conditions and financial, business and other factors. See "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources."
VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION
The Company's revenue, profitability and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in the Middle East, the foreign supply of oil and natural gas, the price of oil and gas imports and overall economic conditions. From time to time, oil and gas prices have been depressed by excess domestic and imported supplies. There can be no assurance that current price levels will be sustained. It is impossible to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices may adversely affect the Company's financial condition, liquidity and results of operations and may reduce the amount of the Company's oil and natural gas that can be produced economically. Additionally, substantially all of the Company's sales of oil and natural gas are made in the spot market or pursuant to contracts based on spot
market prices and not pursuant to long-term fixed price contracts. With the objective of reducing price risk, the Company enters into hedging transactions with respect to a portion of its expected future production. There can be no assurance, however, that such hedging transactions will reduce risk or mitigate the effect of any substantial or extended decline in oil or natural gas prices. Any substantial or extended decline in the prices of oil or natural gas would have a material adverse effect on the Company's financial condition and results of operations.
In addition, the marketability of the Company's production depends upon the availability and capacity of gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand all could adversely affect the Company's ability to produce and market its oil and natural gas. If market factors were to change dramatically, the financial impact on the Company could be substantial. The availability of markets and the volatility of product prices are beyond the control of the Company and represent a significant risk. See "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations -- Overview" and "Item 1 - Business - -- Oil and Gas Marketing."
UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES
This Annual Report contains estimates of the Company's proved oil and gas reserves and the estimated future net revenues therefrom based upon the Ryder Scott Reports that rely upon various assumptions, including assumptions required by the Commission as to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. As a result, such estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated in the Ryder Scott Reports. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this Annual Report. In addition, the Company's proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing oil and gas prices and other factors, many of which are beyond the Company's control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to the Company's reserves will likely vary from the estimates used, and such variances may be material.
Approximately 25% of the Company's total proved reserves at December 31, 1997 were undeveloped, which are by their nature less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. The reserve data set forth in the Ryder Scott Report assumes that substantial capital expenditures by the Company will be required to develop such reserves. Although cost and reserve estimates attributable to the Company's oil and gas reserves have been prepared in accordance with industry standards, no assurance can be given that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated. See "Item 1 - Business -- Oil and Gas Reserves."
The present value of future net revenues referred to in this Annual Report 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 Securities and Exchange Commission, the estimated discounted future net cash flows from proved reserves are 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 changes in consumption by 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 Securities and Exchange Commission to be used in calculating discounted future net cash flows 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 or the oil and gas industry in general.
REPLACEMENT OF RESERVES
As is customary in the oil and gas exploration and production industry, the Company's future success depends upon its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless the Company replaces its estimated proved reserves (through development, exploration or acquisition), the Company's proved reserves will generally decline as they are produced.
The Company's current strategy includes increasing its reserve base through acquisitions of lease blocks with drilling potential and by continuing to exploit its existing properties. There can be no assurance, however, that the Company's exploration and development projects will result in significant additional reserves or that the Company will have continuing success drilling productive wells at economically viable costs. Furthermore, while the Company's revenues may increase if prevailing oil and gas prices increase significantly, the Company's finding costs for additional reserves could also increase. For a discussion of the Company's reserves, see "Item 1 - Business -- Oil and Gas Reserves."
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company makes, and will continue to make, substantial expenditures for the development, exploration, acquisition and production of oil and natural gas reserves. The Company made capital expenditures, including exploration expense, of $92 million during 1996 and $155 million during 1997. Management believes that the Company will have sufficient cash provided by operating activities and borrowings under the Bank credit facility to fund future capital expenditures. However, if revenues or cash flows from operations decrease as a result of lower oil and natural gas prices or operating difficulties, the Company may be limited in its ability to expend the capital necessary to undertake or complete its drilling program, or it may be forced to raise additional debt or equity proceeds to fund such expenditures. There can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet these requirements. See "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources."
INDUSTRY RISKS
Oil and gas drilling and production activities are subject to numerous risks, many of which are beyond the Company's control. These risks include the risk that no commercially productive oil or natural gas reservoirs will be encountered, that operations may be curtailed, delayed or canceled and that title problems, weather conditions, compliance with governmental requirements, mechanical difficulties or shortages or delays in the delivery of drilling rigs, work boats and other equipment may limit the Company's ability to market its production. 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 natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. In addition, the Company's properties may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties.
Industry operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, 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. Additionally, the Company's oil and gas operations are located in an area that is subject to tropical weather disturbances, some of which can be severe enough to cause substantial damage to facilities and possibly interrupt production. 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 any insurance will be adequate to cover losses or liabilities. The Company cannot predict the continued availability of insurance at premium levels that justify its purchase.
GOVERNMENTAL REGULATION
Oil and gas operations are subject to various United States federal, state and local governmental regulations that change from time to time in response to economic or political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. To date, expenditures related to complying with these laws and for remediation of existing environmental contamination have not been significant in relation to the results of operations of the Company. Although the Company believes it is in substantial compliance with all applicable laws and regulations, the requirements imposed by such laws and regulations are frequently changed and subject to interpretation, and the Company is unable to predict the ultimate cost of compliance with these requirements or their effect on its operations. See "Item 1 - Business -- Regulation."
RELIANCE ON KEY PERSONNEL
The Company's operations are dependent upon a relatively small group of key management and technical personnel. There can be no assurance that such individuals will remain with the Company for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on the Company. See "Item 10 - Directors and Executive Officers of the Registrant."
COMPETITION
The Company operates in a highly competitive environment. The Company competes with major and independent oil and gas companies for the acquisition of desirable oil and gas properties, as well as for the equipment and labor required to develop and operate such properties. Many of these competitors have financial and other resources substantially greater than those of the Company. See "Item 1 - Business -- Competition."
RISKS OF HEDGING TRANSACTIONS
In order to manage its exposure to price risks in the marketing of its oil and natural gas, the Company has in the past and expects to continue to enter into oil and natural gas price hedging arrangements with respect to a portion of its expected production. These arrangements may include futures contracts on the New York Mercantile Exchange (NYMEX), fixed price delivery contracts and financial swaps. While intended to reduce the effects of volatility of the price of oil and natural gas, such transactions may limit potential gains by the Company if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose the Company to the risk of financial loss in certain circumstances, including instances in which (i) production is less than expected, (ii) if there is a widening of price differentials between delivery points for the Company's production and the delivery point assumed in the hedge arrangement, (iii) the counterparties to the Company's future contracts fail to perform the contract or (iv) a sudden, unexpected event materially impacts oil or natural gas prices. See "Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations -- Hedging Transactions" and "Item 1 - Business -- Oil and Gas Marketing."
ITEM 2
ITEM 2 - DESCRIPTION OF PROPERTIES
ITEM 2 (A) - SIGNIFICANT PROPERTIES
The Company has grown principally through the acquisition and development of properties in the Gulf of Mexico offshore Louisiana. The first four leases were acquired from the State of Louisiana, four leases were purchased from third parties and the remaining leases have been acquired at Gulf of Mexico State and Federal OCS lease sales. At December 31, 1997 the Company had 34 lease blocks in the Gulf of Mexico. All of the Company's proved oil and gas reserves at December 31, 1997 were in these blocks.
