ITEM 1. BUSINESS
This document includes "forward looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"). All statements other than statements of historical facts included in this document, including without limitation, statements under "Discussion and Analysis of Financial Condition and Results of Operations" regarding the financial position and estimated quantities and net present values of reserves of the Torch Energy Royalty Trust ("Trust") are forward-looking statements. Torch Energy Advisors Incorporated ("Torch") and the Trust can give no assurances that the assumptions upon which these statements are based will prove to be correct. Important factors that could cause actual results to differ materially from Torch's expectations ("Cautionary Statements") are disclosed under "Risk Factors" elsewhere in this document. All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified by the Cautionary Statements.
GENERAL
The Trust was formed effective October 1, 1993 under the Delaware Business Trust Act pursuant to a trust agreement ("Trust Agreement") among Wilmington Trust Company, as trustee ("Trustee"), Torch Royalty Company ("TRC") and Velasco Gas Company Ltd. ("Velasco") as owners of certain oil and gas properties ("Underlying Properties") and Torch as grantor. TRC and Velasco created net profits interests ("Net Profits Interests") and conveyed such interests to Torch. Torch conveyed the Net Profits Interests to the Trust in exchange for an aggregate of 8,600,000 units of beneficial interest ("Units"). Such Units were sold to the public through various underwriters in November 1993. Pursuant to an administrative services agreement ("Administrative Services Agreement"), Torch provides accounting, bookkeeping, informational and other services related to the Net Profits Interest.
The Trust will not terminate prior to January 1, 2003, except upon the affirmative vote of the holders of not less than 80% of the outstanding Units. Thereafter, the Trust will terminate upon the first to occur of (i) an affirmative vote of the holders of not less than 66-2/3% of the outstanding Units to liquidate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust from the Net Profits Interests to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive quarters; (iii) March 1 of any year if it is determined based on a reserve report as of December 31 of the prior year that the present value of estimated pre-tax future net cash flows, discounted at 10%, of proved reserves attributable to the Net Profits Interests is equal to or less than $25 million; or (iv) December 31, 2012. After termination of the Trust, the remaining assets of the Trust will be sold and the proceeds therefrom (after expenses) will be distributed to the unitholders ("Unitholders"). The sole purpose of the Trust is to hold the Net Profits Interests, to receive payments from TRC and Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity.
TRC and Velasco, as owners of the Underlying Properties subject to and burdened by the Net Profits Interests, contracted to sell the oil and gas production from such properties to Torch Energy Marketing Inc. ("TEMI"), a subsidiary of Torch, under a purchase contract ("Purchase Contract"). TRC and Velasco receive payments reflecting the proceeds of oil and gas sold and aggregate these payments, deduct applicable costs and make payments to the Trustee each quarter for the amounts due to the Trust. Unitholders receive quarterly cash distributions relating to oil and gas produced and sold from the Underlying Properties. Because no additional properties will be contributed to the Trust, the assets of the Trust deplete over time and a portion of each cash distribution made by the Trust is analogous to a return of capital.
TORCH ENERGY ROYALTY TRUST
The Underlying Properties constitute working interests in the Chalkley Field in Louisiana ("Chalkley Field"), the Robinson's Bend Field in the Black Warrior Basin in Alabama ("Robinson's Bend Field"), fields that produce from the Cotton Valley formations in Texas ("Cotton Valley Fields") and fields that produce from the Austin Chalk formation in Texas ("Austin Chalk Fields"). The Underlying Properties represent interests in all productive formations from 100 feet below the deepest productive formation in each field to the surface when the Trust was formed. The Trust therefore has no interest in deeper productive formations. Other clients of Torch also own interests in oil and gas properties located in the same geographic areas as the Underlying Properties and own interests in certain of the same wells, which interests are not burdened by the Net Profits Interests.
Sales of coal seam and tight sands gas attributable to the Net Profits Interests prior to January 1, 2003 result in Unitholders receiving quarterly allocations of tax credits under Section 29 of the Internal Revenue Code of 1986 ("Section 29 Credit"). In 1998, 1997, and 1996, the Section 29 Credit available for production from qualifying coal seam properties was approximately $1.06, $1.05 and $1.03, respectively, for each MMBtu of gas produced and sold. This rate is adjusted annually for inflation. The Section 29 Credit available for production from qualifying tight sands properties is approximately $0.52 for each MMBtu of gas produced and sold and such amount is not adjusted for inflation.
Separate conveyances ("Conveyances") were used to transfer the Net Profits Interests in each state. Net proceeds ("Net Proceeds"), generally defined as gross revenues received from the sale of production attributable to the Underlying Properties during any period less property, production, severance and similar taxes, and development, operating, and certain other costs (excluding operating and development costs from the Robinson's Bend Field until January 1, 2003), are calculated separately for each Conveyance. If, during any period, costs and expenses deducted in calculating Net Proceeds exceed gross proceeds under a Conveyance, neither the Trust nor Unitholders are liable to pay such excess directly, but the Trust will receive no payments for distribution to Unitholders with respect to such Conveyance until future gross proceeds exceed future costs and expenses plus the cumulative excess of such costs and expenses not previously recouped by TRC and Velasco plus interest thereon. Because development and operating costs generally are deducted in computing Net Proceeds, such costs will affect the amounts paid to the Trust from the Net Profits Interests. The complete definitions of Net Proceeds are set forth in the Conveyances.
MARKETING ARRANGEMENTS
In connection with the formation of the Trust, TRC, Velasco and TEMI entered into the Purchase Contract which expires upon the termination of the Trust. Under the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an index price for oil and gas ("Index Price"), less certain gathering, treating and transportation charges, which are calculated monthly. The Index Price equals 97% of the average spot market prices of oil and gas ("Average Market Prices") at the four locations where TEMI sells production, which, prior to September 1, 2000, is adjusted to reflect the terms of a hedge contract ("Hedge Contract") to which TEMI is a party. Under the Hedge Contract, TEMI receives prices specified in the Hedge Contract ("Specified Prices") for quantities of oil and gas specified therein ("Specified Quantities"). In calculating the Index Price for gas (which represents approximately 97% of the estimated reserves as of January 1, 1999, on a net equivalent Mcf of gas ("Mcfe") basis), the Specified Prices received weightings ranging from approximately 40% to 70% pertaining to production prior to August 31, 1997. Thereafter, the Specified Prices receive a weighting of approximately 10% and less. The Average Market Prices receive the balance of the weighting. The Specified Prices for gas increase each year from $1.83 per MMBtu in 1996 to $1.89 per MMBtu in 2000 and are adjusted to reflect the difference between the settlement prices for oil and gas in the futures markets and the Average Market Prices.
TORCH ENERGY ROYALTY TRUST
The Purchase Contract also provides that the minimum price paid by TEMI for gas production is $1.70 per MMBtu ("Minimum Price"). When TEMI pays a purchase price based on the Minimum Price it receives price credits ("Price Credits"), equal to the difference between the Index Price and the Minimum Price, that it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. In addition, if the Index Price for gas exceeds $2.10 per MMBtu, TEMI is entitled to deduct 50% of such excess ("Price Differential") in determining the purchase price. Beginning January 1, 2001, TEMI has an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be entitled to deduct the Price Differential in calculating the purchase price and will forfeit all accrued Price Credits. TEMI has purchased contracts granting TEMI the right to sell estimated gas production in excess of the Specified Quantities at a price intended to limit TEMI's losses in the event the Index Price falls below the Minimum Price.
Gas production is purchased at the wellhead and, therefore, Net Proceeds do not include any amounts received in connection with extracting natural gas liquids from such production at gas processing or treating facilities.
GATHERING, TREATING AND TRANSPORTATION ARRANGEMENTS
The Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation fees in calculating the purchase price for gas in the Robinson's Bend, Austin Chalk and Cotton Valley Fields. The amounts that may be deducted in calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and transport gas. For the Robinson's Bend Field, TEMI is entitled to deduct a gathering, treating and transportation fee of $0.260 per MMBtu adjusted for inflation ($0.274 for 1998 and 1997, and $0.272 per MMBtu for 1996, plus fuel usage equal to 5% of revenues, payable to Bahia Gas Gathering, Ltd. ("Bahia"), an affiliate of Torch, pursuant to a gas gathering agreement. Additionally, a fee of $.05 per MMBtu, representing a gathering fee payable to a non-affiliate of Torch, is deducted in calculating the purchase price for production from 68 of the 394 wells in the Robinson's Bend Field. TEMI deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase price for production from the Austin Chalk Fields as a fee to gather, treat and transport gas production. TEMI deducts from the purchase price for gas for production attributable to certain wells in the Cotton Valley Fields a transportation fee of $0.045 per MMBtu. During the years ended December 31, 1998, 1997 and 1996, gathering, treating and transportation fees charged to the Trust by TEMI, attributable to production during the twelve months ended September 30, 1998, 1997 and 1996 in the Robinson's Bend, Austin Chalk and Cotton Valley Fields, totaled $1,650,000, $1,965,000 and $2,137,000, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.
NET PROFITS INTERESTS
The Net Profits Interests entitle the Trust to receive 95% of the Net Proceeds attributable to oil and gas produced and sold from wells (other than infill wells) on the Underlying Properties. In calculating Net Proceeds from the Robinson's Bend Field, operating and development costs incurred prior to January 1, 2003 are not deducted. In addition, the amounts paid to the Trust from the Robinson's Bend Field during any calendar quarter are subject to a volume limitation ("Volume Limitation") equal to the gross proceeds from the sale of 912.5 MMcf of gas, less property, production, severance and related taxes. The Robinson's Bend Field production attributable to the Trust did not meet the Volume Limitation during the three years ended December 31, 1998 and is not expected to do so in the future.
The Net Profits Interests also entitle the Trust to 20% of the Net Proceeds (defined below) of wells drilled on the Underlying Properties since the Trust's establishment into formations in which the Trust has an
TORCH ENERGY ROYALTY TRUST
interest, other than wells drilled to replace damaged or destroyed wells ("Infill Wells"). Infill Well Net Proceeds represent the aggregate gross revenues received from Infill Wells less the aggregate amount of the following Infill Well costs: i) property, production, severance and similar taxes; ii) development costs; iii) operating costs; and iv) interest on the recovered portion, if any, of the foregoing costs computed at a rate of interest announced publicly by Citibank, N.A. in New York as its base rate.
RISK FACTORS
VOLATILITY OF OIL AND GAS PRICES
The Trust's cash distributions, operating results and the value of the Net Profits Interest are substantially dependent on prices of gas and, to a lesser extent, oil. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond control of Torch. These factors include weather conditions in the United States, the condition of the United States economy, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternate fuel sources. Any substantial and extended decline in the price of oil and gas would have an adverse effect on the Trust's revenues, cash distributions and value of the Net Profits Interests.
UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET CASH FLOWS
Estimates of economically recoverable oil and gas reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are to some degree speculative and may vary considerably from actual results. Therefore, actual production, revenues, taxes and development and operation expenditures may not occur as estimated. Future results of the Trust will depend upon the ability of the owners of the Underlying Properties to develop, produce and sell their oil and natural gas reserves. The reserve data included herein are estimates only and are subject to many uncertainties. Actual quantities of oil and natural gas may differ considerably from the amounts set forth herein. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds the sum of the estimated undiscounted future cash flows attributable to the Trust's oil and gas reserves plus the estimated future tax credits under Section 29 of the Internal Revenue Code of 1986 ("Section 29 Credit") for Federal income tax purposes. The impairment loss is equal to the difference between the carrying value of the Net Profits Interest and the fair value of the Net Profits Interest. An impairment of $29.1 million in the carrying value of the Net Profits Interest was recorded during the fourth quarter of 1998. No impairment was recorded for 1997 or 1996.
OPERATING RISKS
Cash payments to the Trust are derived from the production and sale of oil and gas, which operations are subject to risk inherent in such activities, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. These risks could result in substantial losses which are deducted in calculating the Net Proceeds paid to the Trust due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations.
TORCH ENERGY ROYALTY TRUST
COMPETITION AND MARKETS
The Trust's distributions are dependent on gas production and prices and, to a lesser extent, oil production and prices from the Underlying Properties. The gas industry is highly competitive in all of its phases. In marketing production from the Underlying Properties, TEMI encounters competition from major gas companies, independent gas concerns, and individual producers and operators. Many of these competitors have greater financial and other resources than TEMI. Competition may also be presented by alternative fuel sources, including heating oil and other fossil fuels.
Crude oil and natural gas supplies are currently abundant relative to demand in the worldwide markets for those commodities. Market prices are typically volatile as a result of uncertainties caused by world events. Demand for natural gas production has historically been seasonal in nature, and prices for gas fluctuate accordingly. Such price fluctuations will directly impact Trust distributions, estimated reserve attributable to the Trust and estimated future net revenues from Trust reserves.
REGULATION OF NATURAL GAS
The production, transportation and sale of natural gas from the Underlying Properties are subject to Federal and state governmental regulation, including regulation of tariffs charged by pipelines, taxes, the prevention of waste, the conservation of gas, pollution controls and various other matters. The United States has governmental power to impose pollution control measures.
Federal Regulation
The Underlying Properties will be subject to the jurisdiction of FERC with respect to various aspects of gas operations including the marketing and production of gas. The Natural Gas Act and the Natural Gas Policy Act (collectively, the "Acts") mandate Federal regulation of interstate transportation of gas. The Natural Gas Wellhead Decontrol Act of 1989 terminated wellhead price controls on all domestic gas on January 1, 1993. Numerous questions have been raised concerning the interpretation and implementation of several significant provisions of the Acts and of the regulations and policies promulgated by FERC thereunder. A number of lawsuits and administrative proceedings have been instituted which challenge the validity of regulations implementing the Acts. In addition, FERC currently has under consideration various policies and proposals that may affect the marketing of gas under new and existing contracts. Accordingly, Torch is unable to predict the impact of any such government regulation.
In the past, Congress has been very active in the area of gas regulation. Recently enacted legislation repeals incremental pricing requirements and gas use restraints previously applicable. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Underlying Properties and the Trust.
State Regulation
Many state jurisdictions have at times imposed limitations on the production of gas by restricting the rate of flow for gas wells below their actual capacity to produce and by imposing acreage limitations for the drilling of a well. States may also impose additional regulations of these matters. Most states regulate the production of gas, including requirements for obtaining drilling permits, the method of developing new fields, provisions for the unitization or pooling of gas properties, the spacing, operation, plugging and abandonment of wells and the prevention of waste of gas resources. The rate of production may be regulated and the maximum daily production allowable from gas wells may be established on a market demand or conservation basis or both.
TORCH ENERGY ROYALTY TRUST
ENVIRONMENTAL REGULATION
Activities on the Underlying Properties are subject to existing Federal, state and local laws, rules and regulations which govern health, safety, environmental quality and pollution control. It is anticipated that, absent the occurrence of an unanticipated event, compliance with existing Federal, state and local laws, rules and regulations regulating health, safety, the release of materials into the environment or otherwise relating to the protection of the environment will not have a material adverse effect upon the Trust or Unitholders. Torch has informed the Trust that it cannot predict what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from operations on the Underlying Properties could have on the Trust or Unitholders. However, pursuant to the terms of the Conveyances, any costs or expenses incurred by TRC or Velasco in connection with environmental liabilities, to the extent arising out of or relating to activities occurring on, or in connection with, or conditions existing on or under, the Underlying Properties before October 1, 1993, will be borne by TRC or Velasco and not the Trust and will not be deducted in calculating Net Proceeds and will, therefore, not reduce amounts payable to the Trust.
ITEM 2.
ITEM 2. PROPERTIES
DESCRIPTION OF THE UNDERLYING PROPERTIES
Chalkley Field. The Underlying Properties in the Chalkley Field, located in Cameron Parish, Louisiana, include an average 16.2% working interest (12.1% net revenue interest) in five unitized wells producing from the Miogyp "B" reservoir and one well producing from the Lower Miogyp reservoir. The wells produce from a depth in excess of 14,000 feet. The working interest in the well producing in the Lower Miogyp reservoir is 64.4% (48.3% net revenue interest). A subsidiary of Exxon Corporation operates the five wells in the Miogyp "B" reservoir, and a subsidiary of Torch operates the well producing from the Lower Miogyp formation.
Robinson's Bend Field. The Underlying Properties include an average 42.7% working interest (31.9% net revenue interest) in 394 wells in the Robinson's Bend Field in the Black Warrior Basin of Alabama. Sales of production of coal seam gas from the Robinson's Bend Field prior to January 1, 2003 entitle Unitholders to Section 29 Credits, provided certain requirements are met. The Section 29 Credit for qualifying coal seam gas production was approximately $1.06, $1.05 and $1.03 per MMBtu in 1998, 1997 and 1996, respectively. This rate is adjusted annually for inflation. All of the wells in the Robinson's Bend Field are operated by an affiliate of Torch.
