ITEM 1. BUSINESS
GENERAL
Continental Natural Gas, Inc. (herein "CNG" or the "Company") is an independent mid-stream energy company engaged in the purchasing, gathering, treating, processing and marketing of natural gas and natural gas liquids (NGLs). The Company, through its direct and indirect subsidiaries, owns and operates approximately 2,000 miles of natural gas gathering pipelines and interests in six natural gas processing plants located in Texas and Oklahoma. CNG's gathering lines have a combined throughput capacity of 550 MMcf/d, while CNG's processing plants have a combined NGL production capacity of 1,400 Mgal/d. CNG provides essential services to natural gas producers in the area of its gathering systems and plants by (i) connecting the producers' wells to the Company's gathering systems, (ii) treating the producers' natural gas to ensure that it meets pipeline specifications, (iii) transporting the natural gas from the wellhead to CNG's processing plants where NGLs are extracted from the natural gas stream and (iv) providing access for the natural gas and NGLs to various markets in the United States. The Company markets off-system gas, as well as on-system gas, to utilities, end-users, other marketers and pipeline affiliates.
Through 1990, the Company's activities were primarily limited to marketing of off-system gas. Concurrent with the evolving deregulation of the natural gas industry, the Company began to acquire natural gas gathering systems and processing plants to complement its marketing business. Since 1990, the Company has completed approximately $118 million of acquisitions and system expansion projects. During 1997, CNG's average gathering throughput was 113 MMcf/d and average processing plant throughput was 140 MMcf/d, compared to 1996 when CNG's average gathering throughput was 79 MMcf/d and average processing plant throughput was 129 MMcf/d. The Company's NGL production for 1997 averaged 349 Mgal/d, compared to 1996 NGL production averaging 264 Mgal/d. Over the three years ended December 31, 1997, the Company's daily natural gas throughput has increased 102%. The Company's EBITDA (as defined in Definitions) was $7.7 million, $9.5 million and $5.4 million for the years ended 1997, 1996 and 1995 respectively.
At the beginning of 1997, the Company's principal assets were located in the Panhandle Area, which is a major natural gas producing area with significant long-lived natural gas reserves. These assets consisted of: (i) the Beaver Plant and Beaver Gathering System, (ii) the Mocane Plant and (iii) approximately 800 miles of gas gathering lines (the "Texas Gathering Assets") located throughout the Texas panhandle. Consistent with its business strategy to make investments which complement its existing operations and to expand into new strategic areas, during 1997 the Company completed approximately $57.0 million in acquisitions and capital expansions. These acquisitions included purchase and upgrade of the Spearman Plant located in Ochiltree County, Texas, purchase of approximately a 56% interest in the Laverne Gas Processing Plant located in Harper County, Oklahoma and purchase of Taurus Energy Corp. (with assets consisting of 761 miles of gathering systems and two processing plants located in north central Texas) and acquisition of the Beaver-Harper Gathering System located in Beaver and Harper Counties, Oklahoma. Acquisition of Taurus Energy Corp., with assets located in north central Texas, added a new geographic area to CNG's gathering and processing operations. Thus far in 1998, the Company has acquired interests in four additional gathering systems located principally in southeastern Oklahoma. See -- DEVELOPMENT OF THE BUSINESS (INCLUDING RECENT DEVELOPMENTS).
Although the Company's principal growth in recent years has been derived from its gathering and processing operations, the Company's sale of off-system gas, which does not enter its gathering or processing facilities, remains a significant portion of its business. In 1997, revenue from the sale of off-system gas accounted for approximately 61% of the Company's total operating revenue. This off-system gas was purchased from over 70 producers and transported via 18 interstate and intrastate pipelines during 1997.
DEFINITIONS
The definitions set forth below apply to the terms in this Annual Report on Form 10-K:
"Bcf" means billion cubic feet of natural gas.
"Beaver Gathering System" means the Company's natural gas gathering system located in Beaver County, Oklahoma which gathers natural gas for delivery to the Beaver Plant.
"Beaver Plant or Beaver" means the Company's natural gas processing plant located in Beaver County, Oklahoma which is directly connected to the Beaver Gathering System.
"Capacity Release" means firm transportation which the Company has acquired by purchase or assignment from another party (typically a utility company) on a particular pipeline.
"CNG Market Area" means various of the Company's markets for natural gas and NGLs located in the Midwestern, Mid-Continent, Rocky Mountain and Southern Texas regions of the United States.
"EBITDA" represents operating income plus, depreciation, depletion and amortization. It should not be considered in isolation or as a substitute for net income as a measure of the Company's operating results or to cash flows from operating activities (determined in accordance with generally accepted accounting principles) as a measure of liquidity. Not all companies calculate EBITDA using the same methods; therefore, the Company believes that EBITDA is a measure commonly reported and widely used by analysts, investors and other interested parties in the natural gas industry and understands that it is used by such persons as one measure of a company's historical ability to service its debt.
"EPA" means the Environmental Protection Agency.
"Extraction" means removing liquid and liquefiable hydrocarbons (NGLs) from natural gas.
"FERC" means the Federal Energy Regulatory Commission.