ITEM 2 (B) - RESERVES
The information on the Company's oil and gas reserves is set out under Item 1 on page 6.
The information on the Company's oil and gas production is set out under Item 7 on page 25.
ITEM 3
ITEM 3 - LEGAL PROCEEDINGS
LEGAL PROCEEDINGS
The Company has been named as a defendant in certain lawsuits arising in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on the financial position, results of operations or liquidity of the Company.
ITEM 4
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
PART II
ITEM 5
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All the shares of common stock are held by the Parent Company, Petsec Energy Ltd. See "Notes to Financial Statements -- Note 1(a) Description of Business" on page 42.
ITEM 6
ITEM 6 - SELECTED FINANCIAL DATA
The following table sets forth selected historical financial data for the Company as of and for each of the periods indicated. The financial data, for the years ended December 31, 1994, 1995, 1996 and 1997 are derived from the financial statements of the Company audited by KPMG Peat Marwick LLP, independent auditors. The financial data, for the year ended December 31, 1993 is derived from the Company's unaudited financial statements which, in the opinion of management, include all adjustments (which consist only of normal recurring adjustments) necessary for a fair presentation of the financial position and results of operations of the Company for such period. The following information should be read in conjunction with "Item 7
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion is intended to assist in the understanding of the Company's historical financial position and results of operations for each year in the three years ended December 31, 1997. Financial Statements and notes thereto included elsewhere in this Annual Report should be referred to in conjunction with the following discussion.
OVERVIEW
The Company is the principal operating subsidiary of Petsec Energy Ltd, an Australian public company with ADRs listed on The Nasdaq Stock Market SM. The Company was incorporated in March 1990 to evaluate oil and gas exploration opportunities in the United States. In 1990, the Company participated in an oil discovery in the Paradox Basin in Colorado. In addition the Company acquired oil and gas lease interests in northern California. The Company also established an office in Lafayette, Louisiana, hired several former employees of Tenneco Oil Company and acquired leases in the Gulf of Mexico, offshore Louisiana. The Company subsequently made a strategic decision to focus its efforts entirely in the Gulf of Mexico and disposed of its interests in the Paradox Basin in January 1995.
The Company has acquired substantially all of its 34 leases in the Gulf of Mexico at federal or state lease sales. The Company maintains an active lease acquisition program in order to increase its inventory of prospects. To date, the Company has retained a 100% working interest ownership in all but one of its leases in the Gulf of Mexico, which enables it to effectively control expenses, capital allocation, and the timing and method of exploration and development of its properties. In the future, the Company intends to maintain substantial working interest positions.
The Company has historically expanded its oil and gas reserves principally through drilling. The Company is currently producing from 18 of its lease blocks. The Company's activities are focused in the shallow waters of the Gulf of Mexico, which provides the Company with access to the substantial infrastructure of the Gulf and allows the Company to utilize lower cost rigs and equipment in bringing its production on line. Over the last three years, concurrent with increases in production, the Company has lowered its lease operating expenses and general and administrative expenses per unit of production.
The Company has significantly increased production and proved reserves in the last three years. Production has increased from 13,603 MMcfe in 1995 to 46,408 MMcfe in 1997. As of December 31, 1997, the Company's proved reserves were 186.0 Bcfe, 66% of which were natural gas.
The Company markets its oil through spot price contracts and typically receives a premium above the price posted. The Company's gas production is sold under contracts which generally reflect spot market conditions in the central Gulf of Mexico. The Company has historically entered into crude oil and natural gas price swaps to reduce its exposure to price fluctuations. The results of operations described herein reflect any hedging transactions undertaken by the Company. See Note 10 to the Financial Statements.
The Company follows the successful efforts method of accounting. Under this method, the Company capitalizes lease acquisition costs, costs to drill and complete exploration wells in which proved reserves are discovered and costs to drill and complete development wells. Costs to drill exploratory wells that do not find proved reserves are expensed. Seismic, geological and geophysical, and delay rental expenditures are expensed as incurred.
The Company is allocated stock compensation expense in respect to options in Petsec Energy Ltd (the Parent) which are granted to the Company's employees and certain consultants. In 1996, the Parent adopted SFAS No. 123, Accounting for Stock-Based Compensation under which it recognizes as expense over the vesting period the fair value of all stock based awards on the date of grant. See Note 5 to the Financial Statements.
The Company reimburses Petsec Energy Ltd for direct expenses incurred in connection with the Company's operations. In addition, the Company has received subordinated loans from its parent to finance its operations. See "-- Liquidity and Capital Resources."
The Company's revenues, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas, which are in turn dependent upon numerous factors that are beyond the Company's control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on the Company's financial position, results of operations and access to capital, as well as the quantities of oil and gas reserves that the Company may economically produce. Current prices are lower than those realized in 1997.
The following table sets forth certain operating information with respect to the oil and gas operations of the Company. Years Ended December 31, --------------------------------- 1995 1996 1997 ---------- ---------- ----------- Net production: Gas (MMcf) 7,519 11,722 27,940 Oil (MBbls) 1,014 2,150 3,078 Total (MMcfe) 13,603 24,622 46,408 Net sales data (in thousands): Gas $13,863 $23,056 $ 64,770 Oil $16,599 $43,971 $ 60,369 Total $30,462 $67,027 $ 125,139 Average sales price (1): Gas (per Mcf) $ 1.84 $ 1.97 $ 2.32 Oil (per Bbl) $ 16.37 $ 20.45 $ 19.61 Total (per Mcfe) $ 2.24 $ 2.72 $ 2.70 Average costs (per Mcfe): Lease operating expenses $ 0.35 $ 0.25 $ 0.25 General, administrative and other expenses $ 0.33 $ 0.21 $ 0.13
(1) Includes effects of hedging activities.
RESULTS OF OPERATIONS
1997 COMPARED TO 1996
General. The Company drilled twenty wells during the year ended December 31, 1997, of which 14 have subsequently been brought into production. In addition, the Company completed the installation of facilities at West Cameron 461, South Marsh Island 7, Grand Isle 45, Main Pass 104 and Main Pass 84. This resulted in an increase in production of 21.8 Bcfe to 46.4 Bcfe in 1997, an 88% increase over the 24.6 Bcfe in 1996.
Oil and Gas Revenues. Oil and gas revenues for 1997 were $125.1 million, an increase of $58.1 million, or 87% above 1996 revenues of $67.0 million. A 43% increase in oil production offset by a 4% decrease in oil prices combined to account for $16.4 million of the increase. A 138% increase in gas production and an 18% increase in the gas price accounted for the remaining $41.7 million of the increase. Increased oil production followed the development of the Ship Shoal 194 field, while the increased gas production stems from the drilling and development of the West Cameron 461, South Marsh Island 7 and Grand Isle 45 fields.