The amounts paid to the Trust from the Robinson's Bend Field in any calendar quarter are subject to a Volume Limitation equal to the gross proceeds from the sale of 912.5 MMcf, less property, production, severance and similar taxes, and development, operating, and certain other costs (excluding operating and development costs until January 1, 2003). Gross production during 1998, 1997 and 1996 attributable to distributions from the Underlying Properties in the Robinson's Bend Field averaged 719 MMcf, 787 MMcf and 853 MMcf per quarter, respectively, and was therefore 25%, 18% and 11%, respectively, less than the Volume Limitation for the year.
In calculating amounts paid to the Trust, lease operating expenses in the Robinson's Bend field are not deducted until after 2002. When these amounts are deducted, the amounts paid to the Trust attributable to the Robinson's Bend field will be reduced substantially. If average prices following 2002 are not substantially greater than gas prices in December 1998, the Trust's current reserve reports indicate that the Trust will not receive any payments attributable to the Robinson's Bend field.
TORCH ENERGY ROYALTY TRUST
Cotton Valley Fields. The Underlying Properties include an average 52.91% working interest (40.17% net revenue interest) in 45 wells in four fields that produce from the Upper and Lower Cotton Valley formations in Texas. A substantial portion of the gas produced and sold from the Cotton Valley Fields prior to January 1, 2003 will qualify for the Section 29 Tax Credits for productions of tight sands gas. The Section 29 Credit for qualifying tight sands gas production is approximately $0.52 per MMBtu and is not adjusted for inflation. All of the wells in the Cotton Valley Fields are operated by a subsidiary of Torch.
Austin Chalk Fields. The Underlying Properties include an average of 18.16% working interest (14.25% net revenue interest) in 90 wells in the Austin Chalk Fields of Central Texas. Production from these fields is derived primarily from the highly fractured Austin Chalk formation using horizontal drilling techniques. A substantial portion of the gas produced and sold from these fields prior to January 1, 2003 will qualify for the Section 29 Credits for tight sands gas. A subsidiary of Torch operates eight wells in the Austin Chalk Fields. A majority of the wells in the Austin Chalk Fields are operated by Union Pacific Resources Corporation.
WELL COUNT AND ACREAGE SUMMARY
The following table shows, as of December 31, 1998, the gross and net interest in oil and gas wells for the Underlying Properties:
The following table shows the gross and net acreage for the Underlying Properties as of December 31, 1998. A gross acre in the following table refers to the number of acres in which a working interest is owned directly by the Trust. The number of net acres is the sum of the fractional ownership of working interests owned directly by the Trust in the gross acres expressed as a whole number and percentages thereof. A net acre is deemed to exist when the sum of fractional ownership of working interests in gross acres equals one.
Acreage ------------------------ Gross Net -------- -------- Chalkley Field...................... 2,152 425 Robinson's Bend Field............... 33,404 14,288 Cotton Valley Fields................ 6,650 4,162 Austin Chalk Fields................. 34,642 6,414 -------- -------- Total............................. 76,848 25,289 ======== ========
DRILLING ACTIVITY
The following table sets forth the results of drilling activity for the Underlying Properties during the three years ended December 31, 1998. Gross wells, as it applies to wells in the following table, refers to the number of wells in which a working interest is owned directly by TRC and Velasco ("Gross Well"). A net well ("Net Well") represents the sum of the fractional ownership working interests in the Gross Wells expressed as whole numbers and percentages thereof.
TORCH ENERGY ROYALTY TRUST
All of the wells shown below represent Infill Wells drilled on the Underlying Properties. The Net Profits Interest entitle the Trust to 20% of an infill well's cash flows after gross proceeds have exceeded costs and expenses ("Payout"). As Payout has not occurred on any of these wells, distributions to Unitholders have not been impacted by the Infill Wells as of December 31, 1998.
Development Wells Gross Net --------------------------- -------------------------- Dry Dry Productive Holes Total Productive Holes Total ---------- ----- ----- ---------- ----- ----- 1996 0 0 0 0 0 0 1997 6 0 6 2.8 0 2.8 1998 0 0 0 0 0 0
There was no other drilling activity on the Underlying Properties during the three years ended December 31, 1998.
OIL AND GAS SALES PRICES AND PRODUCTION COSTS
The following table sets forth, for the Underlying Properties, the net production volumes of gas and oil, the weighted average lifting cost and taxes per Mcfe deducted in calculating net profits income and the weighted average sales price per Mcf of gas and Bbl of oil for production attributable to 1998, 1997 and 1996 cash distributions received by Unitholders (derived from production during the twelve months ended September 30, 1998, 1997 and 1996, respectively).
(a) No operating costs will be deducted from the Net Profits Interest in the Robinson's Bend Field until January 1, 2003. Average lifting costs per Mcfe were $2.45, $2.27 and $2.35, respectively, during 1998, 1997 and 1996, in the Robinson's Bend Field.
(b) Average sales prices are reflective of purchase prices paid by TEMI, pursuant to the Purchase Contract, less certain gathering, treating and transportation charges.
TORCH ENERGY ROYALTY TRUST
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
There are no material pending legal proceedings to which the Trust is a party.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF UNITHOLDERS
No matter was submitted to the Unitholders for a vote in 1998.
TORCH ENERGY ROYALTY TRUST
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S UNITS AND RELATED UNITHOLDER MATTERS
The Units are listed and traded on the New York Stock Exchange under the symbol "TRU." At March 26, 1999, there were 8,600,000 Units outstanding and approximately 694 Unitholders of record. The following table sets forth, for the periods indicated, the high and low sales prices per Unit on the New York Stock Exchange ("NYSE") and the amount of quarterly cash distributions per Unit made by the Trust:
On March 26, 1999, the high sales price per unit on the NYSE was $4.813 and the low sales price on the NYSE was $4.689.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA (In thousands, except per Unit amounts)
Distributable income of the Trust consists of the excess of net profits income plus interest income less general and administrative expenses of the Trust. The Trust recognizes net profits income during the period in which amounts are received by the Trust.
ITEM 7.
ITEM 7. DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
YEAR 2000 ISSUES
The Year 2000 problem ("Y2k") refers to the inability of computer and other information technology systems to properly process date and time information. The problem was caused, in part, by the outdated programming practice of using two digits rather than four to represent the year in a date. The consequence of the Y2k problem is that information technology and embedded processing systems are at risk of malfunction, particularly during the transition between 1999 to 2000.
TORCH ENERGY ROYALTY TRUST
The effects of the Y2k problem are exacerbated by the interdependence of computer and telecommunication systems throughout the world. This interdependence affects the Trust, the Trust's administrative services provider, Torch, and their vendors, customers, business partners, as well as government agencies.
The risks of Y2k fall into three general areas: 1) Corporate Systems, 2) Field Systems and 3) Third Party Exposure. Torch has formed a Y2k Team comprised of representatives from senior management, exploration, exploitation, accounting, legal and internal audit. The costs of these assessments will not impact the Trust's distributions as such costs are borne by Torch pursuant to the Administrative Services Agreement between Torch and the Trust. Torch intends to address each of these areas through a readiness process as described below:
a) Planning and Awareness b) Inventory and Assessment c) Identify Potential Problems and their Business Impact d) Identify/Approve Solutions e) Test and Implement Solutions f) Contingency Planning
CORPORATE SYSTEMS
1. Planning and Awareness. All Torch employees have attended Y2k informational programs including a general discussion of what Y2k is and how it could affect the business. Employees of all levels of the organization have been asked to participate in the identification of potential Y2k risks including routine Excel and Word documents. Awareness of the issue is extremely high. Overall planning of the Y2k function has been delegated to the Y2k Team mentioned above.
2. Inventory and Assessment. The Company has completed an inventory of the traditional computing platforms including client/server systems, LAN systems and PC systems, as well as an inventory of all systems software and operating systems for each computing system. In addition, third party service interfaces, banking/treasury interfaces and telecommunications have been cataloged.
Assessment of component compliance (compliant, non-compliant, expected date of compliance, etc.) has been completed and included research of product information on the Internet, contacting peer group companies and accessing information that peer group companies have already found.
3. Identification. The failure to identify and correct a material Y2k problem in the Corporate Systems could result in inaccurate or untimely financial information provided to the Trustee and Unitholders. At this time, Torch believes that any Y2k disruptions associated with its financial and administration systems will not have a material effect on the Trust.
4. Identify/Approve Solutions. Based upon the assessments of components' compliance, solutions are determined. These solutions include: 1) fix or replace the non-compliant component, 2) buy patches or replacement items, 3) develop workarounds, 4) identify alternate automated processes, 5) design manual procedures and 6) develop business continuity plans for specific items or systems.
5. Test and Implement Solution. Since April 1998 Torch has been working on an upgrade to its accounting software and is expected to achieve full Y2k compliance in the first half of 1999. In addition, all network and desktop applications used by Torch have been inventoried and are generally Y2k compliant.
TORCH ENERGY ROYALTY TRUST
6. Contingency Planning. Notwithstanding the foregoing, should there be significant unanticipated disruptions in Torch's financial and administrative systems, a number of accounting processes that are currently automated will need to be performed manually. Torch is currently considering its options with respect to contingency arrangement for temporary staffing to accommodate such situations.
FIELD SYSTEMS
1. Planning and Awareness. Employees at all levels of the organization have been asked to participate in the identification of potential Y2k risk impacting Torch's field systems, including management of field and facility assets.
2. Inventory and Assessment. All embedded chip technology used in the field operations including safety systems, measurement devices, overflow valves, SCADA systems and other field processes that are date-or-time sensitive were located. During the assessment stage a list of assets to be tested was assembled. Consideration was given to 1) issues of health and safety, 2) environmental concerns, 3) economic factors and 4) other business risks. Vendors and manufacturers have been contacted as well as product research through the Internet and the use of peer group company shared information. To date, the majority of embedded components researched have been deemed either date-insensitive or Y2k compliant. However, the complexity of embedded systems is such that a small minority of non-compliant components, even a single non-compliant component, can corrupt an entire system. The component level evaluation is substantially complete and a broader evaluation at the system level has commenced. Torch anticipates that the system level evaluation will be completed by the end of the second quarter 1999.
3. Identification. The failure to identify and correct a material Y2k problem could result in outcomes ranging from errors in data reporting to curtailments or shutdowns in production. Torch is actively engaged in a program to prioritize the remediation of embedded components and systems which are either known to be Y2k non-compliant or which have higher risk of Y2k failures, and to further prioritize remediation targets by the anticipated financial impact of any such failures on the Trust. To assist in this effort, Torch has retained consultants who are knowledgeable and experienced in the assessment of Y2k issues impacting field operations. Torch intends to give extremely high priority to the remediation of any situation that impacts employee health and safety or environmental security. At this time, Torch is unable to express any degree of confidence that there will not be material production disruptions associated with Y2k compliance. Depending on the magnitude of any such disruptions and the time required to correct them, such failures could materially and adversely impact distributions, depletion deductions and Section 29 credits available for allocation by the Trust to the Unitholders.
4. Identify/Approve Solutions. Based upon the assessment of field systems, regarding compliance or non-compliance, solutions are determined. These potential solutions include 1) fix or replace non-compliant items, 2) buy patches or replacement items, 3) develop workarounds, 4) identify alternative automated processes, 5) design manual procedures and 6) develop business continuity plans for specific items or systems.
5. Test and Implement Solutions. Once identified, assessed and prioritized, Torch intends to test, upgrade and certify embedded components and systems in field process control units deemed to pose the greatest risk of significant non-compliance. It is important to note that in some circumstances, the procedures used to test embedded components for Y2k compliance themselves pose a risk of damaging the component or corrupting the system. Accordingly, there may be situations in which a decision not to test may be deemed the most prudent.
TORCH ENERGY ROYALTY TRUST
6. Contingency Planning. Should material production disruptions occur as a result of Y2k failures in the field operations, the Trust's financial condition will be impacted. This contingency is being factored into capital budgeting and liquidity planning.
THIRD PARTY EXPOSURES
1. Planning and Awareness. Torch has been involved in informational programs with its employees who have significant interaction with outside vendors, customers and business partners which may have an impact on the Trust's financial condition. All levels of employees in the organization have participated in the identification of potential third party Y2k risk.
2. Inventory and Assessment. Surveys of general Y2k readiness have been sent to third parties such as vendors, customers and business partners which impact the Trust's financial condition. An assessment has been made regarding the impact associated with such third parties' Y2k compliance on the Trust.
3. Identification. Certain third parties' failure to identify Y2k problems can have significant adverse effects on the Trust. For example, an Underlying Property third party operator's failure to identify Y2k problems may result in adverse outcomes such as data reporting errors, curtailments and production shutdowns. Additionally, Y2k problems in connection with the possible interruption of TEMI's third party gathering, treating, processing or transportation arrangements relating to the Underlying Properties can affect TEMI's obligation under the Purchase Contract. Other significant concerns include the integrity of global telecommunication systems, the readiness of commercial banks to execute electronic fund transfers and the financial community's ability to maintain an orderly market of the Trust's Units. All such events could materially or entirely eliminate distributions, depletion deductions and Section 29 Credits available for allocation by the Trust to the Unitholders.
4. Identify/Approve Solutions. By prioritizing the various third party risks mentioned above, a list of critical third party vendors, customers and business partners has been determined. By cross-referencing the results of the aforementioned Y2k readiness survey with this list of critical third parties, solutions can be determined. Field visits, office visits and additional meetings to access the third party's Y2k compliance may be necessary.
5. Test and Implement Solutions. Where Torch perceives significant risk of Y2k non-compliance of a third party that may have a material impact on the financial condition of the Trust, joint testing may be undertaken during 1999. Joint testing would occur following upgrades and other remediation to hardware, software and communications links, as applicable, with the intent of determining that the remediation system being tested will perform as expected after December 31, 1999.
6. Contingency Planning. Should material production disruptions occur as a result of Y2k failures of third parties, the distributions, depletion deductions and Section 29 Credits available for allocation by the Trust to the Unitholders will be impacted. The Company and the Trust do not believe it is economically feasible to provide for this contingency.
TORCH ENERGY ROYALTY TRUST
RESULTS OF OPERATIONS
DISCUSSION OF YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Because a modified cash basis of accounting is utilized by the Trust, Net Proceeds to the Trust for the years ended December 31, 1998, 1997 and 1996 is derived from actual oil and gas production from October 1, 1997 through September 30, 1998, October 1, 1996 through September 30, 1997 and October 1, 1995 through September 30, 1996, respectively. The following tables set forth, for the Underlying Properties, oil and gas sales attributable to distributions received by Unitholders during the three years ended December 31, 1998.
Bbls of Oil ----------------------------------- 1998 1997 1996 ------- ------- -------- Chalkley Field................ 26,736 40,260 61,694 Robinson's Bend Field......... --- --- --- Cotton Valley Fields.......... 6,481 6,157 7,607 Austin Chalk Fields........... 41,174 60,236 79,289 ------- ------- -------- Total......................... 74,391 106,653 148,590 ======= ======== ========
Mcf of Gas ----------------------------------- 1998 1997 1996 ------- ------- -------- Chalkley Field................ 3,219,550 4,195,263 5,713,920 Robinson's Bend Field......... 2,879,422 3,148,834 3,415,346 Cotton Valley Fields.......... 1,469,645 1,385,461 1,734,783 Austin Chalk Fields........... 445,443 605,455 768,023 ---------- ---------- ---------- Total......................... 8,014,060 9,335,013 11,632,072 ========== ========== ==========
For the year ended December 31, 1998, net profits income was $13,615,000, as compared to $15,183,000 and $17,381,000 for the same periods in 1997 and 1996, respectively. Such decreases are primarily due to normal declines in oil and gas production attributable to the Underlying Properties, partially offset by higher average gas prices paid to the Trust during 1998 and 1997.
Gas production attributable to the distributions received by Unitholders during the year ended December 31, 1998 was 8,014,060 Mcf, as compared to gas production of 9,335,013 Mcf and 11,632,072 Mcf for the same periods in 1997 and 1996, respectively. Oil production attributable to the Underlying Properties for the year ended December 31, 1998 was 74,391 Bbls as compared to 106,653 Bbls and 148,590 Bbls for the same periods in 1997 and 1996, respectively.
As of December 31, 1998, six infill wells were drilled and commenced production. Infill well production totaled 1,700 bbls of oil and 344,458 Mcf of gas during the year ended December 31, 1998 and 2,075 bbls of oil and 274,577 Mcf of gas during the year ended December 31, 1997. Distributions received by Unitholders have not been impacted by these wells as gross proceeds have not exceeded costs and expenses for each of the infill wells.
The average price used to calculate Net Proceeds for gas during the year ended December 31, 1998 was $2.10 per MMBtu as compared to $1.91 per MMBtu and $1.70 per MMBtu for the years ended December 31, 1997 and 1996, respectively. The average price used to calculate Net Proceeds for oil during the years ended December 31, 1998, 1997 and 1996 was $12.71, $17.06 and $17.10 per Bbl, respectively. When TEMI pays a purchase price for gas based on the Minimum Price of $1.70 per MMBtu, TEMI
TORCH ENERGY ROYALTY TRUST
receives Price Credits which it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. As of December 31, 1998, TEMI's outstanding Price Credits will reduce future distributions by $97,000. All such Price Credits, computed on a monthly basis, are attributable to September 1998 production and may be entitled to be deducted by TEMI in calculating the purchase price in the future when the Index Price for gas exceeds the Minimum Price. Net Price Credits in the amount of $317,000 and $2,305,000 were deducted in calculating the purchase price related to distributions during 1997 and 1996, respectively.