"Firm transportation" means the obligation of a pipeline to transport natural gas without curtailment or reduction up to the quantity which the pipeline has committed to transport under the contract with its customer. Under firm transportation, the pipeline reserves sufficient capacity on its pipelines to satisfy the transportation requirements of all firm transportation customers without curtailment (except for curtailment which may result due to acts of God or similar occurrences).
"Fractionation" is the process by which the NGL stream is subjected to controlled temperatures, causing the NGLs to separate, or fractionate, into the separate NGL products of ethane, propane, butane, isobutane and natural gas.
"Fuel and shrinkage" is the heating value of the natural gas extracted in the form of NGLs or consumed as fuel during processing.
"Hamlin Gathering System" means the Company's natural gas gathering system located in Cottle, Fisher, Haskell, Jones, Mitchell, Nolan, Stonewall and Taylor Counties, Texas.
"Hamlin Plant" means the Company's natural gas processing plant located in Fisher County, Texas.
"Interruptible transportation" means the obligation of a pipeline to transport natural gas on a "first come -- first serve" basis after the pipeline has satisfied all of its firm transportation obligations.
"Laverne Plant" means the natural gas processing plant operated by the Company which is located in Harper County, Oklahoma. The Company owns approximately a 56% interest in the Laverne Plant.
"Mcf" means thousand cubic feet of natural gas.
"Mgal/d" means thousand gallons per day.
"MMcf" means million cubic feet of natural gas.
"MMcf/d" or "MMcf per day" means million cubic feet per day.
"Mocane Plant or Mocane" means the Company's natural gas processing plant located in Beaver County, Oklahoma which is not directly connected to the Beaver Gathering System.
"NGLs" means the liquids which are extracted from natural gas which include ethane, propane, butane, isobutane and natural gasoline.
"Off-system gas" means the natural gas, which the Company purchases from time to time for resale to its customers which is neither gathered nor processed by the Company.
"On-system gas" means the natural gas which is gathered or processed by the Company.
"Processing" includes treatment, extraction and fractionation.
"Panhandle Area" means the panhandle region of Oklahoma and Texas, where the Company's gathering and processing assets are located.
"Reserves" means proven/producing natural gas reserves from wells whose production is processed and/ or gathered at the Company's plants and/or pipeline systems.
"Spearman Plant" means the Company's natural gas processing plant located in Ochiltree County, Texas.
"Shackleford Gathering System" means the Company's natural gas gathering system located in Callahan, Shackleford, Stephens and Throckmorton Counties, Texas.
"Shackleford Plant" means the Company's natural gas processing plant located in Callahan County, Texas.
"Texas Gathering Assets" means the natural gas gathering assets located in various counties in the panhandle of Texas and Oklahoma which were acquired by the Company from subsidiaries of Enron Corporation.
"Treatment" refers to the removal of water vapor, solids and other contaminants, such as hydrogen sulfide or carbon dioxide, contained in the natural gas stream that would interfere with pipeline transportation or marketing of the natural gas to consumers.
DEVELOPMENT OF THE BUSINESS (INCLUDING RECENT DEVELOPMENTS)
Consistent with its business strategy to make investments which complement its existing operations and to expand into new strategic areas, the Company completed approximately $57.0 million in acquisitions and capital expansions in 1997. In addition, the Company achieved increases in the volume of off-system gas which it markets and increased its margins for the sale of NGLs. Although revenues from the marketing of electricity have not yet been generated, the Company has continued its efforts to develop an infrastructure and establish a presence in the electricity marketing industry.
ACQUISITIONS
Beaver-Harper System Acquisition. In December 1997, the Company acquired the Beaver-Harper Gathering System from Vintage Petroleum, Inc. for a purchase price of $2.35 million. The Beaver-Harper Gathering System consists of approximately 90 miles of gathering lines and four natural gas compressors (three of which are leased by the Company and one of which is owned by the Company) with a total of 2000 horsepower. Current throughput on the Beaver-Harper Gathering System is approximately 5.7 MMcf/d and total system capacity is approximately 15 MMcf/d. The Beaver-Harper Gathering System is connected to the Company's Beaver Gathering System and gas gathered on the system has historically and will continue to be delivered to the Company's Beaver Plant for processing. Acquisition of the Beaver-Harper System was undertaken, in part, to insure that the natural gas delivered into the Beaver-Harper Gathering System would remain available for processing in the Company's Beaver Plant.
Taurus Acquisition. In November 1997, the Company acquired Taurus Energy Corp. ("Taurus") under an Agreement and Plan of Merger for a purchase price of $42 million. Prior to acquisition by the CNG, Taurus Energy Corp. was a wholly-owned subsidiary of Coda Energy, Inc.
In general, Taurus's activities were similar to those conducted by the CNG in the Panhandle Area and consist of the purchase, gathering and processing of natural gas -- the Company will continue such activities under the name of Continental/Taurus Energy Company, L.P. The assets held by Taurus consist, generally, of two separate processing plants, gathering systems and related contracts covering areas in north central Texas -- one system, commonly known as the Hamlin processing plant and gathering system, is located in portions of Cottle, Fisher, Haskell, Jones, Mitchell, Nolan, Stonewall and Taylor Counties, Texas, and the other system, commonly known as the Shackleford plant and gathering system, is located in portions of Callahan, Shackleford, Stephens and Throckmorton Counties, Texas.