The average realized gas price in 1997 was $2.32 per Mcf, or 8% below the $2.53 per Mcf average gas price that would have otherwise been received if no hedging had been undertaken. In the same period, the average realized oil price was $19.61 per Bbl, or 3% above the $19.10 per Bbl that would have otherwise been received if no hedging had taken place. In 1996 the average realized gas price was $1.97 per Mcf, or 24% below the $2.58 per Mcf price that would have otherwise been received if no hedging had been undertaken. In the same period the average realized oil price was $20.45 per Bbl, or 3% below the $21.04 per Bbl that would have otherwise been received if no hedging had taken place. Hedging activities resulted in a $4.4 million decrease in revenues for 1997 compared to an $8.4 million decrease in 1996.
Lease Operating Expenses. Lease operating expenses in 1997 were $11.5 million, an increase of $5.3 million, or 85%, from $6.2 million in 1996. The increase was attributable to increased production. Lease operating expenses per Mcfe were $0.25 in both years.
Depletion, Depreciation and Amortization ("DD&A"). DD&A expense increased $34.3 million, or 116%, from $29.6 million in 1996 to $63.9 million in 1997. Production increases accounted for $26.1 million of the increase while an increase in the average rate per unit from $1.20 to $1.38 per Mcfe accounted for the balance. The increase in the unit rate was due to increased capital expenditures from the Company's exploration and development activities coupled with increased costs of drilling goods and services, platform and facilities construction and transportation services in the industry. As a result of Ryder Scott reserve revisions in the fourth quarter, the unit DD&A rate was reduced to $1.25 per Mcfe in the fourth quarter compared to an average rate of $1.41 for the preceding three quarters.
Exploration Expenditures. The Company uses the successful efforts method to account for oil and gas exploration, evaluation and development expenditure. Under this method $10.5 million for dry hole and impairment costs and $7.3 million for seismic, geological and geophysical expenditures were expensed as incurred in 1997. There were no dry hole and impairment costs in 1996 while seismic, geological and geophysical expenditures totaled $7.1 million.
General and Administrative Expense. General and administrative expense increased $0.8 million, or 15%, to $6.1 million in 1997 from $5.3 million in 1996. On a per Mcfe basis the rate decreased 38% from $0.21 to $0.13 due to increased production.
Interest Expense. Interest expense in 1997 increased $4.2 million, or 124%, to $7.6 million from $3.4 million in 1996 due to increased borrowings coupled with an increased effective interest rate as a result of the Senior Subordinated Notes.
Net Income. As a result of the conditions noted above, net income for 1997 was $13.1 million, an increase of $4.2 million, or 47% over the earnings of $8.9 million for 1996.
1996 COMPARED TO 1995
General. During the year ended December 31, 1996, the Company set a larger platform and facility at Ship Shoal 193, significantly increasing production capacity at that field. In addition, a facility and pipeline was completed to tie-in its Main Pass 91 wells to its Main Pass 6/7 facility. The Company drilled and completed eight wells during the period. This activity resulted in an increase in production of 81% from 13.6 Bcfe in 1995 to 24.6 Bcfe in 1996. Average daily production for 1996 increased 81% to 67.5 MMcfe from 37.3 MMcfe for 1995.
Oil and Gas Revenues. Oil and gas revenues for 1996 were $67.0 million, an increase of $36.5 million, or 120% above 1995 revenues of $30.5 million. A 112% increase in oil production coupled with a 25% increase in oil prices combined to account for $27.3 million of the increase. A 56% increase in gas production and a 7% increase in the gas price accounted for the remaining $9.2 million of the increase. The increased oil production resulted from the tie-back of additional wells and increased capacity at Ship Shoal 193 following installation of a larger manned four pile platform. The increased gas production resulted from a full year's production at West Cameron 543/544 and commencement of production at Main Pass 91 in the second half of the year.
The average realized gas price in 1996 was $1.97 per Mcf, or 24% below the $2.58 per Mcf that would have otherwise been received if no hedging had been undertaken. In the same period the average realized oil price was $20.45 per Bbl, or 3% below the $21.04 per Bbl that would have otherwise been received if no hedging had taken place. The average realized gas price in 1995 was $1.84 per Mcf, or 4% above the $1.76 per Mcf that would have otherwise been received if no hedging had been undertaken. In the same period the average realized oil price was $16.37, or 1% above the $16.22 per Bbl that would have otherwise been received if no hedging had taken place. Hedging activities resulted in a $8.4 million decrease in revenues for 1996 compared to a $0.8 million increase in 1995.
Lease Operating Expenses. Lease operating expenses in 1996 were $6.2 million, an increase of $1.4 million, or 29%, from $4.8 million in 1995. Production efficiencies were realized as lease operating expense per Mcfe decreased from $0.35 in 1995 to $0.25 in 1996.
Depletion, Depreciation and Amortization. DD&A expense increased $20.3 million, or 218%, from $9.3 million in 1995 to $29.6 million in 1996. Production increases accounted for $7.5 million of the increase while an increase in the average rate per unit from $0.68 to $1.20 per Mcfe accounted for the balance. The increase in rate was attributable to increased capital expenditures from the Company's exploration and production activities.
Exploration Expenditures. Under the successful efforts method of accounting $7.1 million of seismic, geological and geophysical expenditures were expensed as incurred in 1996. This was an increase of $3.7 million, or 109%, over the expense of $3.4 million for 1995 as the Company expanded its access to a broader seismic base in the Gulf of Mexico.
General and Administrative Expenses. General and administrative expense increased $0.8 million, or 18%, to $5.3 million in 1996 from $4.5 million in 1995. This increase was attributable to the Company's success and resultant growth in production. On a per Mcfe basis the rate decreased 36% from $0.33 to $0.21.
Interest Expense. Interest expense in 1996 increased $0.9 million, or 36%, to $3.4 million from $2.5 million in 1995 due to increased borrowings under the Bank credit facility.
Net Income. As a result of the conditions noted above, net income for 1996 was $8.9 million, an increase of $1.9 million, or 27% over the earnings of $7.0 million for 1995.
LIQUIDITY AND CAPITAL RESOURCES
The following table represents cash flow data for the Company for the periods indicated.
Years Ended December 31, ------------------------------- 1995 1996 1997 ------------------------------- (in thousands) CASH FLOW DATA: Net cash provided by operating activities $21,561 $47,297 $95,740 Net cash used in investing activities 47,836 85,939 148,432 Net cash provided by financing activities 27,158 37,566 59,781
The fluctuation in cash provided by operating activities from 1996 to 1997 was primarily due to increased oil and gas production. Similarly the fluctuation from 1995 to 1996 was primarily due to increased oil and gas production coupled with higher prices for both commodities. Before changes in operating assets and liabilities, funds from operations were $93.7 million in 1997, $45.4 million in 1996 and $16.0 million in 1995.
The increase in cash used in investing activities in all periods was due to expenditures on exploration and development.