Lease operating expenses and capital expenditures deducted in calculating distributions during the years ended December 31, 1998, 1997 and 1996 totaled $1,947,000, $1,898,000 and $2,081,000, respectively. In accordance with the Conveyance, no operating or development costs will be deducted in calculating the Net Proceeds from the Robinson's Bend Field prior to January 1, 2003. Severance tax deducted in calculating distributions during the years ended December 31, 1998, 1997 and 1996 totaled $710,000, $874,000 and $1,018,000, respectively, for all four fields.
General and administrative expenses during the years ended December 31, 1998, 1997 and 1996 amounted to $700,000, $678,000 and $684,000, respectively. These expenses primarily relate to administrative services provided by Torch and the Trustee.
During the year ended December 31, 1998, an impairment of $29.1 million was recorded to the financial statement line item titled "Amortization of Net Profits Interest" on the Statement of Changes in Trust Corpus to reduce the carrying value of the Net Profits Interest in accordance with Financial Accounting Standards Board Statement No. 121. Such impairment was mainly attributable to depressed gas prices. This impairment did not impact current year cash distributions nor Section 29 Credits allocated to Unitholders and additionally will not affect future cash distributions and Section 29 Credits. No such impairment was recorded during the years ended December 31, 1997 and 1996.
For the year ended December 31, 1998, distributable income was $12,936,000, or $1.50 per Unit, as compared to $14,525,000, or $1.69 per Unit, and $16,722,000, or $1.94 per Unit, for the same periods in 1997 and 1996, respectively. Total cash distributions of $12,917,000, or $1.50 per Unit, were made during the year ended December 31, 1998 as compared to $14,534,000, or $1.69 per Unit, and $16,727,000, or $1.95 per Unit, for the same periods in 1997 and 1996, respectively. The Section 29 Credits relating to qualifying production from coal seam and tight sands properties, during the twelve months ended September 30, 1998, 1997 and 1996, totaled approximately $0.38, $0.41 and $0.44 per Unit, respectively.
TORCH ENERGY ROYALTY TRUST
Net profits received by the Trust during the years ended December 31, 1998, 1997, and 1996, derived from production sold during the twelve months ended September 30, 1998, 1997 and 1996, respectively, was computed as shown in the following table (in thousands):
(a) Lease operating expenses are not deducted in calculating Net Proceeds until January 1, 2003. Lease operating expenses and property taxes were $7,041, $7,163 and $8,024 during 1998, 1997 and 1996, respectively.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Trust is exposed to market risk, including adverse changes in commodity prices. The Trust's assets constitute Net Profits Interests in the Underlying Properties. As a result, the Trust's operating results can be significantly affected by fluctuations in commodity prices caused by changing market forces and the price received for production from the Underlying Properties.
All production from the Underlying Properties is sold pursuant to a Purchase Contract between TRC and Velasco, as the owners of the Underlying Properties, and TEMI. Pursuant to the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an Index Price, less certain other charges. Substantially all of the Index Price is calculated based on market prices of oil and gas and therefor is subject to commodity price risk. The Purchase Contract expires upon termination of the Trust and provides a Minimum Price of $1.70 per MMBtu paid by TEMI for gas until December 31, 2000. When TEMI pays a purchase price based on the Minimum Price, it receives Price Credits equal to the difference between the Index Price and the Minimum Price that it is entitled to deduct when the Index Price exceeds the Minimum Price. Additionally, if the Index Price exceeds $2.10 per MMBtu, TEMI is entitled to deduct such excess, the Price Differential. Beginning January 1, 2001, TEMI has an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be entitled to deduct the Price Differential and will forfeit all accrued Price Credits.
TORCH ENERGY ROYALTY TRUST
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
Wilmington Trust Company as Trustee of Torch Energy Royalty Trust and to the Unitholders:
We have audited the accompanying statements of assets, liabilities and trust corpus of the Torch Energy Royalty Trust (the "Trust") as of December 31, 1998 and 1997, and the related statements of distributable income and changes in trust corpus for each of the years then ended. These financial statements are the responsibility of the Trustee. 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.
As described in Note 2, the financial statements are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Trust as of December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the years then ended, on the basis of accounting described in Note 2.
/s/ KPMG LLP Houston, Texas March 26, 1999
INDEPENDENT AUDITORS' REPORT
Wilmington Trust Company as Trustee of Torch Energy Royalty Trust and to the Unitholders:
We have audited the statements of distributable income and changes in trust corpus of the Torch Energy Royalty Trust (the "Trust") for the year ended December 31, 1996. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the financial statements based on our audit.
We conducted our audit 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 the Trustee, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As described in Note 2 to the financial statements, these financial statements have been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles.
In our opinion, such financial statements present fairly, in all material respects, the distributable income and changes in trust corpus of the Trust for the year ended December 31, 1996 on the basis of accounting described in Note 2.
/s/ Deloitte & Touche LLP - - -------------------------- Houston, Texas March 18, 1997
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (In thousands)
ASSETS
The accompanying notes to financial statements are an integral part of these statements.
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF DISTRIBUTABLE INCOME (In thousands, except per Unit amounts)
The accompanying notes to financial statements are an integral part of these statements.
TORCH ENERGY ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS (In thousands)
The accompanying notes to financial statements are an integral part of these statements.
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
1. Nature of Operations
The Torch Energy Royalty Trust ("Trust") was formed effective October 1, 1993, pursuant to a trust agreement ("Trust Agreement") among Wilmington Trust Company, as trustee ("Trustee"), Torch Royalty Company ("TRC") and Velasco Gas Company, Ltd. ("Velasco") as owners of certain oil and gas properties ("Underlying Properties") and Torch Energy Advisors Incorporated ("Torch") as grantor. TRC and Velasco created net profits interests ("Net Profits Interests") and conveyed such interests to Torch. Torch conveyed the Net Profits Interests to the Trust in exchange for an aggregate of 8,600,000 units of beneficial interest ("Units"). Such Units were sold to the public through various underwriters in November 1993.
The Trust will not terminate prior to January 1, 2003, except upon the affirmative vote of the holders of not less than 80% of the outstanding Units. Thereafter, the Trust will terminate upon the first to occur of: (i) an affirmative vote of the holders of not less than 66-2/3% of the outstanding Units to liquidate the Trust; (ii) such time as the ratio of the cash amounts received by the Trust from the Net Profits Interests to administrative costs of the Trust is less than 1.2 to 1.0 for three consecutive quarters; (iii) March 1 of any year if it is determined based on a reserve report as of December 31 of the prior year that the present value of estimated pre-tax future net cash flows, discounted at 10%, of proved reserves attributable to the Net Profits Interests is equal to or less than $25 million; or (iv) December 31, 2012. After termination of the Trust, the remaining assets of the Trust will be sold, and the proceeds therefrom (after expenses) will be distributed to the unitholders ("Unitholders"). The sole purpose of the Trust is to hold the Net Profits Interests, to receive payments from TRC and Velasco, and to make payments to Unitholders. The Trust does not conduct any business activity.
TRC and Velasco receive payments reflecting the proceeds of oil and gas sold and aggregate these payments, deduct applicable costs and make payments to the Trustee each quarter for the amounts due to the Trust. Unitholders receive quarterly cash distributions relating to oil and gas produced and sold from the Underlying Properties. Because no additional properties will be contributed to the Trust, the assets of the Trust deplete over time and a portion of each cash distribution made by the Trust is analogous to a return of capital.
The only assets of the Trust, other than cash and temporary investments being held for the payment of expenses and liabilities and for distribution to Unitholders, are the Net Profits Interests. Under the Trust Agreement, the Trustee receives the payments attributable to the Net Profits Interests and pays all expenses, liabilities and obligations of the Trust. The Trustee has the discretion to establish a cash reserve for the payment of any liability that is contingent or uncertain in amount or that otherwise is not currently due and payable. The Trustee is entitled to cause the Trust to borrow money to pay expenses, liabilities and obligations that cannot be paid out of cash held by the Trust. The Trustee is entitled to cause the Trust to borrow from any source, including from the entity serving as Trustee, provided that the entity serving as Trustee shall not be obligated to lend to the Trust. To secure payment of any such indebtedness (including any indebtedness to the Trustee), the Trustee is authorized to (i) mortgage and otherwise encumber the entire Trust estate or any portion thereof; (ii) carve out and convey production payments; (iii) include all terms, powers, remedies, covenants and provisions it deems necessary or advisable, including confession of judgement and the power of sale with or without judicial proceedings; and (iv) provide for the exercise of those and other remedies available to a secured lender in the event of a default on such loan. The terms of such indebtedness and security interest, if funds were loaned by the Trustee, must be similar to the terms which the Trustee would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and the Trustee shall by entitled to enforce
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
its rights with respect to any such indebtedness and security interest as if it were not then serving as Trustee.
The Trustee is authorized and directed to sell and convey the Net Profits Interests without Unitholder approval in certain instances as described in the Trust Agreement, including upon termination of the Trust. The Trustee is empowered by the Trust Agreement to employ consultants and agents (including Torch) and to make payments of all fees for services or expenses out of the assets of the Trust.
2. Basis of Accounting
The financial statements of the Trust are prepared on a modified cash basis and are not intended to present the financial position and results of operations in conformity with generally accepted accounting principles ("GAAP"). Preparation of the Trust's financial statements on such basis includes the following:
- - - Revenues are recognized in the period in which amounts are received by the Trust. Therefore, revenues recognized during the years ended December 31, 1998, 1997 and 1996 are derived from oil and gas production sold during the twelve-month periods ended September 30, 1998, 1997 and 1996, respectively. General and administrative expenses are recognized on an accrual basis.
- - - Amortization of the Net Profits Interests is calculated on a unit-of- production basis and charged directly to trust corpus.
- - - Distributions to Unitholders are recorded when declared by the Trustee.
- - - An impairment loss is recognized when the net carrying value of the Net Profits Interests exceeds the sum of the estimated undiscounted future cash flows attributable to the Trust's oil and gas reserves plus the estimated future tax credits under Section 29 of the Internal Revenue Code of 1986 ("Section 29 Credit") for Federal income tax purposes. The impairment loss is equal to the difference between the carrying value of the Net Profits Interest and the fair value of the Net Profits Interest.
In computing the estimated undiscounted future cash flows, estimated future oil and gas prices as determined by Torch management, are applied to estimated future production of oil and gas reserves over the economic lives of the reserves and pursuant to the Trust Agreement. If the aforementioned undiscounted future cash flows and Section 29 Credits are less than the carrying value of the Net Profits Interest, an impairment provision is recognized. The fair value of the Net Profits Interest is computed by discounting the aforementioned cash flows and Section 29 Credits by 10%. Additionally, it is assumed for these computations that TEMI continues its Minimum Price commitment, pursuant to the Purchase Contract, until the Trust dissolves. Based on Torch management's pricing assumptions and production estimates by T.J. Smith & Company, Inc., Ryder Scott Company and H.J. Gruy and Associates ("Independent Reserve Engineers") at December 31, 1998, the present value of the estimated pre-tax future net cash flow, discounted at 10%, for the proved reserves attributable to the Net Profits Interest will be less than $25 million in 2003. Pursuant to the Trust Agreement, it was assumed that the Trust would then dissolve and the remaining assets of the Trust would be sold and the proceeds therefrom would be distributed to the Unitholders. The aforementioned impairment test resulted in a $29.1 million write-down in the carrying value of the Net Profits Interest during the fourth quarter of 1998.
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
- - - The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because net profits income is not accrued in the period of production and amortization of the Net Profits Interests is not charged against operating results.
3. Federal Income Taxes
Tax counsel has advised the Trustee that, under current tax law, the Trust is classified as a grantor trust for Federal income tax purposes and not an association taxable as a business entity. However, the opinion of tax counsel is not binding on the Internal Revenue Service. As a grantor trust, the Trust is not subject to Federal income tax.
Because the Trust is treated as a grantor trust for Federal income tax purposes and a Unitholder is treated as directly owning an interest in the Net Profits Interests, each Unitholder is taxed directly on such Unitholder's pro rata share of income attributable to the Net Profits Interests consistent with the Unitholder's method of accounting and without regard to the taxable year or accounting method employed by the Trust. Amounts payable with respect to the Net Profits Interests are paid to the Trust on the quarterly record date established for quarterly distributions in respect to each calendar quarter during the term of the Trust, and the income, deductions and income tax credits relating to Section 29 Credits resulting from such payments are allocated to the Unitholders of record on such date.
4. Distributions and Income Computations
Each quarter the amount of cash available for distribution to Unitholders (the "Quarterly Distribution Amount") is equal to the excess, if any, of the cash received by the Trust, on the last day of the second month following the previous calendar quarter (or the next business day thereafter) ending prior to the dissolution of the Trust, from the Net Profits Interests then held by the Trust plus, with certain exceptions, any other cash receipts of the Trust during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the payment of contingent or future obligations of the Trust. Based on the payment procedures relating to the Net Profits Interest, cash received by the Trust on the last day of the second month of a particular quarter from the Net Profits Interests generally represents proceeds from the sale of oil and gas produced from the Underlying Properties during the preceding calendar quarter. The Quarterly Distribution Amount for each quarter is payable to Unitholders of record on the last day of the second month of the calendar quarter unless such day is not a business day in which case the record date is the next business day thereafter. The Trust distributes the Quarterly Distribution Amount, which is distributed within approximately 10 days after the record date to each person who was a Unitholder of record on the associated record date.
5. Related Party Transactions
Marketing Arrangements
TRC and Velasco, as owners of the Underlying Properties subject to and burdened by the Net Profits Interests, contracted to sell the oil and gas production from such properties to Torch Energy Marketing, Inc. ("TEMI"), a subsidiary of Torch, under a purchase contract ("Purchase Contract"). Under the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an index price for oil and gas ("Index Price"), less certain gathering, treating and transportation charges, which are calculated monthly. The Index Price equals 97% of the average spot market prices of oil and gas ("Average Market Prices") at the four locations where TEMI sells production, which, prior to September 1, 2000, is adjusted to reflect the terms of a hedge contract
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
("Hedge Contract") to which TEMI is a party. Under the Hedge Contract, TEMI receives prices specified in the Hedge Contract ("Specified Prices") for quantities of oil and gas specified therein ("Specified Quantities"). While the Index Price calculation reflects the terms of the Hedge Contract, the Trust's net profits income is not impacted by payments or receipts made by or received by TEMI in connection with its participation in the Hedge Contract. In calculating the Index Price for gas (which represents approximately 97% of the estimated reserves as of January 1, 1999, on an Mcfe basis), the Specified Prices received weightings ranging from approximately 40% to 70% pertaining to production prior to August 31, 1997. Thereafter, the Specified Prices receive a weighting of approximately 10% and less. The Average Market Prices receive the balance of the weighting. The Specified Prices for gas increase each year from $1.83 per MMBtu in 1996 to $1.89 per MMBtu in 2000 and are adjusted to reflect the difference between the settlement prices for oil and gas in the futures markets and the Average Market Prices.
The Purchase Contract also provides that the minimum price paid by TEMI for gas production is $1.70 per MMBtu ("Minimum Price"). When TEMI pays a purchase price based on the Minimum Price it receives price credits ("Price Credits") equal to the difference between the Index Price and the Minimum Price that it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. Price Credits are computed on a monthly basis, and as of December 31, 1998, TEMI's outstanding Price Credits, net to the Trust, were $97,000. All such Price Credits were attributable to September 1998 production. TEMI may be entitled to deduct these Price Credits in calculating the purchase price in the future when the Index Price for gas exceeds the Minimum Price. Net Price Credits in the amount of $317,000 and $2,305,000 were deducted in calculating the purchase price related to distributions during 1997 and 1996, respectively. In addition, if the Index Price for gas exceeds $2.10 per MMBtu ("Sharing Price"), TEMI is entitled to deduct 50% of such excess ("Price Differential") in determining the purchase price. Beginning January 1, 2001, TEMI has an annual option to discontinue the Minimum Price commitment. However, if TEMI discontinues the Minimum Price commitment, it will no longer be entitled to deduct the Price Differential in calculating the purchase price and will forfeit all accrued Price Credits. TEMI has purchased contracts granting TEMI the right to sell estimated gas production in excess of the Specified Quantities at a price intended to limit TEMI's losses in the event the Index Price falls below the Minimum Price.
Gross revenues (before deductions for applicable gathering, treating and transportation charges) from TEMI included in net profits income for the years ended December 31, 1998, 1997 and 1996 were $18,638,000, $20,719,000 and $23,531,000, respectively.