The Shackleford Gas Gathering System, consisting of approximately 250 miles of 3" to 10" gathering lines and 21 field compressors (including 5 rental units) totaling over 4500 horsepower, collects natural gas from approximately 250 wells. The Shackleford Plant is a refrigerated lean oil absorption plant located near Putnam, Texas with a throughput capacity of approximately 30 MMcf/d. Three compressors, having approximately 1600 total horsepower, are located at the Shackleford Plant. The Hamlin Gathering System collects natural gas from approximately 450 wells utilizing 500 miles of 2" to 16" gathering lines and 12 field compressors having a total or approximately 3000 horsepower. The Hamlin Plant has a total design capacity of 20 MMcf/d through the use of a propane refrigeration plant, a cryogenic plant and 9 compressors having a total horsepower of approximately 5300. Together the Shackleford and Hamlin Plants are capable of extracting 290 Mgal/d of NGLs.
Approximately 80% of the natural gas delivered to the Shackleford Plant and a majority of the natural gas delivered to the Hamlin Plant is dedicated under "percentage of proceeds" contracts. See -- DESCRIPTION OF THE BUSINESS, Gathering and Processing, Purchasing.
In order to close on the Taurus acquisition, CNG entered into an Amended and Restated Loan Agreement (the "Amended Loan Agreement") with ING Capital Corp. Under the terms of the Amended Loan Agreement, CNG's term loan facility was increased from $39 million to $75 million, while CNG's revolving loan facility remained at $25 million. Proceeds of the term loan facility were used as follows: $42 million as the purchase price in connection with the Taurus acquisition; $30.26 million to refinance outstanding amounts under CNG's existing credit facility and $2.74 for general corporate purposes (including working capital expenses in relation to the Amended Loan Agreement). See also -- Item 7, MANAGEMENT DISCUSSION AND ANALYSIS, Liquidity and Capital Resources, Financing Facilities.
Spearman Acquisition. In July 1997, the Company completed the acquisition of the Spearman Plant located in Ochiltree County, Texas, for a purchase price of $1.05 million. The Company also expended approximately $1.4 million to upgrade the Spearman Plant during the third and fourth quarter of 1997. The Spearman Plant was originally constructed in 1959. The current maximum throughput of the Spearman Plant is estimated to be approximately 40 MMcf/d utilizing a refrigerated lean-oil absorption process, producing approximately 68 Mgal/d of NGLs. The Company has utilized the Spearman Plant for processing natural gas the Company gathers through its nearby Spearman gathering system which comprises part of the Texas Gathering Assets.
The Company uses the Spearman Plant to extract NGLs from the natural gas which is gathered on the Spearman gathering system prior to delivery of such gas to interstate pipelines. From October through the end of 1997, the Spearman Plant averaged 39 MMcf/d of gas throughput and 62 Mgal/d of NGL production.
Laverne Acquisition. In July 1997, the Company purchased from Conoco Inc. and its affiliate a 36% interest in the Laverne Plant for a purchase price of $2.9 million. Prior to the acquisition from Conoco and its affiliate, the Company had acquired approximately 17% of the plant for $1.4 million and presently owns approximately 56% of the Laverne Plant. The Company's interest in the Laverne Plant is held by Continental Laverne Gas Processing, L.L.C., an Oklahoma limited liability company which was formed in May 1997, for the purpose of acquiring interests in the Laverne Plant.
The Laverne Plant consists of a 200 MMcf/d cryogenic gas processing facility, complete with liquid fractionation capability and above-ground storage. The Laverne Plant straddles GPM Gas Corporation's Laverne natural gas gathering system. Natural gas production feeding the Laverne Plant originates from the Mocane-Laverne field. The plant is located approximately twenty-one (21) miles east of the Beaver Plant. For the period August through December 1997 throughput at the Laverne Plant averaged approximately 51 MMcf/d, yielding approximately 108 Mgal/d of NGLs.
NATURAL GAS, NGL AND ELECTRICITY MARKETING
Natural Gas Marketing. During the year ended December 31, 1997, the Company delivered natural gas to approximately 150 customers in 12 states. In 1997, the Company delivered an average of approximately 289 MMcf/d and had natural gas sales revenues of approximately $290 million. This compares to an average daily volume in 1996 of 224 MMcf/d and natural gas sales revenues of approximately $209 million.
NGL Marketing. During 1997 the Company hired a liquids marketer to manage marketing of the NGLs produced at the Company's plants. As a result of these marketing efforts, the number of customers for the Company's NGLs increased from 2 at the beginning of 1997 to approximately 30 as of December 31, 1997. Management believes that the increase in the Company's NGL customer base has greatly enhanced marketing flexibility for the sale of NGLs and has increased the sales price which the Company receives for its NGLs.
During 1997, the Company sold an average of approximately 387 Mgal/d of NGLs and had NGL sales revenues of approximately $46 million for the year. This compares to an average daily volume in 1996 of 265 Mgal/d and NGL sales revenues of approximately $35 million.