The cash provided by financing activities in 1997 consisted primarily of proceeds from a June 1997 Senior Subordinated Note issue (described below) a portion of which was used to repay outstandings under the bank credit facility. The cash provided by financing activities in 1995 and 1996 consisted of advances from Petsec Energy Ltd and borrowings under the bank credit facility.
Since 1990 the Company has financed its working capital needs, operations and growth primarily with advances from its parent, Petsec Energy Ltd, cash flow from operations and bank borrowings.
Petsec Energy Ltd made an initial cash investment of $11.4 million in the Company and, subsequently, increased this investment with advances of $18.5 million from an Australian offering of Ordinary Shares in September 1995 and $31.0 million out of net proceeds from a U.S. offering of ADRs in July 1996.
Funds advanced by the Parent have historically been provided in the form of subordinated loans. These loans are subordinated to the payment of all Senior Indebtedness and have been subordinated to the Notes defined herein. The US dollar loans bear interest at 7.18% and, in the case of Australian dollar borrowings, 6.83%. The loans from the Parent do not have mandatory principal payments due until December 31, 2007. No interest was paid or accrued on these loans prior to June 1, 1997. Any payments or distributions made by the Company to its Parent have been principally for reimbursement of direct expenses incurred in connection with the Company's operations.
In April 1996, the Company entered into a $75 million bank credit facility, under which the current borrowing base is $60 million. In addition, a sublimit of $15 million exists for letter of credit purposes to support the bonding requirements of the MMS and commodity swap transactions. At December 31, 1997, there were no borrowings outstanding under the bank credit facility. The bank credit facility is a two-year revolving credit facility followed by a two-year term period with equal quarterly amortization payments. The facility matures in April 2001. The bank credit facility is secured by the Company's Gulf of Mexico producing properties and contains financial covenants that require the Company to maintain a ratio of senior debt to earnings before interest, taxes, depletion, depreciation and amortization of not more than 2.75 to 1.0 and a coverage ratio of earnings before interest, taxes and depletion, depreciation and amortization to total interest of not less than 3.0 to 1.0. The Company is currently in compliance with all financial covenants under the bank credit facility. Outstanding borrowings accrue interest at the rate of LIBOR plus a margin of 1.25% to 1.50% per annum, depending upon the total amount borrowed. The Company is obligated to pay a fee equal to .30% to .35% per annum based on the unused portion of the borrowing base under the facility
The Company's ability to borrow under the bank credit facility is dependent upon the reserve value of its oil and gas properties, as determined by The Chase Manhattan Bank ("Chase"). If the reserve value of the Company's borrowing base declines, the amount available to the Company under the bank credit facility will be reduced and, to the extent that the borrowing base is less than the amount then outstanding (including letters of credit) under the bank credit facility, the Company will be obligated to repay such excess amount upon ninety days' notice from Chase or to provide additional collateral.
In June 1997, the Company issued $100 million of 9 1/2% Senior Subordinated Notes due 2007 (the "Notes"). The Notes were issued at a discount with a yield to maturity of 9.56% per annum. The net proceeds from the offering of the Notes were approximately $96.4 million. The Company used a portion of the net proceeds to repay borrowings under the bank credit facility. The remainder of the net proceeds is being used to provide working capital for the Company and to fund further exploration and development of its oil and gas properties, the acquisition of lease blocks and other general corporate purposes.
The Company intends to finance expenditures for 1998 with cash on hand, cash flow from operations and bank borrowings. The Company was high bidder on seven lease blocks at the March 18, 1998, OCS Louisiana Offshore Sale. If the Company is awarded all of these leases, the committed costs will be $7.8 million. The capital expenditure budget is continually re-evaluated based on drilling results, commodity prices, cash flow from operations and property acquisitions.
HEDGING TRANSACTIONS
From time to time, the Company has utilized hedging transactions with respect to a portion of its oil and gas production to achieve a more predictable cash flow and to reduce its exposure to oil and gas price fluctuations. While these hedging arrangements limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The credit worthiness of counter parties is subject to continuing review and full performance is anticipated. The Company limits the duration of the transactions and the percentage of the Company's expected aggregate oil and gas production that may be hedged. The Company accounts for these transactions as hedging activities and, accordingly, gains or losses are included in oil and gas revenues when the hedged production is delivered.
The Company enters into forward swap contracts with major financial institutions to reduce the price volatility on the sale of oil and gas production. In swap agreements, the Company receives the difference between a fixed price per unit of production and a floating price issued by a third party. If the floating price is higher than the fixed price, the Company pays the difference.
The Company also enters into collar agreements with third parties. A collar agreement is similar to a swap agreement except that the Company receives the difference between the floor price and the floating price if the floating price is below the floor. The Company pays the difference between the ceiling price and the floating price if the floating price is above the ceiling. The Company has proved reserves sufficient to cover all of these contracts and does not trade in derivatives without underlying forecasted production and proved reserves.
For the years ended December 31, 1995, 1996 and 1997, hedging activities increased revenues by $0.8 million and reduced revenues by $8.4 million and $4.4 million, respectively.
YEAR 2000
The Company is aware of the issues associated with the programming code in existing computer systems as the year 2000 approaches. The Company is utilizing both internal and external resources to identify, correct or reprogram, and test the systems for the year 2000 compliance. It is anticipated that all reprogramming efforts will be complete by December 31, 1998, allowing adequate time for testing. To date, confirmations have been received from the Company's primary processing vendors that plans are being developed to address processing of transactions in the year 2000. Management has not yet assessed the year 2000 compliance expense and related potential effect on the Company's financial position, results of operations or liquidity.
ITEM 7A
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not Applicable
ITEM 8
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial information in this form 10-K refers to Petsec Energy Inc., a wholly owned subsidiary of Petsec Energy Ltd. The publicly listed Petsec Energy Ltd files its annual consolidated financial statements separately under form 20-F and a summary of its quarterly consolidated financial statements under form 6-K. The response to this item begins on page 37.
ITEM 9
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None PART III
ITEM 10
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
MANAGEMENT
DIRECTORS AND EXECUTIVES
The following table sets forth the name, age and position of each person who is a director, executive officer, key employee, or who provides services to the Company.
Name Age Position - ---- --- -------- Terrence N. Fern 50 Chairman and Chief Executive Officer Anthony J. Walton 55 Director Maynard V. Smith 47 General Manager-- Exploration and Production Howard H. Wilson, Jr. 39 Vice President (Operations) Mark A. Gannaway 42 Exploration Manager Prent H. Kallenberger 43 Geophysical Manager Ross A. Keogh 38 Director, Treasurer and Financial Controller James E. Slatten III 39 Director, Secretary and Manager -- Land and Legal
Mr. Smith provides services to the Company through an arrangement with the Company's parent.
The following biographies describe the business experience of the directors, executive officers and those who provide services to the Company. Directors serve annual terms.
TERRENCE N. FERN has served as Chairman and Chief Executive Officer of the Company since 1990. Mr. Fern has over 25 years of extensive international experience in petroleum and minerals exploration, development and financing. Mr. Fern holds a Bachelor of Science degree from The University of Sydney and has followed careers in both exploration geophysics and natural resource investment.