Gas production is purchased at the wellhead and, therefore, distributions do not include any amounts received in connection with extracting natural gas liquids from such production at gas processing or treating facilities.
Gathering, Treating and Transportation Arrangements
The Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation costs in calculating the purchase price for gas in the Robinson's Bend, Austin Chalk and Cotton Valley Fields. The amounts that may be deducted in calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and transport gas. In the Robinson's Bend Field, TEMI is entitled to deduct a gathering, treating and transportation fee of $0.26 per MMBtu adjusted annually for inflation ($0.274 for 1998 and 1997 and $0.272 per MMBtu for 1996), plus fuel usage equal to 5% of revenues, payable to Bahia Gas Gathering, Ltd. ("Bahia"), an affiliate of Torch, pursuant to a gas gathering agreement. Additionally, a fee of $0.05 per MMBtu,
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
representing a gathering fee payable to a non-affiliate of Torch, is deducted in calculating the purchase price for production from 68 of the 394 wells in the Robinson's Bend Field. TEMI also deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase price for production from the Austin Chalk Fields, as a fee to gather, treat and transport gas production. TEMI deducts from the purchase price for gas in the Cotton Valley Fields a transportation fee of $0.045 per MMBtu for production attributable to certain wells. This transportation fee is paid to a third party. During the years ended December 31, 1998, 1997 and 1996, gathering, treating and transportation fees charged to the Trust by TEMI, attributable to production during the twelve months ended September 30, 1998, 1997 and 1996 in the Robinson's Bend, Austin Chalk and Cotton Valley Fields, totaled $1,650,000, $1,965,000 and $2,137,000, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.
Operator Overhead Fees
A subsidiary of Torch operates certain oil and gas interests burdened by the Net Profits Interests. The Underlying Properties are charged, on the same basis as other third parties, for all customary expenses and costs reimbursements associated with these activities. Operator overhead fees deducted from the Net Proceeds computations for the Chalkley, Cotton Valley and Austin Chalk fields totaled $196,000, $182,000, and $181,000 for the years ended December 31, 1998, 1997 and 1996, respectively. In accordance with the Conveyance, no overhead fees were deducted in calculating the Net Proceeds from the Robinson Bend properties.
Administrative Services Agreement
Pursuant to the Trust Agreement, Torch and the Trust entered into an administrative services agreement, effective October 1, 1993. The Trust is obligated, throughout the term of the Trust, to pay to Torch each quarter an administrative services fee for accounting, bookkeeping, informational and other services relating to the Net Profits Interests. The administrative services fee is $87,500 per calendar quarter commencing October 1, 1993. The amount of the administrative services fee is adjusted annually, based upon the change in the Producer's Price Index as published by the Department of Labor, Bureau of Labor Statistics. Administrative services fees of $368,000 were paid by the Trust to Torch during the year ended December 31, 1998. Such fees were $366,000 during each of the years ended December 31, 1997 and 1996.
Compensation of the Trustee and Transfer Agent
The Trust Agreement provides that the Trustee be compensated for its administrative services, out of the Trust assets, in an annual amount of $41,000, plus an hourly charge for services in excess of a combined total of 250 hours annually at its standard rate. The Trustee receives a transfer agency fee of $5.00 annually per account (minimum of $15,000 annually), subject to change each December, beginning December 1994, based upon the change in the Producer's Price Index as published by the Department of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate issued. Total administrative and transfer agent fees charged by the Trustee were $56,000 in each of the years ended December 31, 1998, 1997 and 1996. The Trustee is also entitled to reimbursement for out-of- pocket expenses.
6. Supplemental Oil and Gas Information (Unaudited)
Total proved oil and gas reserves attributable to the Net Profits Interests are primarily based upon reserve reports prepared by Independent Reserve Engineers. Future net cash flows were computed by applying
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
end-of-period Purchase Contract prices for oil and gas to estimated future production, less the estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves. In accordance with terms of the Robinson's Bend Field Conveyance, no operating or developing costs prior to January 1, 2003 were deducted from the Robinson's Bend Field future net revenues.
Reserve Quantities:
The following table sets forth the estimated total and proved developed oil and gas reserves attributable to the Trust's Net Profits Interests (all located in the United States) for the years ended December 31, 1998, 1997 and 1996, based on reserve reports prepared by the Independent Reserve Engineers. As a net profits interest does not entitle the Trust to a specific quantity of oil or gas, but to a portion of oil and gas sufficient to yield a specified portion of the net proceeds derived therefrom, proved reserves attributable to a net profits interest are calculated by deducting an amount of oil or gas sufficient, if sold at the prices used in preparing the reserve estimates for the Underlying Properties, to pay an amount of applicable future estimated production expenses, development costs and taxes for such Underlying Properties. The use of this convention to estimate reserve volumes attributable to the Net Profits Interests is standard practice in the industry.
Year-end reserves at December 31, 1998 were 33.6 billion cubic feet equivalent ("Bcfe") as compared to 1997 year-end reserves of 42.0 Bcfe. The reduction in reported reserves includes 1998 production of 6.3 Bcfe and a negative reserve revision of 2.1 Bcfe. Such reserve revision was primarily a result of a decline in natural gas prices in 1998 as compared to 1997.
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (in thousands):
Estimated future net cash flows from the Net Profits Interests in proved oil and gas reserves at December 31, 1998, 1997 and 1996 are presented in the following table:
The following table sets forth the changes in the present value of estimated future net revenues from proved reserves attributable to the Trust's Net Profits Interests during the years ended December 31, 1998, 1997 and 1996:
Estimates of future net cash flows from proved reserves of gas and oil condensate were made in accordance with Financial Accounting Standards Board Statement 69, "Disclosure about Oil and Gas Producing Activities." The Trust has not filed or included in reports to any other Federal authority or agency any estimates of proved net oil and gas reserves.
The following table summarizes the estimated Section 29 Credits attributable to the Trust's Net Profits Interest for qualifying coal seam and tight sand production at December 31, 1998, 1997, and 1996. Such estimates are based upon the production estimates set forth in the reserve reports prepared by the Independent Reserve Engineers. The qualifying tight sands Section 29 Tax Credit estimate was computed utilizing a rate of approximately $.52 per MMBtu. The qualifying coal seam Section 29 Tax Credit estimate was computed utilizing a constant rate of approximately $1.06, $1.05 and $1.03 per MMBtu for 1998, 1997 and 1996, respectively.
TORCH ENERGY ROYALTY TRUST
NOTES TO FINANCIAL STATEMENTS
7. Quarterly Financial Data (Unaudited--in thousands, except per Unit amounts)
The following table sets forth, for the periods indicated, summarized quarterly financial data:
TORCH ENERGY ROYALTY TRUST
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
During February 1998 the firm of Deloitte & Touche LLP was replaced as the Trust's principal independent accountant and auditors to audit all the Trust's financial statements with the firm of KPMG LLP. The Trust had no disagreements with Deloitte & Touche LLP concerning their audit or the application of accounting principles.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Registrant has no directors or executive officers. The Trustee is a corporate trustee that may be removed as trustee under the Trust Agreement, with or without cause, at a meeting duly called and held by the affirmative vote of Unitholders of not less than a majority of all the Units then outstanding. Any such removal of the Trustee shall be effective only at such time as a successor trustee fulfilling the requirements of Section 3807(a) of the Delaware Business Trust Act has been appointed and has accepted such appointment.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The following is a description of certain fees and expenses paid or borne by the Trust, including fees paid to Torch, the Trustee, the Transfer Agent or their affiliates.
Ongoing Administrative Expenses. The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the Trustee in its capacity as Trustee and/or transfer agent.
Compensation of the Trustee and Transfer Agent. The Trust Agreement provides that the Trustee be compensated for its administrative services, out of the Trust assets, in an annual amount of $41,000, plus an hourly charge for services in excess of a combined total of 250 hours annually at its standard rate. The Trustee receives a transfer agency fee of $5.00 annually per account (minimum of $15,000 annually), subject to change each December, beginning December 1994, based upon the change in the Producer's Price Index as published by the Department of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate issued. The Trustee is entitled to reimbursement for out-of-pocket expenses.
Fees to Torch. Torch will receive, throughout the term of the Trust, an administrative services fee for accounting, bookkeeping and informational services related to the Net Profits Interests as described below in "Item 13 Administrative Services Agreement."
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of March 25, 1999, no person or group of persons was known by the Trust to be the beneficial owner of more than 5% of the Units. The Trust has no officers or directors.
TORCH ENERGY ROYALTY TRUST
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Administrative Services Agreement
Pursuant to the Trust Agreement, Torch and the Trust entered into the Administrative Services Agreement effective October 1, 1993. The following summary of certain provisions of the Administrative Services Agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, the provisions of the Administrative Services Agreement.
The Trust is obligated, throughout the term of the Trust, to pay to Torch each quarter an administrative services fee for accounting, bookkeeping, informational and other services relating to the Net Profits Interests. The administrative services fee is $87,500 per calendar quarter, adjusted annually, based upon the change in the Producer's Price Index as published by the Department of Labor, Bureau of Labor Statistics. Administrative services fees of $368,000 were paid by the Trust to Torch during the year ended December 31, 1998. Such fees were $366,000 in each of the years ended 1997 and 1996.
Marketing Arrangement
TRC and Velasco, as owners of the Underlying Properties subject to and burdened by the Net Profits Interests, contracted to sell the oil and gas production from such properties to TEMI under a Purchase Contract. Under the Purchase Contract, TEMI is obligated to purchase all net production attributable to the Underlying Properties for an Index Price for oil and gas less certain gathering, treating and transportation charges, which are calculated monthly. The Purchase Contract also provides that the Minimum Price paid by TEMI for gas production is $1.70 per MMBtu. When TEMI pays a purchase price based on the Minimum Price, it receives Price Credits equal to the difference between the Index Price and the Minimum Price that it is entitled to deduct in determining the purchase price when the Index Price for gas exceeds the Minimum Price. As of December 31, 1998, TEMI had accumulated Price Credits of $97,000, net to the Trust. TEMI may be entitled to deduct such Price Credits in calculating the purchase price in the future. Net Price Credits in the amount of $317,000 and $2,305,000 were deducted in calculating the purchase price related to distributions during 1997 and 1996, respectively.
Gross revenues (before deductions for applicable gathering, treating and transportation charges) from TEMI included in net profits income for the years ended December 31, 1998, 1997 and 1996 were $18,638,000, $20,719,000 and $23,531,000, respectively.
Gathering, Treating and Transportation Arrangements
The Purchase Contract entitles TEMI to deduct certain gas gathering, treating and transportation costs in calculating the purchase price for gas in the Robinson's Bend, Austin Chalk and Cotton Valley Fields. The amounts that may be deducted in calculating the purchase price for such gas are set forth in the Purchase Contract and are not affected by the actual costs incurred by TEMI to gather, treat and transport gas. In the Robinson's Bend Field, TEMI is entitled to deduct a gathering, treating and transportation fee of $0.26 per MMBtu commencing October 1, 1993 adjusted for inflation ($0.274 for 1998 and 1997 and $0.265 per MMBtu for 1996), plus fuel usage equal to 5% of revenues, payable to Bahia Gas Gathering, Ltd. ("Bahia"), an affiliate of Torch, pursuant to a gas gathering agreement. Additionally, a fee of $0.05 per MMBtu, representing a gathering fee payable to a non-affiliate of Torch, is deducted in calculating the purchase price for production from 68 of the 394 wells in the Robinson's Bend Field. TEMI also deducts $0.38 per MMBtu plus 17% of revenues in calculating the purchase price for production from the Austin Chalk Fields, as a fee to gather, treat and transport gas production. TEMI deducts from the purchase price for gas a transportation fee of $0.045 MMBtu for production attributable to certain wells in the Cotton
TORCH ENERGY ROYALTY TRUST
Valley Fields. During the years ended December 31, 1998, 1997 and 1996, gas gathering, treating and transportation fees charged to the Trust by TEMI, attributable to production during the 12 months ended September 30, 1998, 1997 and 1996 in the Robinson's Bend, Austin Chalk and Cotton Valley Fields, totaled $1,650,000, $1,965,000 and $2,137,000, respectively. No amounts for gathering, treating or transportation are deducted in calculating the purchase price from the Chalkley Field.
TORCH ENERGY ROYALTY TRUST
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements:
Torch Energy Royalty Trust Independent Auditors' Reports Statements of Assets, Liabilities and Trust Corpus at December 31, 1998 and 1997 Statements of Distributable Income for the Years Ended December 31, 1998, 1997 and 1996 Statements of Changes in Trust Corpus for the Years Ended December 31, 1998, 1997 and 1996 Notes to Financial Statements
Torch Energy Advisors Incorporated and Subsidiaries ("Torch") and Torch's Predecessor ("Predecessor") Independent Auditors' Report Consolidated Balance Sheet of Torch as of December 31, 1998 and 1997 and the Related Consolidated Statements of Operations, Stockholders' Equity and Comprehensive Income, and Cash Flows for the years ended December 31, 1998 and 1997 and for the Period October 1, 1996 through December 31, 1996 Predecessor's Consolidated Statement of Operations, Predecessor's Equity and Comprehensive Income and Cash Flows for the Period January 1, 1996 through September 30, 1996 Notes to Consolidated Financial Statements
2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the financial statements and notes thereto.
3. Exhibits
EXHIBIT NUMBER EXHIBIT
4. - Instruments of defining the rights of security holders, including indentures. 4.1 - Form of Torch Energy Royalty Trust Agreement.* 4.2 - Form of Louisiana Trust Agreement.* 4.3 - Specimen Trust Unit Certificate.* 4.4 - Designation of Ancillary Trustee.*
10.- Material contracts. 10.1 - Purchase Agreement between TRC, Velasco and TEMI.* 10.2 - Gas Gathering Agreement between TEMI and Bahia Gas Gathering, Ltd.* 10.3 - Amendment to Gas Gathering Agreement.* 10.4 - Water Gathering and Disposal Agreement between Torch Energy Associates, Ltd. and Velasco.*
TORCH ENERGY ROYALTY TRUST
10.5 - Form of Texas Conveyance.* 10.6 - Form of Louisiana Conveyance.* 10.7 - Form of Alabama Conveyance.* 10.8 - Standby Performance Agreement between Torch and the Trust.* 10.9 - Amendment to Water Gathering Contract.* 10.10 - First Amendment to Oil and Gas Purchase Contract (previously filed on form 10-Q for the quarter ended September 30, 1994).
23. Consents of experts and counsel. 23.1 - Consent of T.J. Smith and Company, Inc. 23.2 - Consent of H.J. Gruy and Associates, Inc. 23.3 - Consent of Ryder Scott Company
27. Financial Data Schedule
99. Additional Exhibits. 99.1 Financial Statements of Torch Energy Advisors Incorporated.
* Incorporated by reference from Registration Statements on Form S-1 of Torch Energy Advisors Incorporated (Registration No. 33-68688) dated November 16, 1993 .
(b) Report on Form 8-K:
None filed during the quarter ended December 31, 1998.
SIGNATURES
Pursuant to the requirements 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.
TORCH ENERGY ROYALTY TRUST
By: Wilmington Trust Company Trustee
By: /s/ Bruce L. Bisson ------------------------------- Bruce L. Bisson, Vice President
Date: March 29, 1999
(The Trust has no directors or executive officers.)
TORCH ENERGY ROYALTY TRUST
Torch Energy Royalty Trust Rodney Square North 1100 North Market Street Wilmington, Delaware 19890 Attention: Corporate Trust Administration
Legal Counsel Butler & Binion, L.L.P. Houston, Texas
Tax Counsel Butler & Binion, L.L.P. Houston, Texas
Auditors KPMG LLP Houston, Texas
Transfer Agent and Registrar Wilmington Trust Company 1100 North Market Street Wilmington, Delaware 19890 Attention: Corporate Trust Administration
INDEPENDENT AUDITORS' REPORT
The Board of Directors Torch Energy Advisors Incorporated:
We have audited the accompanying consolidated balance sheets of Torch Energy Advisors Incorporated and subsidiaries as of December 31, 1998 and 1997 and the related consolidated statements of operations, stockholders' equity and comprehensive income and cash flows for the years ended December 31, 1998 and 1997 and the period October 1, 1996 through December 31, 1996 and the related Predecessor's consolidated statements of operations, predecessor's equity and comprehensive income and cash flows for the period January 1, 1996 through September 30, 1996. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Torch Energy Advisors Incorporated and subsidiaries as of December 31, 1998 and 1997 and the results of their operations and their cash flows and those of their Predecessors for the years ended December 31, 1998 and 1997, the period October 1, 1996 through December 31, 1996 and the period January 1, 1996 through September 30, 1996, in conformity with generally accepted accounting principles.
As discussed in Notes 1 and 8, on September 30, 1996, certain members of the Predecessor's management purchased the Predecessor. The consolidated financial statements of the Company reflect assets and liabilities at fair value at the date of the purchase. As a result, the consolidated financial statements of the Company are presented on a different basis than those of the Predecessor and, therefore, are not comparable in all respects.