Electricity Marketing. In October 1997, the Company hired an electricity marketer with the intent of developing the infrastructure necessary to engage in the wholesale and retail trading of electricity. During the fourth quarter of 1997, the Company undertook numerous activities in order to develop the necessary infrastructure, including: (i) making the necessary contacts with other electricity marketing companies, (ii) negotiating the terms of various "blanket" purchase, sale and exchange agreements; and (iii) submitting credit applications to various companies with which the Company expects to do business.
The Company anticipates making its first wholesale purchases and sales of electricity in the second or third quarter of 1998. Retail sales of electricity cannot be made until such activities are permitted under applicable state regulations.
RECENT DEVELOPMENTS
Gothic Acquisition. On January 23, 1998, the Company entered into a binding agreement with Gothic Energy Corporation to acquire interests in 4 natural gas gathering systems and Senior Redeemable Preferred Stock, Series A of Gothic. The purchase price under the agreement is $12 million, which includes $6 million of Gothic's Senior Redeemable Preferred Stock, Series A. Gothic is traded on the NASDAQ under the symbol "GOTH."
In January 1998, CNG closed on its purchase of an interest in one of Gothic's gathering systems. In this transaction, CNG purchased all of the issued and outstanding stock of Gothic Gas Corporation which indirectly owns an undivided 55.23% interest in the Sycamore gathering system. In March 1998, the Company acquired interests in the three remaining gathering systems -- being an undivided 1/3 interest in the Choctaw Thrust gathering system, all interest in the Panola gathering system and all interest in the Northeast Wilburton gathering system. The Company's interest in the Choctaw Thrust gathering system is subject to a preferential right to purchase which expires in April 1998.
Together the Gothic Systems are comprised of approximately 80 miles of pipeline and collect natural gas from approximately 90 wells and redeliver such natural gas into various interstate and intrastate pipelines. In connection with acquisition of the Gothic Systems, the Company and Gothic entered into various natural gas purchase arrangements.
CIG Settlement. In February 1998, the Company announced a settlement with Colorado Interstate Gas Company. The settlement resulted in dismissal of a lawsuit pending in the District Court of El Paso County, Colorado, Case No. 93-CV-1894. See -- Item 3, LEGAL PROCEEDINGS.
DESCRIPTION OF THE BUSINESS
GATHERING AND PROCESSING
The Company's natural gas gathering and processing activities include contracting to purchase natural gas supplies, operating and maintaining a system of gathering pipelines that connect these natural gas supplies to transport lines or natural gas processing plants and operating and maintaining processing plants linked to its gathering systems.
Purchasing. In 1997, the Company purchased natural gas from over 200 suppliers, ranging from major producers to small independent companies. With the acquisition of Taurus, the Company expanded its purchasing activities to north central Texas. The Company's natural gas throughput in its gathering systems and processing plants is generally supplied by producers pursuant to long-term contracts (i.e., contracts in excess of one year). In arranging new purchase contracts, the Company submits to the producer an offer to purchase the natural gas from the prospective acreage. The producer typically evaluates various offers based upon the purchase price and other contract provisions, line pressure, the time period required for well connection and the gathering company's reputation for service and reliable marketing. The Company believes that its flexibility in negotiating contract terms, prompt connection of wells, reliable performance under its contracts and strong overall relationships with producers provide it with an important competitive advantage in the acquisition of new natural gas supplies.
The terms of the Company's natural gas purchase contracts are determined based upon negotiations with producers, competition and the desire to maximize the value to be realized from its gathering and processing systems. The Company purchases a majority of its on-system gas supplies pursuant to long-term contracts that require producers to dedicate all natural gas produced from designated properties. The pricing of these producer contracts is generally not fixed, however, and follows the market price.
The Company's on-system gas contracts with producers may be classified as (i) processing contracts, (ii) purchase contracts or (iii) gathering contracts. On average in 1997, the Company contracted approximately 15% of its natural gas volumes pursuant to processing contracts, approximately 50% pursuant to purchase contracts (sometimes with processing included) and approximately 35% under gathering contracts (sometimes with processing included).
Under processing contracts, the Company agrees to process the raw natural gas from the wells on behalf of the producers and to allocate the NGLs recovered and the residue natural gas to each well connected to its gathering systems. The Company retains a percentage of the value of the NGLs extracted net of plant fuel and NGL shrinkage. The producer bears a share of the cost of NGL extraction in return for a share of NGL revenue. The Company's processing contracts are typically of two types -- "keep whole" contracts and "percentage of proceeds" contracts. Under a "keep whole" arrangement, the Company must reimburse the producer for fuel and shrinkage. Under a percentage of proceeds contract, the processor does not reimburse the producer for fuel and shrinkage. From the processor's share of proceeds, it is obligated to pay its operating costs for its plants and gathering systems. The Company's processing contracts in the Panhandle Area are typically on a "keep-whole" basis, while the Company's arrangements with respect to the Taurus acquisition are typically "percentage of proceeds" contracts.
Under a purchase contract, the Company generally pays for natural gas received at the wellhead or at some other delivery point. The Company then usually resells the natural gas and NGLs after processing the
natural gas for its own account at its processing facilities. The Company derives a gross margin equal to the difference between sale proceeds of both the NGLs and the residue natural gas and the cost of the natural gas purchased at the wellhead.