ANTHONY J. WALTON has served as Director of the Company since 1994. Mr. Walton is President of Armstrong Holdings Corp., a private investment company and corporate finance advisory firm. Previously, Mr. Walton was Chief Executive Officer of Llama Company, a regional investment bank specializing in private equity and debt placements for medium-sized companies. Prior to joining Llama Company, Mr. Walton served as Chief General Manager, Americas and Europe, of Westpac Banking Corporation of Sydney, Australia, and held various management positions with Chase Manhattan Bank in New York and London. Mr. Walton received his Bachelor of Arts degree from Haverford College and a Master of Business Administration degree in International Finance from the Wharton Graduate School of Finance at the University of Pennsylvania.
MAYNARD V. SMITH has served as General Manager -- Exploration and Production since 1990. Mr. Smith has over 20 years of oil and gas exploration experience and has served in various technical and executive positions with Gulf Oil Corporation, Tenneco Oil Company, Natomas Oil Company, and Barcoo Petroleum Company in the United States, Australia and Southeast Asia.
Mr. Smith holds a Bachelor of Science degree in Geology from the California State University at San Diego.
HOWARD H. WILSON, JR. has served as Vice President (Operations) of the Company since 1993. Between 1981 and 1993, Mr. Wilson held various technical and managerial positions with Placid Oil Company and Nerco Oil and Gas, Inc. involving onshore and offshore oil and gas fields in Louisiana. Mr. Wilson holds a Bachelor of Science degree in Petroleum Engineering from the Louisiana Polytechnic Institute.
MARK A. GANNAWAY is the Exploration Manager of the Company. Mr. Gannaway joined the Company in July 1991. Between 1979 and 1988, Mr. Gannaway worked for Tenneco Oil Company in various technical and supervisory positions and his career with Tenneco involved working in the Midcontinent and Eastern Gulf of Mexico regions. From 1988 to 1990 Mr. Gannaway was a geologic consultant in Lafayette, Louisiana. Mr. Gannaway holds a Bachelor of Science degree in Geological Engineering from the University of Oklahoma.
PRENT H. KALLENBERGER is the Geophysical Manager of the Company. He joined the Company in September 1992. Between 1982 and 1992, Mr. Kallenberger worked in various technical and supervisory positions with Tenneco Oil Company, Union Pacific Resources, Inc., and Unocal Corporation in California and Texas. Mr. Kallenberger holds a Bachelor of Science degree in Geology from Boise State University and a Master of Science degree in Geophysics from the Colorado School of Mines.
ROSS A. KEOGH has served as Financial Controller and Treasurer of the Company since 1990 and has 15 years experience in the oil and gas industry. Between 1979 and 1989, Mr. Keogh worked in the financial accounting and budgeting divisions of Total Oil Company and as Joint Venture Administrator for Bridge Oil Limited in Australia. Mr. Keogh holds a Bachelor of Economics degree, with a major in Accounting, from Macquarie University in Sydney. Mr. Keogh was appointed as a Director in March 1998.
JAMES E. SLATTEN III was appointed as Manager--Land and Legal in January 1998. He has over 14 years experience in corporate and energy law. Prior to joining the Company he was a partner in the Louisiana law firm of Gordon, Arata, McCollam & Duplantis. Mr. Slatten holds a Bachelor of Arts degree in political science and economics from the University of Southwestern Louisiana and post-graduate degrees in law (J.D.) and business management (M.H.A.) from Tulane University. Mr. Slatten was appointed as a Director and Secretary in March 1998.
ITEM 11
ITEM 11 - EXECUTIVE COMPENSATION
COMPENSATION OF EXECUTIVE OFFICERS
The following table sets forth the compensation paid by the Company for services rendered during each of the last two fiscal years to or for the accounts of the Chief Executive Officer and the other six most highly compensated Executive Officers (collectively, the "Named Executive Officers"). The Company has entered into employment agreements with certain management and technical personnel. These agreements expire in June 1999.
(1) Mr. Fern receives no compensation from the Company. The Parent made payments in 1997 and 1996 of $290,000 and $292,334, respectively, to a company controlled by Mr. Fern's family and which provides management and geological services to the Parent. (2) "Other Annual Compensation includes payments to Mr. Stevens of $61,374 for relocation costs. (3) Options issued are in respect of ordinary shares in the Parent Company. (4) "All Other Compensation" includes forgiveness of a loan to Mr. Stevens for housing assistance. (5) Mr. Stevens resigned as an Officer and Director of the Company in December, 1997. (6) Mr. Warren resigned as an Officer and Director of the Company in November, 1997
SHARE AND OPTION PLANS
The Parent maintains an Employee Share Plan (the "Share Plan") and an Employee Share Option Plan (the "Option Plan"). Both plans were approved by the shareholders at the Parent's 1994 Annual General Meeting and are administered by a committee (the "Remuneration Committee") appointed by the Board of Directors of the Parent. The total number of Ordinary Shares issued or subject to option under all share and option plans during any five year period may not exceed 5% of the total number of issued Ordinary Shares at the relevant date.
The Share Plan provides for the issue of Ordinary Shares to employees and directors at prevailing market prices. Purchases pursuant to the Share Plan are financed by interest free loans from the Parent, subject to certain conditions set by the Remuneration Committee. Grants are subject to a minimum six month vesting term and the vesting may also be contingent upon the market price of the Ordinary Shares on the Australian Stock Exchange ("ASX") achieving certain benchmarks. After the vesting of such shares, the grantee may either repay the Parent loan or sell such shares and retain the difference. As of December 31, 1997, all employees and directors of the Company, in the aggregate, owned 1,525,000 Ordinary Shares subject to the terms of this Plan.
The Option Plan provides for the issue of options to purchase Ordinary Shares to employees and directors at prevailing market prices and subject to certain conditions set by the Remuneration Committee. Grants are subject to a minimum six month vesting term and the vesting may also be contingent upon the market price on the ASX of the Ordinary Shares achieving certain benchmarks. Options granted under the Option Plan expire five years from the date of grant. As of December 31, 1997, all directors and employees of the Company, in the aggregate, held options to purchase an aggregate of 1,361,000 Ordinary Shares pursuant to the Option Plan.
STOCK OPTION GRANTS AND EXERCISES
The Parent did not grant any stock options or stock appreciation rights ("SARs") to the Named Executive Officers of the Company in 1997.
The following table sets forth the aggregated option exercises by each of the Named Executive Officers during the year ended December 31, 1997.
COMPENSATION OF DIRECTORS
Anthony J. Walton was paid $20,000 in 1997 and $40,000 in 1996 for services as a director pursuant to an arrangement whereby Mr. Walton provided financial advice to the Company. In 1997 Mr. Walton was granted options underlying 50,000 ordinary shares of the Parent Company at an exercise price of A$5.69. The exercise price for the options is in Australian dollars ("A$") being the currency of the ordinary shares subject to the options. The expiry date is June 29, 2001. There were no other arrangements pursuant to which directors of the Company receive compensation for their services as directors in 1997 or 1996.