March 30, 1999 Houston, Texas
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
(Amounts in Thousands)
ASSETS
December 31, ----------------- 1998 1997 -------- -------- CURRENT ASSETS:
Cash and cash equivalents.............................. $ 35,923 $ 49,900 Accounts receivable - product marketing................ 45,636 55,588 Accounts receivable - joint interest billing........... 10,692 7,903 Accounts receivable - oil and gas and other............ 23,357 23,840 Due from affiliates.................................... 7,856 3,405 Other current assets................................... 5,118 3,154 -------- -------- Total current assets................................. 128,582 143,790 -------- -------- PROPERTY AND EQUIPMENT, AT COST:
Oil and gas (successful efforts method)................ 8,106 6,354 Other fixed assets..................................... 10,363 5,543 -------- -------- 18,469 11,897
Accumulated depreciation, depletion and amortization... (5,574) (2,179) -------- -------- 12,895 9,718 -------- --------
DUE FROM AFFILIATES........................................ 2,967 1,850
NOTES RECEIVABLE........................................... 37,001 13,363
INVESTMENT IN MARKETABLE SECURITIES........................ 741 1,650
EQUITY INVESTMENTS......................................... 5,735 4,049
INVESTMENTS AT COST........................................ 400 400
OTHER ASSETS............................................... 1,753 1,142 -------- -------- $190,074 $175,962 ======== ========
See accompanying notes to consolidated financial statements.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Amounts in Thousands, except Share Data)
LIABILITIES AND STOCKHOLDERS' EQUITY
December 31, ------------------- 1998 1997 -------- -------- CURRENT LIABILITIES: Accounts payable - product marketing $ 46,519 $ 56,957 Accounts payable - joint interest billing 7,445 3,865 Accrued liabilities 21,221 24,933 Note payable to bank --- 60 Revenue, royalty and production taxes payable 31,917 30,516 -------- -------- Total current liabilities 107,102 116,331 -------- --------
OTHER LIABILITIES 7,618 7,216 -------- --------
NOTE PAYABLE TO BANK 36,277 10,614 -------- -------- SENIOR SUBORDINATED NOTE PAYABLE - AFFILIATE 25,500 25,500 -------- -------- COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY: Common stock, par value $1.00, 1,000 shares authorized, issued and outstanding 1 1 Additional paid-in capital 1,999 1,999 Accumulated comprehensive income - unrealized gain (loss) in value of investment in equity securities, net (516) 394 Retained earnings 12,093 13,907 -------- -------- Total stockholders' equity 13,577 16,301 -------- -------- $190,074 $175,962 ======== ========
See accompanying notes to consolidated financial statements.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in Thousands)
See accompanying notes to consolidated financial statements.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' AND PREDECESSOR'S EQUITY AND COMPREHENSIVE INCOME YEARS ENDED DECEMBER 31, 1998 AND 1997 AND OCTOBER 1, 1996 THROUGH DECEMBER 31, 1996 AND JANUARY 1, 1996 THROUGH SEPTEMBER 30, 1996
(Amounts in Thousands)
See accompanying notes to consolidated financial statements.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in Thousands)
See accompanying notes to consolidated financial statements.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(Amounts in Thousands)
See accompanying notes to consolidated financial statements.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(Amounts in Thousands)
See accompanying notes to consolidated financial statements.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
1. ORGANIZATION
Torch Energy Advisors Incorporated ("TEAI" or the "Company") provides an extensive array of specialized outsourcing services to companies primarily in the energy industry. Services include accounting and finance, information technology, procurement, oil and gas operations, hydrocarbon marketing, and property acquisitions and divestitures. TEAI also provides growth capital, in the form of mezzanine finance and equity capital, to independent oil and gas producers. Since 1981, the Company's clients have included insurance companies, corporate and public pension funds, foundations, endowments, foreign investors and public oil and gas companies. Since inception, the Company has invested approximately $1.6 billion on behalf of the Company and its clients. The Company is headquartered in Houston, Texas, and maintains operational district offices in Texas, Oklahoma, California and Alabama.
Until September 1996, TEAI (the "Predecessor" when discussing periods prior to September 30, 1996) operated as a single business segment and was a wholly owned subsidiary of Torchmark Corporation ("Torchmark"), an insurance and financial services holding company headquartered in Birmingham, Alabama. On September 30, 1996, certain members of the Predecessor's executive management, through the formation of Management Holding Company ("MHC") and Torch Acquisition Company ("TAC"), purchased TEAI from Torchmark ("the Management Buyout") (See Note 8). Torchmark retained a warrant for 10% of TAC's common stock on a fully diluted basis. The Management Buyout was recorded using the purchase method of accounting as TEAI's executive management had no ownership in the Predecessor. During 1997, MHC was merged into TAC.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION -
The consolidated financial statements include the accounts of the Company, its wholly owned subsidiaries and its majority owned subsidiaries. The Company's investments in 15 oil and gas partnerships ("partnerships") were accounted for under the equity method due to the Company's ability to exercise significant influence over operating and financial policies of the investees until April 1997 at which time the partnerships were sold to Bellwether Exploration Company ("Bellwether"). All significant intercompany accounts and transactions have been eliminated.
Effective November 1, 1996 Torch Energy Marketing, Inc. ("TEMI"), a wholly owned subsidiary, formed a limited liability company with an unaffiliated party to conduct gas marketing activities. TEMI acts as a manager and owns a 50% interest in this venture. As the Company effectively controls the venture through management contracts and execution of the day-to-day operating and financial decisions, the activities for this venture are included in the financial statements with the unaffiliated party's interest reflected as minority interest. During 1996, the Company formed two limited liability companies with an unaffiliated party to provide certain management, administrative and support services to a foreign party. The Company owned a 50% interest in both limited liability companies until March 1997 at which time the companies were sold. Prior to March 1997, the activities are consolidated in the financial statements with the unaffiliated parties' interest reflected as minority interest. Effective June 30, 1997, the Company purchased The Procurement Centre ("TPC") to obtain the benefit of TPC's experience and expertise in providing consulting and outsourcing services for the procurement of materials and services,
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
inventory management, logistics and other administrative services. The Company paid $375,000 to obtain a 75% interest in TPC. The activities of TPC subsequent to the acquisition are consolidated in the financial statements with the unaffiliated parties' interest reflected as a minority interest. Prior activities of TPC are not material.
Torch Energy Finance Fund LPI ("TEFF"), a Texas limited liability partnership, was formed on September 6, 1995 and amended on July 14, 1997 for the purpose of providing growth capital to small and mid-size oil and gas companies for use in acquisition and exploitation opportunities. Torch Energy Finance Company ("TEFC"), a wholly owned subsidiary, serves as the sole general partner (10%) and the Company serves as the sole limited partner (90%). Activities for TEFF are consolidated in the Company's financial statements. Advances to third party oil and gas companies are recorded as notes receivable. Equity investees, owned 20% through 50%, and over which the Company exercises significant influence, are accounted for by the equity method. All other unconsolidated investees are accounted for by the cost method.
The Company has a limited partnership interest in Southern Missouri Gas Company, L.P. ("SMGC"), a local natural gas distribution company located in Missouri. This investment of $2.7 million at December 31, 1998 is accounted for under the equity method.
Novistar, a wholly owned subsidiary, was formed on April 24, 1998 for the purpose of providing state-of-the-art business process services including transaction processing, information management and process reengineering in three principal areas: oil and gas property administration, information technology and procurement and inventory management. Activities for Novistar are consolidated in the Company's financial statements. Effective June 3, 1998, the Company formed a limited liability company, Torch Drilling Services, L.L.C. ("Torch Drilling"), for the purpose of acquiring a license to conduct short radius drilling technology on a pilot project. Activities for Torch Drilling are consolidated in the Company's financial statements. Effective December 15, 1998, the Company purchased Petroleum Financial, Inc. ("PFI"), a privately held provider of accounting and information technology outsourcing services to mid-market oil and gas companies. The company paid $1.25 million to obtain PFI's existing client base and to expand the Company's ability to reach new clients. The activities of PFI subsequent to the acquisition are consolidated in the financial statements. Prior activities of PFI are not material.
CASH AND CASH EQUIVALENTS -
Cash in excess of the Company's daily requirements is generally invested in short-term, highly liquid investments with original maturities of six months or less. Such investments are carried at cost, which approximates fair value and, for purposes of reporting cash flows, are considered to be cash equivalents.
INVESTMENT IN MARKETABLE SECURITIES -
Marketable investment securities are classified in three categories: trading, available-for-sale, or held-to-maturity. Trading securities are bought and held principally for the purpose of selling such securities in the near term. Held-to-maturity securities are those securities in which the Company has the ability and intent to hold the security until maturity. All other securities not included in trading or held-to-maturity are classified as available-for-sale.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
The Company has no held-to-maturity or trading securities at December 31, 1998. The Company has available-for-sale securities which are recorded at fair value, with unrealized gains and losses, excluded from earnings and reported as accumulated comprehensive income, a separate component of the stockholders' equity, net of deferred income taxes.
Dividend and interest income are recognized when earned. Realized gains and losses for securities classified as available-for-sale were included in earnings and were derived using the specific identification method for determining the cost of securities sold.
PROPERTY AND EQUIPMENT -
Oil and gas properties are accounted for on the successful efforts method whereby costs, including lease acquisition and intangible drilling costs associated with exploration efforts which result in the discovery of proved reserves and costs associated with development wells, whether or not productive, are capitalized. Gain or loss is recognized when a property is sold or ceases to produce and is abandoned. Capitalized costs of producing oil and gas properties are amortized using the unit-of-production method based on units of proved reserves as estimated by independent petroleum engineers.
The Company recognizes an impairment loss when the carrying amount of a long-lived asset exceeds the sum of the estimated undiscounted future cash flow of the asset. For each long-lived asset determined to be impaired, an impairment loss equal to the difference between the carrying value and the fair value of the depletable unit was recognized. Fair value, on a depletable unit basis, is estimated to be the present value of expected future cash flows computed by applying estimated future oil and gas prices, as determined by management, to estimated future production of oil and gas reserves over the economic lives of the reserves. The Company incurred no such writedown during the years ended December 31, 1998 and 1997 or the periods October 1, 1996 to December 31, 1996 and January 1, 1996 to September 30, 1996.
Costs of acquiring undeveloped oil and gas leases are capitalized and assessed periodically to determine whether an impairment has occurred; appropriate valuation allowances are established when necessary. No such allowance was required during the years ended December 31, 1998 and 1997 and the periods October 1, 1996 to December 31, 1996 and January 1, 1996 to September 30, 1996.
Fixed assets are depreciated on a straight-line basis over their estimated useful lives. Leasehold improvements, which are recorded at cost, are amortized on a straight-line basis over their estimated useful lives or the life of the lease, whichever is shorter.
GAS BALANCING -
The Company uses the entitlement method for recording sales of natural gas. Under the entitlement method of accounting, revenue is recorded based on the Company's net revenue interest in production. Deliveries of natural gas in excess of the Company's net revenue interest are recorded as liabilities and under-deliveries are recorded as assets. Production imbalances are recorded at the lower of the sales price in effect at the time of production or the current market value. At December 31, 1998 and 1997, the Company's liabilities due to gas sales in excess of
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
its entitled share were approximately $.67 million and $.47 million, respectively, and the receivables for gas sales less than the Company's entitled share were approximately $.56 million and $.53 million, respectively.
DERIVATIVES -
The Company entered into a variety of commodity derivative financial instruments (futures, swaps and option contracts) for non-trading purposes. The Company made use of these derivative financial instruments as a hedging strategy to manage commodity prices associated with gas sales and purchases and to reduce the risk of price fluctuations. The Company uses the hedge method of accounting for these instruments and, as a result, gains and losses related to commodity derivatives that qualify as hedges of commodity commitments are recognized in income when the underlying hedged physical transaction closes. To qualify as hedges, these instruments must highly correlate to anticipated future natural gas sales and purchases and crude oil sales, such that the Company's exposure to the effects of price changes is reduced. Gains and losses related to such instruments, to the extent settled in cash and for which the physical transaction has not yet closed, are reported in other current liabilities or other current assets as deferred gains or losses. The Company had deferred gains of $.4 million and $.3 million at December 31, 1998 and December 31, 1997, respectively. There were no deferred gains or losses at December 31, 1996. Gains or losses on derivative financial instruments that do not qualify as a hedge are immediately recognized in income. Oil and gas revenues and product marketing margin were increased by a total of $1.8 million in 1998, decreased by a total of $2.3 million in 1997, decreased by $.1 million for the period October 1, 1996 through December 31, 1996, and increased by $.8 million for the period January 1, 1996 through September 30, 1996 as a result of such derivative activity.
INCOME TAXES -
Effective in 1997, TEAI and its subsidiaries elected to be treated as qualified subchapter S corporations under Section 1361 (b) (3) of the Internal Revenue Code of 1986. The effect of the election is that TAC will file an S corporation tax return that includes TEAI and subsidiaries. Each TAC stockholder is responsible for reporting its share of taxable income or loss and no federal income taxes are recorded by the Company, except for a tax on excess net passive income and certain built-in gains, if applicable.
Prior to the consummation of the Management Buyout, the Predecessor and its subsidiaries were included in Torchmark's consolidated Federal income tax return. Income taxes were recorded as if the Predecessor and its subsidiaries filed a separate return and the Predecessor and its subsidiaries received a current benefit to the extent their losses were used in Torchmark's consolidated tax return. Taxes on income were reduced by utilizable tax credits in Torchmark's consolidated tax return. For the period January 1, 1996 through September 30, 1996, deferred income taxes were accounted for using the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of "temporary differences" by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The effect on deferred income taxes of a change in tax rates is recognized in income in the period the change occurs.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
RECLASSIFICATIONS -
Certain reclassifications of prior period statements have been made to conform with current reporting practices.
USE OF ESTIMATES -
Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates.
3. RELATED PARTY TRANSACTIONS
ACCOUNTS RECEIVABLE -
On October 9, 1998, the Company was issued a promissory note from one of the Company's officers for $1.8 million. Principal and interest is due on July 1, 1999.
NOTE RECEIVABLES -
On December 31, 1995, the Predecessor was issued a non-interest bearing note of approximately $18 million from Torchmark to replace an intercompany obligation of an affiliate. The note was forgiven by the Predecessor as a result of the Management Buyout.
ASSET MANAGEMENT -
The Company provides management services relating to oil and gas operations for affiliated entities and investees, including oil and gas limited partnerships. Bellwether and Nuevo Energy Company ("Nuevo") were affiliates of the Predecessor. In accordance with the management agreements, the Company provides various accounting and administrative services for a fixed or variable fee. In addition, the Company receives additional compensation for services related to property or corporate acquisitions or divestitures. The Company's total management fees received from related parties amounted to $1.0 million, $1.8 million and $2.8 million for the years ended December 31, 1998 and 1997 and the period October 1, 1996 through December 31, 1996, respectively. The Predecessor's total management fees received from related parties amounted to $23.7 million (includes $8 million related to Nuevo's purchase of Unocal California properties) for the period January 1, 1996 through September 30, 1996.
In the ordinary course of business, the Company incurs intercompany balances resulting from the payment of costs and expenses on behalf of related parties and from charging management fees under the terms of the respective management and administrative agreements. Such amounts are settled on a regular basis, generally monthly.
PRODUCT MARKETING -
The Company markets oil and natural gas production for properties in which related parties own interests. The Company's marketing fee ranges from .5% to 3% of revenues; such charge is
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
customary within the oil and gas industry. Such revenues for the Company amounted to $.3 million, $1.2 million and $.3 million for the years ended December 31, 1998 and 1997 and the period October 1,1996 through December 31, 1996, respectively. Marketing fees for the Predecessor amounted to $4.0 million for the period January 1, 1996 through September 30, 1996.
WELL OPERATIONS -
The Company operates properties in which related parties own interests. These entities are charged for all customary expenses and cost reimbursements associated with such activities on the same basis as third parties. Operators' overhead charged to affiliates by the Company for the years ended December 31, 1998 and 1997 and the period October 1, 1996 through December 31, 1996 for these activities was $.5 million, $.5 million and $.4 million, respectively. Operators' overhead charged to affiliates by the Predecessor for the period January 1, 1996 through September 30, 1996 was $5.7 million.
OTHER -
Interest expense paid to Torchmark totaled $.6 million for the period January 1, 1996 through September 30, 1996. No interest expense was paid to related entities for the years ended December 31, 1998 and 1997 and the period October 1, 1996 through December 31, 1996.