In (i) gas purchase, (ii) gathering contracts with processing and (iii) keep-whole processing contracts, operating margins are enhanced by maximizing the value of the NGLs extracted from the natural gas stream and minimizing the operating costs which the Company incurs during processing and gathering. Margins under these contracts can be affected by decreases or increases in NGL prices or increases or decreases in natural gas prices.
Gathering. Under gathering contracts, the Company typically gathers natural gas on behalf of a producer from various wellheads for redelivery to specific pipeline interconnection or redelivery points. The producer is charged a gathering fee plus a fuel charge for such gathering services. Generally, the producer will pay the Company a discounted gathering fee in exchange for the Company retaining some or all of the extracted NGLs.
Natural gas from the Company's Texas Gathering Assets is transported to the Company's processing plants located in the Panhandle Area through interstate pipelines, primarily Northern Natural Gas Pipeline ("NNG") and Transwestern Pipeline ("TW"). Approximately 65% of the natural gas transported by NNG and TW for the Company is subject to firm transportation agreements which obligate the pipelines to give priority to the transportation of the Company's natural gas. The Beaver Gathering System delivers on-system gas to the Company's Beaver and Mocane Plants and the Hamlin and Shackleford Gathering Systems deliver on-system gas to the Company's Hamlin and Shackleford Plants, respectively. In addition, natural gas may be transported to the Company's processing plants through interruptible transportation agreements with pipelines and third-party natural gas gatherers. Interruptible transportation agreements require the pipelines to deliver natural gas on a "first-come, first-serve" basis after satisfaction of commitments under firm transportation agreements.
Processing. The Company owns interests in and operates six natural gas processing plants. These processing plants complement the Company's gathering operations by enabling the Company to offer to its producers the option of wellhead purchase or processing contracts. The sale of NGLs contributes to the overall earnings of the Company because of the added value from NGL extraction. In addition, natural gas processing complements and diversifies the earnings derived from natural gas sales. The Company's processing plants at present have excess capacity which, if increased natural gas supplies can be obtained, can be utilized to increase Company revenues with a minimal increase in operating costs. Management of the Company will attempt to obtain the natural gas supplies necessary to utilize such excess capacity and benefit by the resultant efficiency.
The Company's processing plants extract NGLs and remove water vapor, solids and other contaminants contained in the natural gas stream. Each of these plants is capable of recovering substantially all isobutane, normal butane and natural gasoline components from the natural gas stream. Propane and ethane are the Company's two primary NGL products.
The location of the Company's processing plants provide access to nearby markets for the sale of NGLs, thus reducing transportation costs. The Company believes its processing plants provide it with a competitive advantage in the acquisition of natural gas supplies. Much of the Company's natural gas processing capacity has ethane rejection capability, which allows the Company to optimize margins if ethane prices decline significantly relative to natural gas prices. The Company's Beaver and Mocane processing plants are interconnected.
Beaver Plant. The Beaver Plant was built in 1961. When acquired by CNG in 1990, the Beaver Plant consisted of a 40 MMcf/d design capacity refrigeration plant, capable of extracting approximately 40% of the propane, nearly all of the butane and gasoline, and virtually none of the ethane from the inlet natural gas stream. Average throughput was less than 10 MMcf/d prior to the Company's acquisition of the facility. In 1992, the Company purchased and relocated a 65 MMcf/d cryogenic processing plant to the Beaver Plant.
The added facility chills natural gas to -155 degrees Fahrenheit and separates the natural gas from the NGLs condensed at the low temperatures. The Beaver cryogenic processing plant currently recovers 95% of the propane, 80% of the ethane and nearly 100% of the heavier butane and natural gasoline from the natural gas stream.
The design of the Beaver Plant allows for relatively fuel-efficient, low-pollution extraction of a high volume of NGLs from natural gas. The combined cryogenic and refrigeration facilities have a processing capacity of 105 MMcf/d of inlet natural gas and 215 Mgal/d of extracted NGLs. The Beaver Plant's average throughput for 1997 was 70 MMcf/d yielding 200 Mgal/d of NGLs. The Beaver Plant and gathering system have over 24,000 horsepower of gathering and processing compression capability. The cryogenic facilities typically run at full capacity while the refrigeration unit is typically idle.
The NGLs produced consist of a mixture (commonly known as "Y-Grade") of ethane, propane, isobutane, normal butane and natural gasoline. The Y-Grade mixture is delivered into an NGL pipeline operated by an affiliate of Koch Industries, Inc. which is connected to the Beaver Plant.
Mocane Plant. The Mocane Plant was built in 1959, was partially updated in 1985 and was acquired by CNG in early 1995. The Mocane Plant is located about 13 miles northwest of the Beaver Plant. The Mocane Plant has a demonstrated inlet natural gas capacity of 200 MMcf/d and is designed to extract up to 280 Mgal/d of NGLs. The Mocane Plant's average throughput for March 1997 was 65 MMcf/d, yielding 101 Mgal/d of NGLs. Prior to the Company's acquisition of the Mocane Plant in early 1995, recent historical throughput averaged less than 40 MMcf/d.