ITEM 12
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The Common Stock of the Company is owned by Petsec (USA) Inc. which is a wholly owned subsidiary of the Parent Company, Petsec Energy Ltd. See "Notes to Financial Statements -- Note 1(a) Description of Business" on page 42.
ITEM 13
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company has historically been financed in part with borrowings from its immediate parent company, Petsec (U.S.A.), Inc., which is an indirect wholly-owned subsidiary of Petsec Energy Ltd. Outstanding borrowings (the "Subordinated Shareholder Loan") are made by the Company under a subordinated note (the "Subordinated Shareholder Note") in either or both U.S. or Australian dollars, which effective as of June 1, 1997 bears interest at market rates, currently LIBOR plus 1.5% or, in the case of Australian dollar borrowings, the Australian bank bill rate plus 1.5%. The Subordinated Shareholder Note provides that the Subordinated Shareholder Loan (i) is subordinated in right of payment to all present and future Indebtedness of the Company for borrowed money and (ii) not subject to any mandatory principal or sinking fund payment, or mandatory repurchase obligation, until 91 days following the final Stated Maturity of the Notes. The Company has agreed not to modify these two terms of the Subordinated Shareholder Loan until all outstanding Notes have been paid in full, retired or acquired in their entirety by Affiliates of the Company. As of December 31 1997, the amount of Subordinated Shareholder Loan outstanding was $37.3 million.
Three executives, Mark Gannaway, Prent Kallenberger and Maynard Smith, also own overriding royalty interests on certain leases held by the Company, which were issued prior to July 1994 as incentives. As of July 1994, the granting of overriding royalty interests as an incentive was replaced by grants under the Parent's Option Plan.
PART IV
ITEM 14
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
1. FINANCIAL STATEMENTS
Independent Auditors' Report. . . . . . . . . . . . . . . . . . . . . . 38 Balance Sheets as of December 31, 1996, and 1997 . . . . . . . . . . . . . 39 Statements of Operations and Retained Earnings for the years ended December 31, 1995, 1996 and 1997 . . . . . . . . . . . . . . . . . . . . 40 Statements of Cash Flows for the years ended December 31, 1995, 1996 and 1997. . . . . . . . . . . . . . . . . . . . 41 Notes to Financial Statements. . . . . . . . . . . . . . . . . . . . . . 42
INDEPENDENT AUDITORS' REPORT
The Board of Directors Petsec Energy Inc.:
We have audited the accompanying balance sheets of Petsec Energy Inc. as of December 31, 1996 and 1997 and the related statements of operations and retained earnings and cash flows for each of the years in the three-year period ended December 31, 1997. 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 in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Petsec Energy Inc. as of December 31, 1996 and 1997, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 1997 in conformity with generally accepted accounting principles.
As discussed in note 5 to the financial statements, in 1996 the Parent Company adopted the method of accounting for stock-based compensation prescribed by the Statement of Financial Accounting Standards No. 123 for the expense allocated to the Company.
KPMG PEAT MARWICK LLP
New Orleans, Louisiana January 30, 1998
PETSEC ENERGY INC.
A WHOLLY OWNED SUBSIDIARY OF PETSEC ENERGY LTD
BALANCE SHEETS (DOLLARS IN THOUSANDS, EXCEPT SHARE AMOUNTS)
See accompanying notes to financial statements.
PETSEC ENERGY INC.
A WHOLLY OWNED SUBSIDIARY OF PETSEC ENERGY LTD
STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (DOLLARS IN THOUSANDS)
See accompanying notes to financial statements.
PETSEC ENERGY INC.
A WHOLLY OWNED SUBSIDIARY OF PETSEC ENERGY LTD
STATEMENTS OF CASH FLOWS (DOLLARS IN THOUSANDS)
See accompanying notes to financial statements.
PETSEC ENERGY INC.
NOTES TO FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Description of Business
Petsec Energy Inc.(the Company), located in Lafayette, Louisiana, is a wholly-owned subsidiary of Petsec (U.S.A.) Inc., which is a wholly-owned subsidiary of Petsec America Pty. Limited, a company incorporated in Australia. The ultimate holding company is Petsec Energy Ltd (the Parent Company), (formerly Petroleum Securities Australia Limited), also incorporated in Australia.
The primary business of the Company is exploration, development and production of oil and gas; therefore, the Company is directly affected by fluctuating economic conditions of the oil and gas industry. The Company's activities are focused in the shallow waters of the Gulf of Mexico, primarily offshore Louisiana and Texas.
(b) Income Taxes
The Company is included in the consolidated federal and state income tax returns of Petsec (U.S.A.) Inc. The income tax provision has been prepared as if the Company were a separate taxpayer.
The Company accounts for income taxes under Statement of Financial Accounting Standards No. 109 (Statement 109), Accounting for Income Taxes. Under the asset and liability method of Statement 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under Statement 109, the effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
(c) Oil and Gas Properties
The Company uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, and geological and geophysical costs are expensed.
Unproved oil and gas properties are periodically assessed on a property-by-property basis, and a loss is recognized to the extent, if any, that the cost of the property has been impaired. Capitalized costs of producing oil and gas properties are depreciated and depleted by the units-of-production method.
Effective in 1996, the Company began assessing the impairment of capitalized costs of proved oil and gas properties and other long-lived assets in accordance with Statement of Financial Accounting Standards No. 121
(Statement 121), Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. Under this method, the Company generally assesses its oil and gas properties on a field-by-field basis, utilizing its current estimate of future revenues and operating expenses. In the event net undiscounted cash flow is less than the carrying value, an impairment loss is recorded based on estimated fair value, which would consider discounted future net cash flows. Prior to 1996, this assessment had been determined on a company-wide basis. The adoption of Statement 121 did not have an effect on the Company's financial position or results of operations.
The estimated costs of dismantling and abandoning offshore oil and gas properties are provided currently using the units-of-production method. Such provision is included in depletion, depreciation and amortization in the accompanying statement of operations.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depletion, depreciation and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized.
(d) Other Property, Plant and Equipment
Depreciation is calculated using the straight-line method over the estimated useful lives of the assets.
(e) Inventories
Inventories are stated at the lower of cost or market. Cost is determined principally on the average cost method.
(f) Hedging Activities
The Company uses derivative commodity instruments to manage commodity price risks associated with future natural gas and crude oil production but does not use them for speculative purposes. The Company's commodity price hedging program utilizes swap contracts and collars. To qualify as a hedge, these contracts must correlate to anticipated future production such that the Company's exposure to the effects of commodity price changes is reduced. The gains and losses related to these hedging transactions are recognized as adjustments to the revenue recorded for the related production. The Company uses the accrual method of accounting for derivative commodity instruments. At inception, any contract premiums paid are recorded as prepaid expenses and, upon settlement of the hedged production month, are included with the gains and losses on the contracts in oil and gas revenues.