4. INCOME TAXES
The Company's and Predecessor's income tax provision for the years ended December 31, 1998 and 1997 and the periods October 1, 1996 through December 31, 1996 and January 1, 1996 through September 30, 1996, is comprised of the following (amounts in thousands):
(1) The 1997 amount relates to revisions of 1996 tax expense estimates.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
The Company's effective income tax rate differed from the statutory tax rate as follows:
5. INVESTMENTS IN EQUITY SECURITIES
In March 1996, the Predecessor sold 17 million shares of Gulf Canada Resources Ltd. ("Gulf Canada") shares (See Note 9), generating a pre-tax gain of approximately $2.5 million. In April 1996, the Predecessor received 1.3 million Nuevo shares (See Note 9) in exchange for certain California offshore oil properties. In September 1996, the Predecessor's interest in Gulf Canada (consisting of .9 million shares and 5.6 million warrants), Nuevo, and an approximate 1% common stock interest in Bellwether was transferred to Torchmark in connection with the Management Buyout (See Note 8). In April 1997, the Company received 150,000 Bellwether shares and a warrant to purchase 100,000 shares for the sale of certain partnerships (See Note 9).
At December 31, 1998, the Company recorded $.5 million in unrealized losses due to the difference between cost and market value in its investment in Bellwether, resulting in a carrying value of $.7 million. At December 31, 1997, the Company recorded $.4 million in unrealized gains due to the difference between cost and market value in its investment in Bellwether, resulting in a carrying value of $1.7 million. During the period January 1, 1996 through September 30, 1996, the Company recorded $16.1 million and $1.8 million in unrealized gains in Nuevo and Gulf Canada, resulting in a carrying value at the time of the Management Buyout of $51.8 million and $6.0 million, respectively. Carrying value of the investment in Bellwether approximated fair value for the period January 1, 1996 through September 30, 1996. There were no equity securities for the period October 1, 1996 through December 31, 1996.
6. NOTES RECEIVABLE
On April 29, 1997, TEFF was issued a promissory note for up to $12.5 million from TEC Resources, LLC ("TEC") as evidence of TEFF's loan agreement entered into on April 29, 1997 with TEC. An initial advance of the loan was made to TEC on April 29, 1997 for costs and expenses associated with certain oil and gas properties. The loan agreement provides that additional advances be made upon TEC's request at TEFF's sole discretion. On September 14, 1998, the maximum principal amount of the promissory note was increased to $30 million. Certain oil and gas property, other properties and all subsequently acquired assets of TEC secure the promissory note, which matures on April 28, 2001. At December 31, 1998 and 1997, the outstanding balance under the loan agreement was $16.6 million and $6.8 million, respectively.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
Interest accrues on indebtedness at 10% and is payable quarterly to the extent that there is positive cash flow from TEC's operations for the quarter then ended.
On July 17, 1997, TEFF was issued a promissory note for up to $5.25 million from NRC Development, LLC ("NRC") and NRC Pipeline, LLC as evidence of TEFF's loan agreement entered into on July 17, 1997 with NRC and NRC Pipeline, LLC. An initial advance of the loan was made to NRC on July 17, 1997 for costs and expenses associated with certain oil and gas properties. The loan agreement provides that additional advances be made upon NRC's request at TEFF's sole discretion. Certain oil and gas property, other properties and all subsequently acquired assets of NRC or NRC Pipeline, LLC secure the promissory note, which matures on July 17, 2002. At December 31, 1998 and 1997, the outstanding balance under the loan agreement was $4 million. Interest accrues on indebtedness at 15% and is payable quarterly to the extent that there is positive cash flow from NRC's operations for the quarter then ended.
On December 21, 1998, TEFF was issued a promissory note for up to $30 million from ARI Development, LLC ("ARI") as evidence of TEFF's loan agreement entered into on December 21, 1998 with ARI. An additional advance of the loan was made to ARI on December 21, 1998 for costs and expenses associated with certain oil and gas properties. The loan agreement provides that additional advances by made upon ARI's request at TEFF's sole discretion. Certain oil and gas property, other properties and all subsequently acquired assets of ARI secure the promissory note, which matures on December 31, 2003. At December 31, 1998, the outstanding balance under the loan agreement is $14.2 million. Interest accrues on indebtedness at 10% and is payable quarterly to the extent that there is a positive cash flow from ARI's operations for the quarter then ended.
The Company advanced $.7 million during 1998 to Carpatsky Petroleum, Inc. ("Carpatsky"), a Canadian publicly traded company, in exchange for a promissory note bearing interest at 12% per annum. A further $.5 million was advanced to Carpatsky under similar terms which was guaranteed by a third party. Both notes plus accrued interest were due on June 30, 1998. Since Carpatsky's default on its promissory notes, the Company has been seeking repayment by various means. The Company has reached an agreement in principle with Carpatsky to convert the promissory notes into equity in Carpatsky. Under the agreement, the Company will convert the $.7 million note into approximately 6.6 million common shares of Carpatsky with a current market value of approximately $.65 million and a warrant to acquire an additional number of common shares to be determined. The $.5 million promissory note will be transferred to the guarantor at its face value plus accrued interest.
In December 1996, the Company was issued promissory notes from the Company's officers totaling $2 million. Interest accrues on indebtedness at 8%. Principal and interest payments are due annually through December 31, 2002.
7. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
During the year ended December 31, 1995, employees of the Predecessor were covered by Torchmark's retirement plans, including a defined benefit pension plan and a defined contribution savings plan. Net periodic pension costs for the defined benefit plan were calculated on the projected unit credit actuarial cost method.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
Effective January 1, 1996, the Predecessor terminated its participation in the above plans and established a 401(k) retirement plan. During the period January 1, 1996 to September 30, 1996, the Predecessor contributed $1.3 million to the terminated plan leaving a balance of $2.1 million in related accrued pension liabilities. This accrual was reversed into income as the Company has no requirements to contribute future fundings to the terminated plan. The 401(k) retirement plan is funded by employee and Company contributions. Employees may contribute up to 12% of their salaries and the Company matches 50% of employee contributions up to 6%. The Company's contributions to this plan total $1.1 million and $.9 million for the years ended December 31, 1998 and 1997 and $.2 million and $.6 million for the periods October 1, 1996 through December 31, 1996 and January 1, 1996 through September 30, 1996, respectively. In addition, the Company established a discretionary 401(k) retirement plan. During the first quarter of the year, the Company has the option of contributing up to an additional 3% of each employee's salary for the previous year to the plan. The Company's contributions to this plan total $.6 million and $1 million for the years ended December 31, 1998 and 1997 and $.3 million and $.9 million for the periods October 1, 1996 through December 31, 1996 and January 1, 1996 through September 30, 1996, respectively. For both plans, an employee is required to have been employed a minimum of one year by the Company prior to participation. Effective January 1, 1998, the Company waived the minimum one year employment requirement for 401(k) retirement plan participation.
8. MANAGEMENT BUYOUT
On September 30, 1996, the Management Buyout occurred whereby certain members of the Company's executive management purchased the Company from Torchmark for $41 million; $25.5 million in the form of a senior subordinated note payable (See Note 12) and $15.5 million in cash. Immediately prior to the Management Buyout, the Predecessor dividended its investments in Nuevo, Gulf Canada and Bellwether and certain other assets to Torchmark (See Note 9) and received a cash contribution from Torchmark for $10.5 million. As a result of this transaction, the Company received working and other interests in oil and gas properties. Predecessor management fees related to the properties conveyed to TEAI were $1.9 million for the period January 1, 1996 through September 30, 1996. In addition, the Company received interests in certain properties in exchange for consideration of up to $7 million, which is payable solely out of production and is contingent upon the properties achieving pricing and profitability thresholds. Based upon current pricing and profitability projections, no such liability was recorded at December 31, 1998. A liability of $.3 million is recorded at December 31, 1997.
9. ACQUISITIONS AND DISPOSITIONS OF ASSETS
In December 1995, the Predecessor entered into a series of transactions which resulted in the sale of 17 million ordinary shares of Gulf Canada to an affiliate of the Predecessor's principal lender for $68 million. In connection with the transaction, the Predecessor had certain performance obligations; $36.1 million of time deposits collaterized the transaction until such obligations were satisfied. In March 1996, the performance obligations were satisfied and the Predecessor recognized a pre-tax gain of approximately $2.5 million upon the sale of the Gulf Canada stock. In September 1996, the Predecessor's remaining .9 million Gulf Canada shares were transferred to Torchmark in conjunction with the Management Buyout.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
In April 1996, the Predecessor received 1.3 million Nuevo shares at $28 per share in exchange for certain California offshore oil properties. A loss of $1.7 million was recognized on this disposition. In September 1996, these shares were transferred to Torchmark in conjunction with the Management Buyout.
In April 1997, the Company sold its interest in oil and gas properties of certain partnerships, under which the Company was a general partner and provided management services, to Bellwether, a publicly traded oil and gas company for which the Company acts as manager pursuant to a management agreement, and a third party for $18.4 million and $3 million, respectively. In addition, the Company received 150,000 shares of Bellwether common stock valued at $8.375 per share and a warrant to purchase 100,000 shares at $9.90 per share as a fee for advisory services rendered in connection with the sale. During 1997, the Company sold its interest in a gathering company to a third party for $1.8 million.
During the period January 1, 1996 through September 30, 1996, the Predecessor sold its interest in certain oil and gas properties to a third party for $16.3 million, generating a pre-tax gain of $4.9 million.
10. OTHER LONG-TERM LIABILITIES
Other long-term liabilities at December 31, 1998 and 1997 consist of the following (amounts in thousands):
11. TORCH ENERGY ROYALTY TRUST
The Company serves as sponsor and operator of a majority of the properties in which the Torch Energy Royalty Trust (the "Trust") owns a net profits interest. In connection with the formation of the Trust, the Company entered into an oil and gas purchase contract ("Purchase Contract") which expires on the termination date of the Trust, the earliest of which is January 1, 2003. Under the Purchase Contract, the Company is obligated to purchase all net production attributable to the Trust properties for indexed prices for oil and gas. Such prices are calculated monthly and are generally based on the average spot market prices of oil and gas, adjusted to reflect the terms of a hedge contract ("Hedge Contract"), which expires in the year 2000, to which the Company is a party. The Purchase Contract also provides that a minimum price of $1.70 per MMbtu will be paid by the Company for gas production. During the year ended December 31, 1998, the Company purchased 8,051 MMCF of gas and 71 Mbbls of oil at an average price of $2.06 per MCF and $11.09 per Bbl. During the year ended December 31, 1997, the Company purchased 9,085 MMCF of gas and 93 Mbbls of oil at an average of $2.13 per MCF and $16.40 per Bbl. During the periods October 1, 1996 to December 31, 1996 and
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
January 1, 1996 to September 30, 1996, the Company purchased 2,604 MMCF and 8,488 MMCF of gas, respectively, and 35 Mbbls and 109 Mbbls of oil, respectively, at an average price of $2.06 and $1.80 per MCF, respectively, and $18.17 and $17.40 per Bbl, respectively. Under the Hedge Contract, monthly quantities of gas hedged decreased from 531,167 MMbtus of gas in 1996 to 17,250 MMbtus of gas in 2000 and monthly quantities of oil hedged decrease from 6,333 Bbls in 1996 to 167 Bbls in 2000. The price received for gas under the Hedge Contract increases from $1.84 per MMbtu in 1996 to $1.89 per MMbtu in 2000. The price received for oil under the Hedge Contract increases from $19.94 per Bbl in 1996 to $20.20 per Bbl in 2000.
Additionally, the Company has purchased contracts expiring December 2001 to further limit its exposure to losses under the minimum price obligation Purchase Contract. Under these contracts, monthly quantities hedged increase from 16,482 MMbtus per day in 1996 to 16,989 MMbtus per day in 2001 with floor pricing ranging from $1.83 to $1.81 per MMbtu.
12. DEBT
SENIOR SUBORDINATED NOTE PAYABLE - AFFILIATE -
On September 30, 1996, the Company recorded TAC's $25.5 million Senior Subordinated Note (the "Note") payable to Torchmark as part of the purchase price for the Management Buyout. The Note accrues interest at 9% per annum, payable semiannually, and the principal is due and payable on September 30, 2004.
LINE OF CREDIT -
The Company maintains a $13 million credit facility (the "Credit Facility") with a bank. Interest accrues on indebtedness, at the Company's option, at the bank's prime rate (6.6% at December 31, 1998) if less than 50% of revolver borrowing base is outstanding ($5 million at December 31, 1998), prime plus .25% if 50% or more, but less than 75% of revolver borrowing base is outstanding or prime plus .50% if 75% or more of revolver borrowing base is outstanding; or the 1 year London Interbank Offered Rate ("LIBOR") (5.1% at December 31, 1998) plus 1.5% if less than 50% of revolver borrowing base is outstanding, libor plus 1.75% if 50% or more, but less than 75% of revolver borrowing base is outstanding or libor plus 2% if 75% or more of revolver borrowing base is outstanding. The Credit Facility contains, among other terms, provisions for the maintenance of certain financial ratios and restrictions on additional debt. As of December 31, 1998, the Company was not in compliance with one of its financial ratios. The Company has received a waiver on the consolidated interest coverage ratio as of December 31, 1998. Certain oil and gas properties, stock and fixed assets secure the Credit Facility which matures on September 30, 1999. At December 31, 1998 and 1997, there was no outstanding balance under the line of credit.
On July 16, 1997, TEFF entered into a $90 million credit facility the "TEFF Facility") with a bank. Ordinary interest accrues on indebtedness, at TEFF's option, at the bank's prime rate plus 0.5% (8.25% at December 31, 1998) or LIBOR plus 2.0% (7.10% at December 31, 1998) if the loans outstanding are less than or equal to the portfolio base ($20.1 million at December 31, 1998); and at the bank's prime rate plus 5.5% (13.25% at December 31, 1998) or LIBOR plus 7.0% (12.10% at December 31, 1998) of the portion of loans outstanding in excess of the portfolio base. If the outstanding balance under the TEFF Facility exceeds $75 million, then the ordinary interest rate shall be reduced by 0.5%. Principal and interest on the loan will be repaid from cash flow from TEFF's underlying investments. The amount of such repayments will vary
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
between 70% to 100% of the cash flow, depending on the ratio of portfolio base to the outstanding principal balance of the loan. The TEFF Facility contains, among other terms, provisions for the maintenance of certain financial ratios and restrictions on additional debt. All security in the investments currently owned by TEFF or hereafter acquired and proceeds thereof, secure the TEFF Facility, which matures on December 31, 2003. At December 31, 1998, the outstanding balance under the TEFF Facility was $36.3 million at a weighted average interest rate of 9.7%. At December 31, 1997 the outstanding balance under the TEFF facility was $10.6 million. In addition the principle and interest payments mentioned above, the bank will receive 50% of the remaining cash flow after deduction of such principle and interest payments (NCFI). Until such time as the NCFI payments are equal to TEFF's partners' contributions, these amounts will be considered additional principle repayments. After that time, the payments will be considered additional expense. The TEFF Facility provides that NCFI be paid through December 31, 2011 at which time the bank's right to receive NCFI shall terminate. No such interest was incurred for the years ended December 31, 1998 and 1997.
On November 14, 1997, TPC entered into a $200,000 credit facility (the "TPC Facility") with a bank. Interest accrued on indebtedness at the bank's prime rate. All accounts receivable then owned by TPC or thereafter acquired and proceeds thereof, but not the contracts themselves, secured the TPC Facility which matured on November 2, 1998. At December 31, 1997, the outstanding balance under the TPC Facility was $60,000. There is no credit facility for TPC at December 31, 1998.
13. COMMITMENTS AND CONTINGENCIES
LITIGATION -
The Company is involved in certain litigation arising out of the normal course of business, none of which, in the opinion of the Company, will have any material adverse effect on the financial position or results of operations of the Company as a whole. Certain lawsuits to which the Company was a party were assumed by Torchmark as a result of the Management Buyout.
SMGC -
SMGC has a $29 million bank loan due on June 30, 1999. This loan is guaranteed by the general partner of SMGC. TEMI has guaranteed the general partner that it will share proportionally (50%) if any payments are required by the general partner for repayment of SMGC's loan. The current financial position of SMGC would not enable it to repay the loan when due. SMGC is attempting to either renegotiate the terms of the loan or seek other financing options. While the Company does not expect to be required to perform under the TEMI guarantee, the carrying value of the Company's investment in SMGC, in the opinion of the Company, would not result in an impairment to its investment should TEMI be required to repay its portion of the loan.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
LEASE OBLIGATIONS -
Rental expense for operating leases was approximately $1.7 million, $1.7 million, $.6 million and $1.6 million for the years ended December 31, 1998 and 1997 and the periods October 1, 1996 through December 31, 1996 and January 1, 1996 through September 30, 1996, respectively. Future minimum payments under all noncancellable leases, including amounts allocable to affiliates, having initial terms of one year or more consisted of the following as of December 31, 1997 (amounts in thousands):
Operating Year Ending December 31, Leases ------------------------ ----------
1999.............................. $ 1,970 2000.............................. 1,886 2001.............................. 1,812 2002.............................. 1,980 2003.............................. 1,889 Thereafter........................ 5,690 ------- $15,227 =======
14. FINANCIAL DERIVATIVES
The Company uses futures, swap and option contracts to hedge anticipated sales and purchases for pricing commitments of natural gas and crude oil, to reduce the Company's exposure to changes in the market price of natural gas and crude oil, and to fix the price for natural gas and crude oil independently of the physical purchase or sale. Futures involves buying the underlying commodity at fixed prices. Over-the-counter swap contracts require the Company to receive or make payments based on the price of the underlying commodity and are used to manage price and location risk. The Company uses futures, swaps and options to manage margins on underlying fixed-price purchase or sales commitments for physical quantities of the underlying commodity. The Company holds one natural gas option which provides the right, but not the requirement, for the counterparty to sell natural gas to the Company at a fixed price. The Company also holds one natural gas option to limit its exposure to losses under the minimum price obligation to the "Trust" (see Note 11) risk which provides the right, but not the requirement, for the Company to sell natural gas to the counterparty at a fixed price. At December 31, 1998, the Company had natural gas basis swap agreements with broker-dealers to exchange monthly payments on notional quantities amounting to 98 million MMBTU over the ensuing 3 years. At December 31, 1998, the Company had natural gas price swap agreements with broker-dealers to exchange monthly payments on notional quantities amounting to 32 million MMBTU over the ensuing 3 years. Under the price swap agreements, the Company will realize an average price of $2.16 per MMBTU. Under a 6 Mbbl oil price swap agreement, the Company will realize a floor price of $20.17 per barrel.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
Determination of Fair Values of Financial Instruments -----------------------------------------------------
Fair value for cash, short-term investments, receivables, other assets and payables approximates carrying value. The following tables detail the carrying values and approximate fair values of the Company's other investments and derivative financial instruments at December 31, 1998 and 1997.