The Mocane Plant uses refrigeration and lean oil absorption processes to extract NGLs. Propane recovery is approximately 85% and ethane recovery is approximately 25% with nearly 100% of the heavier butane and natural gasoline being recovered. The Mocane Plant has over 7,500 horsepower of compression used in the NGL extraction process.
Y-Grade produced at the Mocane Plant may be sold and delivered to NGL pipelines operated by affiliates of Koch Industries, Inc. and Mapco, Inc. Alternatively, the Company may fractionate the NGLs into the various components at its on-site fractionation facility and deliver these NGLs to purchasers via truck racks. The Mocane Plant has fractionation capacity of 281 Mgal/d. The Mocane facility can produce propane, isobutane, normal butane, natural gasoline and a mixture of ethane and propane.
Spearman Plant. The Spearman Plant located in Ochiltree County, Texas, was built in 1959 and acquired by the Company in July 1997.
The current maximum throughput of the Spearman Plant is estimated to be approximately 40 MMcf/d utilizing a refrigerated lean-oil absorption process, producing approximately 68 Mgal/d of NGLs. During the period October through December, 1997, the Company processed approximately 39 MMcf/d at the Spearman Plant and recovered approximately 62 Mgal/d of NGLs.
At the Spearman Plant, propane recovery is approximately 70% with nearly 100% of the heavier butane and natural gasoline being recovered. The Spearman Plant does not recover ethane. The Spearman Plant has over 900 horsepower of compression used in the NGL extraction process. Y-Grade produced at the Spearman Plant is sold and delivered in an NGL pipeline operated by an affiliate of Koch Industries, Inc.
Laverne Plant. The Laverne Plant consists of a 200 MMcf/d cryogenic gas processing facility, complete with liquid fractionation capability and above-ground storage. The plant is located approximately twenty-one (21) miles east of the Beaver Plant. During the period August through December 1997, the Laverne Plant processed approximately 51 MMcf/d and recovered approximately 108 Mgal/d of NGLs.
The Laverne Plant is a cryogenic gas processing facility complete with liquid fractionation capability and above-ground storage. Propane recovery is approximately 95% and ethane recovery is approximately 60% under current conditions (the plant is capable of recovering 85% ethane at optimum conditions) with nearly 100% of the heavier butane and natural gasoline being recovered. The Laverne Plant has over 12,400 horsepower of compression used in the NGL extraction process.
Y-Grade produced at the Laverne Plant may be sold and delivered to an NGL pipeline operated by an affiliate of Koch Industries, Inc. Alternatively, the Company may fractionate the NGLs into the various components at the on-site fractionation facility and deliver these NGLs to purchasers via truck racks. The Laverne Plant has fractionation capacity of 540 Mgal/d. The Laverne fractionation facility can produce propane, isobutane, normal butane, natural gasoline and a mixture of ethane and propane.
Shackleford and Hamlin Plants. The Shackleford Plant is a 30 MMcf/D capacity refrigerated lean oil absorption plant located near Putnam, Texas. The Hamlin Plant has a capacity of 20 MMcf/D utilizing a propane refrigeration plant and a cryogenic plant and is located near Hamlin, Texas. Together the Shackleford and Hamlin Plants are capable of extracting 290 Mgal/d of NGLs.
At the Shackleford Plant propane recovery is approximately 85% and ethane recovery is approximately 20% with nearly 100% of the heavier butane and natural gasoline being recovered. The Shackleford Plant has over 340 horsepower of compression used in the NGL extraction process. At the Hamlin Plant, propane recovery is approximately 98%, ethane recovery is approximately 85% with nearly 100% recovery of the heavier butanes and natural gasoline. The Hamlin Plant has over 1,500 horsepower of compression used in the NGL extraction process.
Y-Grade produced at the Hamlin Plant is sold and delivered to an NGL pipeline operated an affiliate of Mobil Oil Corporation. Y-Grade produced at the Shackleford Plant is sold and delivered to an NGL pipeline operated by an affiliate of Koch Industries, Inc.
SALES AND MARKETING
Natural Gas Marketing. The Company markets natural gas to local distribution companies ("LDCs"), marketing affiliates of pipeline companies, electric utilities, various business and industrial end-users and other natural gas marketers throughout the CNG Market Area. A portion of the natural gas which the Company markets is produced in the Panhandle Area and is transported from the Company's plants through pipeline interconnections with ANR Pipeline Company ("ANR"), Williams Natural Gas Company ("WNG"), NNG and Colorado Interstate Gas Company ("CIG"). Additional volumes of natural gas which the Company markets are produced at the Hamlin and Shackleford Plants and are sold at the outlet of such Plants. The Hamlin Plant interconnects with Lone Star Pipeline and Transok, L.L.C.'s Palo Duro System. The Shackleford Plant interconnects with Loan Star Pipeline and a pipeline operated by Valero. In addition, the Company purchases and resells off-system gas on numerous pipeline systems located throughout the CNG Market Area.
The Company has multiple pipeline delivery connections, which it believes allow it to negotiate favorable spot sales contracts and transportation rates and to avoid curtailment of natural gas deliveries. Due to the flexibility derived from multiple delivery points, the Company believes that the loss of any of its markets on a particular pipeline would not have a material adverse effect on the Company. The Company's Panhandle Area facilities are located in an area where many interstate pipelines converge, allowing it to take advantage of locational differences in natural gas prices.