(g) Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(h) Reclassifications
Certain amounts in prior years' financial statements have been reclassified to conform to the 1997 financial statement presentation.
2. BANK CREDIT FACILITY AND SENIOR SUBORDINATED NOTES
In April 1996, the Company entered into a $75 million revolving credit facility (the facility) with a syndicate of banks. The facility is a two-year revolving credit facility followed by a two-year term loan with equal quarterly amortization payments. The facility matures in the year 2001 and is secured by the Company's Gulf of Mexico producing properties. Outstanding borrowings accrue interest at LIBOR plus a margin of 1.25% to 1.50% per annum, depending on the balance drawn. The Company is obligated to pay a fee of .30% to .35% per annum of the unused portion of the borrowing base.
At December 31, 1996, borrowings outstanding totaled $37 million at a weighted average annual interest rate of 7.155% and letters of credit outstanding totaled $12.21 million. At December 31, 1996, the fair value of the facility's outstanding borrowings approximated the carrying value. At December 31, 1997, the borrowing base of the bank credit facility was $60 million with no borrowings outstanding. Letters of credit outstanding totaled $9.96 million. The facility is subject to certain restrictive covenants.
In June 1997, the Company issued $100 million 9 1/2% Senior Subordinated Notes due in 2007. The notes were issued at a discount with an annual yield to maturity of 9.56%. A portion of the proceeds was used to pay the outstanding balance on the bank credit facility. At December 31, 1997, the fair value of the notes was $102,625,000 based on quoted market prices. These notes are subject to certain restrictive covenants.
3. SUBORDINATED SHAREHOLDER LOAN
Petsec (U.S.A.) Inc. had advances outstanding to the Company of $58.0 million and $37.3 million at December 31, 1996 and 1997, respectively. A summary of activity is as follows (in thousands):
Beginning Ending Balance Balance Additions Reductions
1995 11,905 18,500 (4,848) 25,038
1996 25,038 36,000 (3,084) 57,954
1997 57,954 1,500 (22,156) 37,298
The average balance outstanding for the years ended 1995, 1996 and 1997 was $13.7 million, $33.6 million, and $47.0 million, respectively.
Prior to June 1, 1997, the advances were without interest charges or fixed repayment terms. Effective June 1, 1997, Petsec (U.S.A.) Inc. began charging the Company interest on the subordinated shareholder loan. At December 31, 1997, the rates were 7.18% for U.S. dollar loans and 6.83% for Australian dollar loans. The Company is unable to determine the fair value of these loans because they are with a related party. In addition, effective June 1, 1997, $20 million of the outstanding subordinated shareholder loan was recapitalized as equity. Petsec (U.S.A.) Inc. has confirmed that no repayments will be required prior to December 31, 2007.
4. SIGNIFICANT CUSTOMERS
Customers which account for 10% or more of revenue for the years ended December 31, 1995, 1996 and 1997 follow:
1995 1996 1997 ---- ---- ----
Vision Resources, Inc. 55% 60% 46% Aquila Energy Marketing Corporation 30% 12% * Duke Energy Trading & Marketing, L.L.C., formerly Pan Energy Trading & Marketing Services, L.L.C. 13% 19% 22% P G & E Energy Trading Corporation - - 16% Natural Gas Clearinghouse * * 12%
* less than 10%
Based upon the current demand for oil and gas, the Company does not believe the loss of any current purchasers would have a material adverse effect on the Company. The Company continually evaluates the financial strength of its customers but does not require collateral to support trade receivables.
5. STOCK COMPENSATION EXPENSE
The Parent Company has an Employee Option Plan and issues options to employees and certain consultants of the Company to purchase stock in the Parent Company. The Parent Company's equity securities are traded on both the Australian Stock Exchange and The Nasdaq Stock Market SM.
The Company is allocated stock compensation expense in respect to the options in the Parent Company which are granted to the Company's employees and certain consultants. Prior to 1996, the Parent Company accounted for its expense related to the stock option plan in accordance with the provisions of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. In 1996, the Parent Company adopted Statement of Financial Accounting Standards No. 123 (Statement 123), Accounting for Stock-Based Compensation, under which it recognizes as expense over the vesting period the fair value of all stock-based awards on the date of grant. The amount is recorded as an increase to additional paid-in-capital. The fair value was determined using the Black-Scholes valuation method. The calculation takes into account the exercise price, expected life, current price of underlying stock, expected volatility of the underlying stock, expected dividend yield and the risk-free interest rate. The expected life, volatility, dividend yield and risk-free interest rates used in determining the fair value of options granted in 1996 were 2.1 to 3.5 years (weighted average 3.0 years); 30%; 0; and 7.1% to 8.4% per annum (weighted average 8% per annum), respectively, and 1.5 to 2.5 years (weighted average 2.1 years); 30%; 0; and 5.8% to 6.5% per annum (weighted average 6.1% per annum), respectively, in 1997.
6. INCOME TAXES
Although the Company is included in the consolidated federal and state income tax returns of Petsec (U.S.A.) Inc., the income tax provision has been prepared as if the Company were a separate taxpayer. Income tax expense attributable to income from continuing operations was $3.5 million, $6.3 million and $6.6 million for the years ended December 31, 1995, 1996 and 1997
respectively, and differed from the amounts computed by applying the U.S. federal income tax rate of 34% to income before income taxes as a result of the following:
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 1996 and 1997 are presented below.
At December 31, 1997, the Company has net operating loss carryforwards for federal income tax purposes of $46.7 million which are available to offset future federal taxable income, if any, through 2012. Although realization is not assured, management believes that it is more likely than not that all of the deferred tax assets will be realized.
7. RELATED PARTY TRANSACTIONS
The Parent Company has advanced funds to Petsec Energy Inc. through its wholly-owned subsidiaries, Petsec America Pty. Limited and Petsec (U.S.A.) Inc. (Note 3). The funds were used to finance operations.
For the years ended December 31, 1995, 1996 and 1997, Petsec Energy Inc. paid an amount of $630,000, $1.0 million and $540,000 to the Parent Company principally for reimbursement of direct expenses incurred in connection with the Company's operations.
8. COMMITMENTS AND CONTINGENCIES
Future minimum lease commitments at December 31, 1997, applicable to noncancelable operating leases with terms of one year or more are summarized as follows (in thousands):
Year 1998 $ 225 1999 208 2000 69 ----- $ 502 ===== Rent expense for the years ended December 31, 1995, 1996 and 1997 was $239,000, $281,000 and $264,000, respectively.