The Company is exposed to credit losses in the event of nonperformance by the counterparties to its derivative financial assets but has no off- balance-sheet credit risk of accounting loss. The Company anticipates, however, that counterparties will be able to fully satisfy their obligations under the contracts. Futures contracts are guaranteed settlement by the NYMEX and have nominal credit risk.
15. DEFERRED REVENUE RECOGNITION
In conjunction with the formation of the Trust and a commmission related to the Gulf Canada transaction, deferred revenue was being recognized as earned for prepaid management fees. For the Trust fees, deferred revenue was being amortized, based on estimated production presented in reserve reports, through 2003. For Gulf Canada fees, deferred revenue was being amortized over three years as the Predecessor maintained certain responsibilities under a participation agreement (See Note 9). In conjunction with the Management Buyout, Torchmark was distributed the Gulf Canada stock and assumed the responsibilities under the participation
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
agreement. No deferred revenue was recorded in conjunction with the Management Buyout. Predecessor management fees related to these properties were $2.5 million for the period January 1, 1996 through September 30, 1996.
16. SFAS 131: DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION
In June 1997, the FASB issued Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" ("SFAS 131"). SFAS 131 establishes standards for the manner public enterprises are required to report information about operating segments in annual financial statements and requires the reporting of selected information about operating segments in interim financial reports to shareholders. SFAS 131 also establishes standards for related disclosures about products and services, geographic areas, and major customers. The Company adopted SFAS 131 at December 31, 1998.
The Company has four reportable segments: service activities, the capital group, the trading group and oil and gas properties. The service activities segment provides technical and administrative services to energy companies, primarily through outsourcing arrangements. The capital group segment provides growth capital to independent oil and gas companies through TEFF, a fund formed to provide small to mid-size companies with capital for acquisition and exploitation opportunities. The trading group segment engages in various hydrocarbon marketing and trading activities. The oil and gas properties segment consists of revenue from interests the Company holds in certain oil and gas properties.
The Company's reportable segments are strategic business units that offer different services. Each business segment is managed separately based on the nature of the services provided to clients and based on the different technology and marketing strategies required by each of the segments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies (see Note 2 of the Notes to Consolidated Financial Statements). The Company evaluates performance based on profit or loss from operations. Intersegment fees are accounted for as if the fees were to third parties.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
The following tables represent reported segment profit or loss and segment assets for the years ended December 31, 1998 and 1997 and for the period October 1, 1996 through December 31, 1996 (amounts in thousands). Such information is not included for the period January 1, 1996 through September 30, 1996 as this information would be impracticable to include as a result of the Management Buyout on September 30, 1996 (see Note 8 of the Notes to Consolidated Financial Statements).
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
The following is a reconciliation of reportable segment revenues, expenditures, profit or loss, assets and equity in investees to the Company's consolidated totals for the years ended December 31, 1998 and 1997 and for the period October 1, 1996 through December 31, 1996 (amounts in thousands):
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
MAJOR CUSTOMER -
One customer accounted for 13.6% and 26% and a different customer accounted for 18.5% of the gross gas marketing revenues during the years ended December 31, 1998 and 1997 and the period October 1, 1996 through December 31, 1996, respectively. There were no customers that accounted for more than 10% of the Company's gross gas marketing revenues for the period January 1, 1996 through September 30, 1996. Revenues from two customers, Bellwether and Nuevo, totaled $25 million, $29 million and $6.6 million in service and overhead fees for the years ended December 31, 1998 and 1997 and the period October 1, 1996 through December 31, 1996, respectively. The Company does not believe that it is dependent upon any particular customer for sales of oil and gas. The management service contract with Nuevo was renegotiated and effective 1999, consists of seven separate service contracts with terms that very between one to four years. The management service agreement with Bellwether extends through the end of 2000. The loss of one or both of these customers would have a material effect on the Company.
17. SUPPLEMENTARY OIL AND GAS DATA (UNAUDITED)
OIL AND GAS PRODUCING ACTIVITIES -
Included herein is information with respect to oil and gas acquisition, exploration, development and production activities, which is based on estimates of year-end oil and gas reserve quantities and estimates of future development costs and production schedules. Reserve quantities and future production are primarily based upon reserve reports prepared by independent petroleum engineering firms of Gruy Engineering Corporation, H.J. Gruy and Associates, Inc., Ryder Scott Company, and T.J. Smith & Company, Inc. and by in-house reserve engineers. These estimates are inherently imprecise and subject to revisions from time to time.
Estimates of future net cash flows from proved reserves of gas, oil, condensate and natural gas liquids (NGL's) were made in accordance with Financial Accounting Standards Board Statement No. 69, "Disclosures about Oil and Gas Producing Activities." The estimates are based on prices in effect at year-end. Estimated future cash inflows are reduced by estimated future development and production costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Prior to 1997, tax expense was calculated by applying the existing statutory tax rates, including any known future changes, to the pre-tax net cash flows, less depreciation of the tax basis of the properties and depletion allowances applicable to the gas, oil, condensate and NGL's production. Effective in 1997, the Company is an S- Corporation for income tax purposes and has a zero effective income tax rate (See Note 2). The results of these disclosures should not be construed to represent the fair market value of the Company's oil and gas properties. A market value determination would include many additional factors including: (i) anticipated future increases or decreases in oil and gas prices and production and development costs; (ii) an allowance for return on investment; (iii) the value of additional reserves, not considered proved at the present, which may be recovered as a result of further exploration and development activities; and (iv) other business risks.
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
Costs incurred -
The following table sets forth the capitalized costs incurred in oil and gas activities for the years ended December 31, 1998, 1997 and 1996 (amounts in thousands):
CAPITALIZED COSTS RELATING TO OIL AND GAS ACTIVITIES -
The following table sets forth the capitalized costs relating to oil and gas activities and the associated accumulated depreciation, depletion and amortization (amounts in thousands):
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (AMOUNTS IN THOUSANDS) -
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
* No income tax provision is recorded in 1998 or 1997 as the Company elected subchapter S corporation status effective January 1, 1997 (See Note 2).
RESERVES-
The Company's estimated total proved and proved developed reserves of oil and gas for the years ended December 31, 1998, 1997 and 1996 are as follows:
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
DISCOUNTED FUTURE NET CASH FLOWS -
The standardized measure of discounted future net cash flows and changes therein related to proved oil and gas reserves are shown below (amounts in thousands):
* No income tax provision is recorded in 1998 or 1997 as the Company elected subchapter S corporation status effective January 1, 1997 (See Note 2).
The following are the principal sources of change in the standardized measure of discounted future net cash flows (amounts in thousands):
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF TORCH ENERGY ADVISORS INCORPORATED (Unaudited)
The following should be read in conjunction with the consolidated financial statements, and the related notes thereto, of Torch Energy Advisors Incorporated and its subsidiaries (the "Company").
DISCUSSION OF YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Revenues
The Company engages in two principal lines of business: providing technical and administrative services to energy companies, primarily through outsourcing arrangements; and providing growth capital to independent oil and gas companies. In addition, the Company also engages in various hydrocarbon marketing and trading activities and receives revenue from interests it holds in oil and gas properties, most of which were acquired in conjunction with the Management Buyout.
The Company's service activities, which include accounting and finance, information technology, oil and gas operations and engineering, hydrocarbon marketing, acquisitions and divestitures, and various administrative services, accounted for over 60% of revenues in 1998. Revenues for such service activities are received under various outsourcing and management contracts and are classified primarily as Service Fees or Overhead Fees. Service Fees include payments for management and administrative services, certain hydrocarbon marketing activities, and consulting services as well as transaction fees received for arranging or advising clients on acquisitions, divestitures or financings. The Company also receives substantial fees related to oil and gas field operations and gas plant operations, which it classifies as Overhead Fees. Overhead Fees are a combination of fees paid by clients and reimbursements received from working interest owners customarily paid to the operator of oil and gas properties.
The Company's contracts for outsourcing and management services differ from contract to contract in how the Company is paid for its services. Certain contracts contain provisions whereby the Company is paid based upon the amount of book assets and operating cash flow of its clients. Others are based upon a set fee or a pricing formula related to the activities performed. As such, Service Fees may fluctuate from year to year based on the level of activity of the Company's clients or other industry and economic factors, such as the level of oil and gas prices. The Company expects to grow Service Fees in future years by adding additional outsourcing contracts with new clients and expanding the level of activities for existing clients.
Service Fees totaled $23.1 million in 1998, down 11.2% from the 1997 figure of $26.0 million primarily due to a decrease in total assets and operating cash flow on Nuevo Energy Company ("Nuevo"). Fees were down 15.6% in 1997 from the 1996 high of $30.8 million due primarily to the $8.0 million transaction fee recorded in 1996 for arranging and advising Nuevo on its nearly $500 million purchase of Unocal's California properties.
Overhead Fees equaled $8.5 million in 1998, down from $9.0 million and $11.4 million in 1997, and 1996, respectively. The 1998 decrease is related to the sale of various non-core properties by clients. The reduction in 1997 is primarily due to the acquisition of certain oil and gas property interests in September 1996 for which the Company previously received
TORCH ENERGY ADVISORS INCORPORATED AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF TORCH ENERGY ADVISORS INCORPORATED (Unaudited)
Overhead Fees from Torchmark. The Company no longer records Overhead Fees related to its management of these properties.
The Company's principal oil and gas properties relate to production payments obtained in conjunction with the Management Buyout in September 1996. The Company's major properties are coal-seam gas fields located in Alabama and Wyoming. The Company also holds interests in gas fields in Texas and Louisiana. Oil and gas revenues for 1998 were $15.1 million, down 18.4% from 1997 oil and gas revenues of $18.5 million. This decrease is mainly attributable to 1997 including a partial year of revenues prior to the sale of certain oil and gas properties in April 1997 (See Note 9 of the Notes to Consolidated Financial Statements). Oil and gas revenues for 1997 were $18.5 million, up 13.5% from 1996 oil and gas revenues of $16.3 million. This increase is mainly attributable to the acquisition of property interests in the Management Buyout, which more than offset the sale of certain oil and gas properties in September 1996 (See Notes 8 and 9 of the Notes to Consolidated Financial Statements).
In 1997, the Company began to provide growth capital to oil and gas companies through Torch Energy Finance Fund LPI ("TEFF"), a fund formed to provide small to mid-size companies with capital for acquisition and exploitation opportunities. TEFF was formed in September 1995, but its resources were expanded in July 1997, when the Company reached an agreement with the Bank of Montreal ("BMO") to provide additional capital for TEFF. The Company records interest income from parties financed by TEFF. In 1998 and 1997, such revenues totaled $1.8 million and $.7 million, respectively.
The Company also engages in various hydrocarbon marketing and trading activities. Revenues for these activities are recorded net of the cost of goods purchased for trading purposes. Net product marketing revenues decreased to $4.4 million in 1998 from $5.3 million and $9.8 million in 1997 and 1996, respectively.
From time to time, the Company has sold interests in various oil and gas properties and securities. In March 1996, the Company sold 17 million Gulf Canada shares, generating a pre-tax gain of approximately $2.5 million. In April 1996, the Company received 1.3 million Nuevo shares in exchange for certain California offshore oil properties. A loss of $1.7 million was recognized on this disposition. In September 1996, the Company's interest in Gulf Canada and Nuevo was transferred to Torchmark in connection with the Management Buyout. In August 1996 and September 1996, the Company sold its interest in certain oil and gas properties to a third party for $16.3 million, generating a pre-tax gain of $4.9 million. In April 1997, the Company sold its interest in oil and gas properties of certain partnerships to Bellwether for $18.4 million. As a fee for advisory services rendered in connection with the sale, the Company received .15 million shares of Bellwether common stock at $8.375 per share and a warrant to purchase .1 million shares at $9.90 per share. (See Notes 1, 5 and 9 of the Notes to Consolidated Financial Statements).
Expenses
The Company includes in general and administrative expense all of the personnel and administrative costs of providing services to its clients pursuant to its outsourcing agreements, with the exception of field operating personnel, which are charged directly to the clients' operations. Because general and administrative expense includes the cost of
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client service, the level of expense recorded by the Company from year to year is subject to variability related to client activity level.
General and administrative expenses totaled $39.0 million, $37.1 million and $37.9 million in 1998, 1997 and 1996, respectively.
Oil and gas expenses for 1998 totaled $8.3 million, down 6.7% from $8.9 million in 1997. Such decrease is mainly due to 1997 including a partial year of expenses prior to the sale of certain oil and gas properties in April 1997 (see Note 9 of the Notes to Consolidated Financial Statements). The average unit production cost per Mcfe in 1998 was $1.23 as compared to an average unit production cost per Mcfe in 1997 of $1.21. Oil and gas expenses for 1997 totaled $8.9 million, up 29% from $6.9 million in 1996. Such increase is mainly attributable to the receipt of certain oil and gas properties in September 1996 (see Note 8 of the Notes to Consolidated Financial Statements). The average unit production cost per Mcfe in 1997 was $1.21 as compared to an average unit production cost per Mcfe in 1996 of $.92.
Interest expense increased by 32.1% to $3.7 million in 1998 from $2.8 million in 1997. Such increase is primarily due to additional funds advanced to TEFF by the Bank of Montreal. Interest expense increased by 75% to $2.8 million in 1997 from $1.6 million in 1996. Such increase is primarily due to 9% in interest recorded on the $25.5 million Senior Subordinated Note payable to Torchmark issued in conjunction with the Management Buyout in September 1996.
Equity in Earnings of Affiliates and Investees
Equity in earnings of affiliates and investees consists of oil and gas partnership interests and other investments including TEFF's 50% interest in TEC Resources, LLC ("TEC"). The Company recorded an equity loss of $.9 million in TEC for the year ended December 31, 1998.
Minority Interests
Effective November 1, 1996 Torch Energy Marketing, Inc. (TEMI), a wholly owned subsidiary, formed a limited liability company with an unaffiliated party to conduct gas marketing activities. TEMI acts as a manager and owns a 50% interest in this venture. As the Company effectively controls the venture, the activities are included in the financial statements with the unaffiliated parties interest reflected as minority interest.
During 1996, the Company formed two limited liability companies with an unaffiliated party to provide certain management, administrative and support services to a foreign party. The Company owned a 50% interest in both limited liability companies until March 1997 at which time the companies were sold. Prior to March 1997, the activities for these ventures were included in the financial statements with the unaffiliated parties interest reflected as minority interest.
Effective June 30, 1997, the Company purchased The Procurement Centre ("TPC") to obtain the benefit of TPC's experience and expertise in providing consulting and outsourcing services for the procurement of materials and services, inventory management, logistics and
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other administrative services. The Company owns a 75% interest in TPC and the activities are included in the financial statements with the unaffiliated parties interest reflected as minority interest.
Net Income
The foregoing activities resulted in the following net income (amounts in thousands):
LIQUIDITY AND CAPITAL RESOURCES
Net cash used in operating activities was $3.8 million for the year ended December 31, 1998. Net cash provided by operating activities was $6.8 million and $7.6 million for the years ended December 31, 1997 and 1996, respectively. In each of the years considered, operating cash flows were affected by significant changes in assets and liabilities due to the Company incurring costs, in the ordinary course of business, on behalf of its clients. The Company spent $6.5 million, $5.6 million and $14.8 million on investments in property and equipment in 1998, 1997, and 1996, respectively. In April 1997, the Company sold its interest in certain oil and gas properties of certain partnerships to Bellwether and a third party generating $18.4 and $3.0 million, respectively, in cash (See Note 9 of the Notes to Consolidated Financial Statements). In August 1996 and September 1996, the Company sold its interest in certain oil and gas properties to a third party generating $16.3 million in cash (See Note 9 of the Notes to Consolidated Financial Statements).