During the year ended December 31, 1997, the Company delivered natural gas to approximately 150 customers located in 12 states. In 1997, the Company delivered an average of approximately 289 MMcf/d and had natural gas sales revenues of approximately $290 million. No one customer accounted for more than 10% of total natural gas sales revenues during 1997.
During 1996 and 1995, the Company experienced average daily natural gas sales of 224 MMcf/d and 165 MMcf/d, respectively. Sales growth in 1996 and 1997 has resulted largely from CNG's hiring of four additional marketing representatives during the period of May 1, 1996 to the present.
By aggregating large volumes of natural gas and maintaining the flexibility to sell into different markets, CNG has been able to maximize sale prices by selling to customers who are willing to pay a premium for large, reliable quantities of natural gas. Accordingly, the Company expects to continue to receive greater value than the commodity spot price for its delivered natural gas.
The Company sells natural gas under sales agreements which may be classified by (i) the duration of the contract, (ii) pricing terms and (iii) the nature of the delivery obligations. "Term" contracts have a duration in excess of one month, "spot" contracts have a duration of one month or less and "peaking" contracts apply during short periods of high demand. The Company sells natural gas at "fixed" prices or at "index" prices which vary on a month-to-month basis with market conditions. Under "baseload" contracts the Company is required (subject to extremely limited exceptions) to deliver a specific volume of natural gas, while under "best efforts" contracts delivery obligations may be suspended at the option of the Company or the purchaser. Due to varying market conditions, the "mix" of the Company's sales agreements vary substantially from time to time.
Transportation. The Company arranges for transportation of the natural gas it markets from the supplier's point of receipt to the sales customer's delivery point. To facilitate the transportation of its natural gas the Company must schedule, nominate and monitor transportation availability on a continual basis. The Company believes that its knowledge of the pipeline network within the CNG Market Area is an important element in its success as a natural gas marketer. This allows the Company to provide its suppliers with multiple outlets for their natural gas and, in times of changes in demand or supply due to weather or other factors, to route natural gas to areas where higher sales prices may be achieved. In an effort to improve profit margins, the Company attempts to reduce transportation charges by taking advantage of its broad array of transportation arrangements and by negotiating Capacity Release, storage and competitive transportation discounts.
The Company transports natural gas on interstate pipelines under interruptible and firm transportation agreements. Under interruptible transportation agreements, a pipeline is usually obligated to transport on a non-discriminatory basis up to a specified maximum quantity of natural gas, subject to available capacity. In return, the Company pays a transportation fee based on the quantity of natural gas actually transported. An interruptible transportation agreement may provide the customer with priority over other interruptible shippers based on the rate paid and subject to the availability of capacity not utilized by parties shipping under firm transportation agreements. As of December 31, 1997, the Company had over 150 interruptible transportation contracts. The majority of off-system gas purchased and sold by the Company is transported under interruptible transportation arrangements.
Under firm transportation agreements, a pipeline is obligated to transport up to a specified maximum quantity of natural gas without interruption, except upon the occurrence of a force majeure event. Certain of the Company's customers, including LDCs and electric utilities, and some of the Company's long-term supply contracts require dependable transportation services provided under firm transportation agreements. Some customers who purchase natural gas from the Company transport such natural gas under their own transportation arrangements, while other customers require or allow the Company to arrange for such transportation services on their behalf.
Under contractual arrangements with pipelines, the Company is required to balance its deliveries and receipts from each pipeline on a monthly or daily basis. The pipelines are authorized to impose "imbalance penalties" in the event that the Company's deliveries or receipts from any pipeline are not balanced on a monthly or daily basis. These penalties are typically quite severe. In addition, the Company may be required to purchase or sell natural gas at unacceptable prices in the event it has not accurately balanced its deliveries or receipts from the pipeline (i.e. it must purchase natural gas to make up deficient volumes or sell natural gas to reduce excess volumes).
Due to regulatory changes resulting from Order 636 of the FERC, the availability of firm transportation has increased, while the availability of interruptible transportation on certain pipelines has decreased. In particular, Order 636 permits current holders of pipeline firm transportation rights, generally LDCs and large end-users, either to enter into Capacity Releases of dedicated capacity with replacement shippers or to turn that capacity back to the pipeline to be posted on an electronic bulletin board for sale. Typically, LDCs sell Capacity Release during periods of low demand and compete with released capacity by other LDCs or the pipeline's unsubscribed capacity. As a result, the Company is often able to purchase Capacity Release at a discount from posted rates.
NGL Marketing. The Company presently sells NGLs primarily to wholesale markets with some sales in the local retail market. In 1997, the Company hired an NGL marketer with the intent of realizing higher margins on NGLs through increased sales to the retail market and increasing the marketing of third-party NGLs. Generally, prices for NGLs tend not to vary directly with natural gas prices, but more closely follow the prices of crude oil derivatives. Processing margins increase when natural gas prices are lower in relation to NGL prices. The Company had NGL sales of approximately $46 million in 1997 on NGL average volumes of 387 Mgal/d compared to NGL sales of approximately $37 million in 1996 on NGL average volumes of 265 Mgal/d.