9. ADDITIONAL PAID-IN-CAPITAL
The following is a reconciliation of additional paid-in-capital for 1997:
Balance at December 31, 1996 $ 482
Recapitalization of loan 19,594
Stock Options 905 -------- Balance at December 31, 1997 $ 20,981 ========
10. HEDGING ACTIVITIES
Energy Swaps:
The Company enters into forward swap contracts with major financial institutions to reduce the price volatility on the sale of oil and gas production. In swap agreements, the Company receives the difference between a fixed price per unit of production and a floating price issued by a third party. If the floating price is higher than the fixed price, the Company pays the difference. At December 31, 1997, the Company had contracts maturing monthly through May 2000 on the net sale of 1.6 million barrels of oil at an average price of $20.02 per barrel and on the net sale of 19.4 million mmbtu of gas at an average price of $2.155 per mmbtu. The effect to the Company to terminate these contracts at December 31, 1997 is estimated to be a gain of $2.5 million for oil and a cost of $1.6 million for gas.
For the years ended December 31, 1995, 1996 and 1997, hedging activities increased revenues by $0.8 million and reduced revenues by $8.4 million and $4.4 million, respectively.
Collars:
The Company enters into collar agreements with third parties. A collar agreement is similar to a swap agreement except that the Company receives the difference between the floor price and the floating price if the floating price is below the floor. The Company pays the difference between the ceiling price and the floating price if the floating price is above the ceiling. At December 31, 1997, the Company had 3,480,000 mmbtu of gas hedged through December 1998 in costless collars with an average floor price of $2.27 per mmbtu and an average ceiling price of $3.69 per mmbtu. The effect to the Company to terminate these contracts at December 31, 1997 is estimated to be a gain of $0.4 million.
11. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest was $2.3 million, $3.4 million and $6.8 million for the years ended December 31, 1995, 1996 and 1997, respectively. The Company has not paid any cash for income taxes in these years.
12. LITIGATION
The Company is involved in certain lawsuits arising in the ordinary course of business. While the outcome of any of these lawsuits cannot be predicted with certainty, management expects these matters to have no material adverse effect on the financial position, results of operations or liquidity of the Company.
13. SUPPLEMENTARY OIL AND GAS DISCLOSURES -- UNAUDITED
Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Prior to December 31, 1996 the Company had a June 30 fiscal year end. As such, reserve data for December 31 was unavailable prior to 1995.
Estimates of proved and proved developed reserves at June 30, 1994 and 1995 and December 31, 1995, 1996 and 1997 were based on studies performed by Ryder Scott Company.
No major discovery or other favorable or adverse event subsequent to December 31, 1997 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
ESTIMATED NET QUANTITIES OF OIL AND GAS RESERVES
The following table sets forth the Company's net proved reserves, including the changes therein, and proved developed reserves (all within the United States) as estimated by Ryder Scott Company:
Capitalized costs for oil and gas producing activities consist of the following:
Costs incurred for oil and gas property acquisition, exploration and development activities are as follows:
Years Ended December 31, 1995 1996 1997 (in thousands)
Lease acquisition $ 2,930 $ 6,699 $ 8,437 Exploration 34,786 71,490 115,523 Development 12,925 14,187 31,327 ------- ------- ------- Total costs incurred $50,641 $92,376 $155,287 ======= ======= ========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS REVENUES
The following information has been developed utilizing procedures prescribed by Statement of Financial Accounting Standards No. 69 "Disclosures about Oil and Gas Producing Activities" (SFAS No. 69) and based on natural gas and crude oil reserve and production volumes estimated by Ryder Scott Company. It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying period end oil and gas prices adjusted for fixed and determinable escalations including hedged prices to the estimated future production of period-end proved reserves. As of December 31, 1997, approximately 19.4 million mmbtu of the Company's future gas production and 1.6 million barrels of oil were subject to such positions. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying period-end statutory tax rates to aggregate future pretax net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate is required by SFAS No. 69.
Management does not rely solely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and gas reserves is as follows:
The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1997 was based on average natural gas prices of approximately $2.39 per mcf and on average liquids of approximately $17.00 per barrel. Had March 1998 prices been used, the Company's standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 1997 would have been reduced.
2. FINANCIAL STATEMENTS SCHEDULES
None
3. EXHIBITS
Exhibit No. Exhibit ----------- -------
4.1 Articles of Incorporation of the Company (filed with Registration Statement on Form S-4 (No. 333-31625) and included herein by reference)
4.2 By-Laws of the Company (filed with Registration Statement on Form S-4 (File No. 333-31625) and included herein by reference)
4.3 Indenture dated as of June 13, 1997 among the Company, as issuer, and the Bank of New York, as trustee (filed with Registration Statement on Form S-4. (File No 333-31625) and is included herein by reference)
4.4 Registration Rights Agreement dated June 13, 1997 by and among the Company and Merrill Lynch & Co., Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Donaldson, Lufkin & Jenrette Securities Corporation and Salomon Brothers Inc. (filed with Registration Statement on Form S-4 (File No. 333-31625) and included herein by reference)
10.1 Credit Agreement by and among Petsec Energy Inc. and Chase Manhattan Bank and certain financial institutions named therein as Lenders (filed with Registration Statement on Form S-4 filed (File No. 333-31625) and included herein by reference)
23.1* Consent of Ryder Scott Company
24.1* Power of Attorney (included on the signature pages of this Annual Report)
27* Financial Data Schedule
- ----------------------- * Filed herewith
4. REPORTS ON FORM 8-K
No Reports were filed.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, this 31st day of March 1998.
Petsec Energy Inc.
By: /s/Ross A. Keogh ------------------------------- Name: Ross A. Keogh Title:Director and Treasurer
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Ross A. Keogh, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign on his behalf individually and in each capacity stated below any and all amendments to this annual report, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitutes, may lawfully do or cause to be done by virtue hereof.
Name Title Date ---- ----- ---- /s/Terrence N. Fern Chairman and Chief Executive March 31, 1998 - ----------------------- Officer (Principal Executive Terrence N. Fern Officer)
/s/Anthony J. Walton March 31, 1998 - ----------------------- Anthony J. Walton Director
/s/James S. Slatten III March 31, 1998 - ----------------------- James S. Slatten III Director and Secretary
EXHIBIT INDEX
Exhibit No. Exhibit ----------- -------
4.1 Articles of Incorporation of the Company (filed with Registration Statement on Form S-4 (No. 333-31625) and included herein by reference)
4.2 By-Laws of the Company (filed with Registration Statement on Form S-4 (File No. 333-31625) and included herein by reference)
4.3 Indenture dated as of June 13, 1997 among the Company, as issuer, and the Bank of New York, as trustee (filed with Registration Statement on Form S-4. (File No 333-31625) and is included herein by reference)
4.4 Registration Rights Agreement dated June 13, 1997 by and among the Company and Merrill Lynch & Co., Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Donaldson, Lufkin & Jenrette Securities Corporation and Salomon Brothers Inc. (filed with Registration Statement on Form S-4 (File No. 333-31625) and included herein by reference)
10.1 Credit Agreement by and among Petsec Energy Inc. and Chase Manhattan Bank and certain financial institutions named therein as Lenders (filed with Registration Statement on Form S-4 filed (File No. 333-31625) and included herein by reference)
23.1* Consent of Ryder Scott Company
24.1* Power of Attorney (included on the signature pages of this Annual Report)
27* Financial Data Schedule
- ----------------------- * Filed herewith