Financing Activities
The Company maintains a $13 million credit facility (the "Credit Facility") with a bank. Interest accrues on indebtedness, at the Company's option, at the bank's prime rate (6.6% at December 31, 1998) if less than 50% of revolver borrowing base is outstanding ($5 million at December 31, 1998), prime plus .25% if 50% or more, but less than 75% of revolver borrowing base is outstanding or prime plus .50% if 75% or more of revolver borrowing base is outstanding; or the 1 year London Interbank Offered Rate ("LIBOR") (5.1% at December 31, 1998) plus 1.5% if less than 50% of revolver borrowing base is outstanding, libor plus 1.75% if 50% or more, but less than 75% of revolver borrowing base is outstanding or libor plus 2% if 75% or more of revolver borrowing base is outstanding. The Credit Facility contains, among other terms, provisions for the maintenance of certain financial ratios and restrictions on additional debt. As of December 31, 1998, the Company was not in compliance with one of its financial ratios. The Company has received a waiver on the consolidated interest coverage ratio as of December 31, 1998. Certain oil and gas properties, stock and fixed assets secure the Credit Facility which matures on September 30, 1999. At December 31, 1998 and 1997, there was no outstanding balance under the line of credit.
On July 16, 1997, TEFF entered into a $90 million credit facility (the "TEFF Facility") with BMO. Ordinary interest accrues on indebtedness, at TEFF's option, at the bank's prime rate plus 0.5% (8.25% at December 31, 1998) or LIBOR plus 2.0% (7.10% at December 31, 1998)
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if the loans outstanding are less than or equal to the portfolio base ($20.1 million at December 31, 1998); and at the bank's prime rate plus 5.5% (13.25% at December 31, 1998) or LIBOR plus 7.0% (12.10% at December 31, 1998) of the portion of loans outstanding in excess of the portfolio base. If the outstanding balance under the TEFF Facility exceeds $75 million, then the ordinary interest rate shall be reduced by .5%. Principal and interest on the loan will be repaid from cash flow from TEFF's underlying investments. The amount of such repayments will vary from between 70% to 100% of the cash flow, depending on the ratio of portfolio base to the outstanding principal balance of the loan. The TEFF Facility contains, among other terms, provisions for the maintenance of certain financial ratios and restrictions on additional debt. All security in the investments currently owned by TEFF or hereafter acquired and proceeds thereof, secure the TEFF Facility, which matures on December 31, 2003. At December 31, 1998, the outstanding balance under the TEFF Facility was $36.3 million at a weighted average interest rate of 9.7%. At December 31, 1997, the outstanding balance under the TEFF Facility was $10.6 million. In addition to the principle and interest payments mentioned above, the bank will receive 50% of the remaining cash flow after deduction of such principle and interest payments (NCFI). Until such time as the NCFI payments are equal to TEFF's partners' contributions, these amounts will be considered additional principle repayments. After that time, the payments will be considered additional expense. The TEFF Facility provides that NCFI be paid through December 31, 2011 at which time the bank's right to receive NCFI shall terminate. No such interest was incurred for the years ended December 31, 1998 and 1997.
On November 14, 1997, TPC entered into a $200,000 credit facility (the "TPC Facility") with a bank. Interest accrued on indebtedness at the bank's prime rate. All accounts receivable currently owned by TPC or thereafter acquired and proceeds thereof, but not contracts themselves, secured the TPC Facility which matured on November 2, 1998. At December 31, 1997, the outstanding balance under the TPC Facility was $60,000.
On September 30, 1996, the Company recorded a $25.5 million Senior Subordinated Note payable to Torchmark as part of the purchase price for the Management Buyout. This note accrues interest at 9% per annum, payable semiannually, and the principal is due and payable on September 30, 2004.
The Company has an investment in Southern Missouri Gas Company, L.P. ("SMGC") which has a $29 million bank loan due on June 30, 1999. This loan is guaranteed by the general partner of SMGC. TEMI has guaranteed the general partner that it will share proportionally (50%) if any payments are required by the general partner for repayment of SMGC's loan. SMGC is planning to either renegotiate the terms of the loan or seek other financing options.
Crude Oil and Natural Gas Price Swaps
The Company uses futures, swap and option contracts to hedge anticipated sales and purchases for pricing commitments of natural gas and crude oil, to reduce the Company's exposure to changes in the market price of natural gas and crude oil, and to fix the price for natural gas and crude oil independently of the physical purchase or sale. Futures involves buying the underlying commodity at fixed prices. Over-the-counter swap contracts require
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the Company to receive or make payments based on the price of the underlying commodity and are used to manage price and location risk. The Company uses futures, swaps and options to manage margins on underlying fixed-price purchase or sales commitments for physical quantities of the underlying commodity. The Company holds one natural gas option to mitigate price risk which provides the right, but not the requirement, for the counterparty to sell natural gas to the Company at a fixed price. The Company also holds one natural gas option to limit its exposure to losses under the minimum price obligation to the "Trust" (see Note 11) risk which provides the right, but not the requirement, for the Company to sell natural gas to the counterparty at a fixed price. At December 31, 1998, the Company had natural gas basis swap agreements with broker-dealers to exchange monthly payments on notional quantities amounting to 98 million MMBTU over the ensuing 3 years. At December 31, 1998, the Company had natural gas price swap agreements with broker-dealers to exchange monthly payments on notional quantities amounting to 32 million MMBTU over the ensuing 3 years. Under the price swap agreements, the Company will realize an average price of $2.16 per MMBTU. Under a 6 Mbbl oil price swap agreement, the Company will realize a floor price of $20.17 per barrel.
Market Risk
Comodity Price Risk - The Company's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to its natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable. Pricing volatility is expected to continue. The Company periodically seeks to reduce its exposure to price volatility by hedging its productions through swaps, options and other commodity derivative instruments. The Company uses hedge accounting for these instruments, and settlements of gains or losses on these contracts are reported as a component of oil and gas revenues and operating cash flows in the period realized. Gains or losses on natural gas price swaps are expected to be offset by sales at the spot market price or to preserve the margin on existing physical contracts. A 10 percent improvement in year-end spot market prices would increase the fair value of derivative contracts in effect at December 31, 1998 by $1.9 million, while a 10 percent drop in spot prices would decrease the fair value of these instruments by $1.9 million. These agreements expose the Company to counterparty credit risk to the extent that the counterparty is unable to meet its settlement commitments to the Company.
Interest Rate Risk - The Company's exposure to changes in interest rates primarily results from short term changes in the LIBOR rates. A 10% increase in the floating LIBOR rates would have the effect of increasing interest costs to the Company by $.35 million per year.
Outlook
The Company has adopted a $10.9 million capital budget for the year ending December 31, 1999 primarily for the recompletion of certain oil and gas properties, information technology and additional investments in current affiliates. The Company believes its working capital and cash flows from operating activities will be sufficient to meet these capital commitments.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement establishes standards of accounting for and disclosures of derivative instruments and hedging activities. This statement is effective for fiscal years beginning after June 15, 1999. The Company has not yet determined the impact of this statement on the Company's financial condition or results of operations.
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Year 2000 Issues
The Year 2000 problem ("Y2K") refers to the inability of computer and other information technology systems to properly process date and time information. The problem was caused, in part, by the outdated programming practice of using two digits rather than four to represent the year in a date. The consequence of the Y2K problem is that information technology and embedded processing systems are at risk of malfunction, particularly during the transition between 1999 to 2000.
The effects of the Y2K are exacerbated by the interdependence of computer and telecommunication systems throughout the world. This interdependence also exists among the Company and its vendors, customers and business partners, as well as with government agencies.
The risks of Y2K fall into three general areas: 1) Corporate Systems, 2) Field Systems and 3) Third Party Exposure. The Company intends to address each of these areas through a readiness process that follows the steps below:
a) Planning and Awareness b) Inventory and Assessment c) Identify Potential Problems and their Business Impact d) Identify/Approve Solutions e) Test and Implement Solutions f) Contingency Planning
The Company has formed a Y2K Team comprised of representatives from senior management, exploration, exploitation, accounting, legal and internal audit. The continuing progress of this Y2K Team is reported regularly to the Company's Board of Directors. The Company is responsible for a substantial portion of its clients' information technology and field operations due to the existing contracts for outsourcing and management services. As a result, the Company and its clients have jointly developed a plan to address the Company's Y2K issues.
The estimated total costs for Y2K readiness have been nominal and it is anticipated that such costs will continue to be nominal through completion. The Company expensed $132,000 related to Y2K for the year ended December 31, 1998 and anticipates an additional $128,000 to be expensed during 1999. In addition, there have been no material capital expenditures for Y2K and there is not anticipated to be material capital expenditures as most major critical field operations do not have date sensitive equipment. Remediation and testing is scheduled to be completed by June 30, 1999.
CORPORATE SYSTEMS
1. Planning and Awareness. All employees have attended Y2K informational programs including a general discussion of what Y2K is and how it could affect the business. Employees of all levels of the organization have been asked to participate in the identification of potential Y2K risks including routine Excel and Word documents.
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Awareness of the issue is extremely high. Overall planning of the Y2K function has been delegated to the Y2K Team mentioned above.
2. Inventory and Assessment. The Company has completed an inventory of the traditional computing platforms including client/server systems, LAN systems and PC systems, as well as an inventory of all systems software and operating systems for each computing system. In addition, third party service interfaces, banking/treasury interfaces and telecommunications have been cataloged.
Assessment of component compliance (compliant, not-compliant, expected date of compliance, etc.) has been completed and included research of product information on the Internet, contacting peer group companies and accessing information that peer group companies have already found.
3. Identification. The failure to identify and correct a material Y2K problem in the Corporate Systems could result in inaccurate or untimely financial information for management decision-making or financial reporting purposes. The severity of such problems may impact the duration during which quality information is available to management. At this time, management believes that any Y2K disruptions associated with its financial and administration systems will not have a material effect on the Company.
4. Identify/Approve Solutions. Based upon the assessments of components' compliance, solutions are determined. These solutions include: 1) fix or replace the non-compliant component, 2) buy patches or replacement items, 3) develop workarounds, 4) identify alternate automated processes, 5) design manual procedures and 6) develop business continuity plans for specific items or systems.
5. Test and Implement Solutions. Since April 1998 Torch has been working on an upgrade to its accounting software and is expected to achieve full Y2K compliance in the first half of 1999. In addition, all network and desktop applications used by the Company have been inventoried and are generally Y2K compliant. No software or hardware can be purchased and placed into service after June 30, 1999 without express Y2K compliance assurance.
6. Contingency Planning. Notwithstanding the foregoing, should there be significant unanticipated disruptions in the Company's financial and administrative systems, a number of accounting processes that are currently automated will need to be performed manually. The Company is currently considering its options with respect to contingency arrangements for temporary staffing to accommodate such situations.
FIELD SYSTEMS
1. Planning and Awareness. The Company's Y2K program has involved all levels of management of field and facility assets from production foremen and higher. Employees at all levels of the organization have been asked to participate in the identification of potential Y2K risk, which might otherwise go unnoticed by higher level employees and directors, and as a result, awareness of the issue is high.
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2. Inventory and Assessment. This step entailed locating all embedded chip technology used in the field operations including safety systems, measurement devices, overflow valves, SCADA systems and other field processes that are date-or-time-sensitive. During the assessment stage a list of assets to be tested was assembled. Consideration was given to 1) issues of health and safety, 2) environmental concerns, 3) economic factors and 4) other business risks as appropriate. Vendors and manufacturers have been contacted as well as product research through the Internet and the use of peer group company shared information. To date, the majority of embedded components researched have been deemed either date-insensitive or Y2K compliant. However, the complexity of embedded systems is such that a small minority of non-compliant components, even a single non-compliant component, can corrupt an entire system. Now that the component level evaluation is substantially complete, a broader evaluation at the system level has commenced. The Company anticipates that the system level evaluation will be completed by the end of the second quarter 1999.
3. Identification. The failure to identify and correct a material Y2K problem could result in outcomes ranging from errors in data reporting to curtailments or shutdowns in production. The Company is actively engaged in a program to prioritize the remediation of embedded components and systems which are either known to be Y2K non-compliant or which have higher risk of Y2K failures, and to further prioritize remediation targets by the anticipated financial impact of any such failures on the Company. To assist in this effort, the Company has retained consultants who are knowledgeable and experienced in the assessment of Y2K issues impacting field operations. The Company intends to give extremely high priority to the remediation of any situation that impacts employee health and safety or environmental security. The cost of the assessment is not expected to be material to the Company's financial results. At this time management is unable to express any degree of confidence that there will not be material production disruptions associated with Y2K non-compliance. Depending on the magnitude of any such disruptions and the time required to correct them, such failures could materially and adversely impact the Company's results of operations, liquidity and financial condition.
4. Identify/Approve Solutions. Based upon the assessment of field systems, regarding compliance or non-compliance, solutions are determined. These potential solutions include 1) fix or replace non-compliant items, 2) buy patches or replacement items, 3) develop workarounds, 4) identify alternative automated processes, 5) design manual procedures and 6) develop business continuity plans for specific items or systems.
5. Test and Implement Solutions. Once identified, assessed and prioritized, the Company intends to test, upgrade and certify those embedded components and systems in field process control units deemed to pose the greatest risk of significant non-compliance. It is important to note that in some circumstances, the procedures used to test embedded components for Y2K compliance themselves pose a risk of damaging the component or corrupting the system. Accordingly, there may be situations in which a decision not to test may be deemed the most prudent.
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The Company does not expect the cost of testing and upgrading its embedded chips to be material due to the number of components and the low cost of such components. If this assumption is incorrect, the Company may incur material costs in connection with testing and remedying Y2K problems. In addition, if the Company is not successful and ultimately experiences Y2K related failures, the costs attributable to lost production, damages to facilities and environmental damages may be material. The effort to address the Y2K situation is dynamic and may likely not be fully completed by December 31, 1999.
6. Contingency Planning. Should material production disruptions occur as a result of Y2K failures in the field operations, the Company's operating cash flow will be impacted. This contingency is being factored into deliberations on capital budgeting, liquidity and capital adequacy. It is management's intention to maintain adequate financial flexibility to sustain the Company during any such period of cash flow disruption.
THIRD PARTY EXPOSURES
1. Planning and Awareness. The Company has been involved in informational programs with its employees who have significant interaction with outside vendors, customers and business partners of the Company. All levels of employees in the organization have been asked to participate in the identification of potential third party Y2K risk, which might otherwise go unnoticed by higher level employees and directors of the Company, and as a result, awareness of the issue is considered high.
2. Inventory and Assessment. Surveys of general Y2K readiness have been sent to all vendors, customers and business partners of the Company. An assessment is made regarding the priority of risk associated with each third party, and how the third party's level of compliance directly affects day-to-day business. The Company's most critical customers are outside operators of wells, gas plants, refineries, natural gas marketers and pipelines.
3. Identification. Refineries are extremely complex operations containing hundreds or thousands of computerized processes. The failure on the part of a refinery customer to identify and correct a material Y2K problem could result in material disruptions in the sale of the production to that refinery. In many cases, affected production may not be easily shifted to other markets, and the result can range from reduced realizations on crude oil produced, curtailed production or even shut-in production. Failures of natural gas marketers and the pipelines that connect production to markets may have similar effects. Although the Company has made inquiries to key third parties on the subject of Y2K readiness and will continue to do so, it has no ability to require responses to such inquiries or to independently verify their accuracy. Accordingly, management is unable to express any degree of confidence that there will not be material production disruptions associated with third party Y2K non-compliance. Depending on the magnitude of any such disruptions and the time required to correct them, such failures could materially and adversely impact the Company's results of operations, liquidity and financial condition.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF TORCH ENERGY ADVISORS INCORPORATED (Unaudited)
Other significant concerns include the integrity of global telecommunication systems, the readiness of commercial banks to execute electronic fund transfers and of the ability of the financial community to maintain an orderly market.
4. Identify/Approve Solutions. By prioritizing the various third party risks mentioned above, a list of most critical third party vendor, customer and business partners has been determined. By cross-referencing the results of the Y2K readiness survey with the Company's priority list of third parties solutions can be determined. These may involve field and/or office visits and more detailed meetings to access the third party's Y2K compliance.
5. Test and Implement Solutions. Where the Company perceives significant risk of Y2K non-compliance that may have a material impact on the Company, and where the relationship between the Company and a vendor, customer or business partner permits, joint testing may be undertaken during 1999. Joint testing would occur following upgrades and other remediation to hardware, software and communications links, as applicable, with the intent of determining that the remediated system being tested will perform as expected after December 31, 1999.
6. Contingency Planning. Should material production disruptions occur as a result of Y2K failures of third parties, the Company's operating cash flow will be impacted. This contingency is being factored into deliberations on capital budgeting, liquidity and capital adequacy. It is management's intention to maintain adequate financial flexibility to sustain the Company during any such period of cash flow disruption.