NGLs are typically used as petrochemical feedstocks, petroleum refinery blendstocks or fuel. Petrochemical plants use ethane, propane, butane and natural gasoline in the production of ethylene, which is used in the manufacture of plastics, building materials, automobile antifreeze and other products. Refineries use normal butane and isobutane as motor fuel additives. Propane has agricultural applications and is used as fuel for household consumption, vehicles and industrial heaters and boilers.
As feedstock, demand for NGLs is influenced by the demand for the end products in which they are used. Also, the demand for normal butane and isobutane, which are important feedstocks for the production of the oxygenate, methyl tertiary butyl ether ("MTBE"), is expected to increase as demand for MTBE increases in gasoline production. The required use of oxygenates in motor gasoline under the Clean Air Act Amendments of 1990 in many parts of the United States is expected to increase demand for MTBE. Seasonal requirements of purchasers using NGLs as a fuel source also affect demand. NGL production is dependent upon the supply and NGL content of domestic natural gas. The market price of NGLs relative to natural gas affects the volume of natural gas processed and the NGLs extracted from the natural gas. Certain NGLs are produced outside North America and imported by ship, which may from time to time affect NGL prices.
Risk Management Activities. The Company uses risk management tools to reduce commodity price risk for (i) purchases of natural gas to replace fuel and shrinkage in connection with processing operations and (ii) its NGL and natural gas sales. With respect to fuel and shrinkage for processing operations the Company examines the prevailing price environment on an ongoing basis to determine if opportunities exist to lock-in prices for replacement natural gas at levels acceptable to the Company. The Company's management is responsible for monitoring the price environment for replacement natural gas and makes any decisions necessary to implement the Company's hedging strategies.
The Company employs several procedures to manage its risk with respect to the purchases and sales of natural gas. The Company's principal strategy is to balance purchases and sales of natural gas on a daily and monthly basis. This means on any given day or in any given month the Company has commitments to purchase and sell approximately the same volume of natural gas. This strategy is accomplished through active management and monitoring of natural gas supply and sales through the Company's natural gas marketing department.
A second strategy employed by the Company to manage risk is to enter into contracts for the "back-to-back" purchase and sale of natural gas. Under this strategy, the Company enters into natural gas purchase contracts and natural gas sales contracts for a corresponding volume of natural gas. The Company thereby locks in its profit and also locks in a supply of natural gas in order to assure performance under the applicable sales contract.
Finally, the Company enters into other hedging transactions with respect to its fixed price purchases and sales of natural gas, which constitute less than 10% of its total purchases and sales. These transactions include futures contracts, swaps and basis agreements and other arrangements common in the financial markets. The Company consistently has hedging positions to cover substantially all of its purchases and sales under fixed price agreements.
The Company generally does not use hedging transactions for speculative purposes. The Company has, however, on certain occasions taken open positions on carefully selected arbitrage opportunities. While these occasions have been relatively few and are carefully reviewed by the Company's management, the Company
believes that the competitive information it obtains from its energy marketing activities allows it to take advantage of certain opportunities in the market.
The Company's management oversees all hedging activity of the Company. A daily book on all positions is maintained and daily and monthly reports are given to management. See Note 15 to the Notes to Consolidated Financial Statements of the Company included herein.
In addition to the risk associated with price movements, credit risk is also inherent in the Company's risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance of a counterparty of its contractual obligations. The Company maintains credit policies with regard to counterparties that the Company believes significantly minimize overall credit risk. These policies include the thorough review of potential counterparties' financial condition, collateral requirements under certain circumstances, monitoring of net exposure to each counterparty and the use of standardized agreements which allow for the netting of positive and negative exposures associated with each counterparty.
Electric Power Marketing. The Company formed Continental Energy Services, L.L.C. ("CES") in 1996 to pursue electric power marketing opportunities that are being created as the domestic electric power industry becomes increasingly deregulated pursuant to the Energy Policy Act of 1992 (the "Energy Policy Act") and certain actions taken by the FERC (including implementation of wholesale open access under Order 888) and public utility commissions in various states. Just as the Company provides aggregation and marketing services for natural gas producers and consumers, CES intends to provide similar services in a deregulating domestic electric industry.
CES received authorization from the FERC in December 1996 to purchase, sell and market wholesale electric power and engage in other energy-related transactions and to charge market-based rates for such services and transactions. CES initially intends to market electric power to electric utilities, municipalities and electric cooperatives on a wholesale basis.
In the future, if the power industry continues to deregulate and subject to state and federal regulations, CES also intends to pursue the direct marketing of power to existing industrial and commercial natural gas customers of the Company in states which permit such activities. There is no guarantee that the states or the federal government will adopt programs permitting such activities or that such programs will be adopted on terms beneficial to CES. If adopted, however, these programs are anticipated to allow CES to market electric power directly to industrial and commercial end-users while using the utilities, municipalities and electric cooperatives solely to generate and transmit power to these end-users, much like the Company markets natural gas to LDCs and end-users using the pipelines for transportation services only. CES also expects to offer a variety of risk management products and services to generators and consumers including futures, options, swaps and basis agreements and other financial instruments.
CES has not, as yet, entered into any contracts or conducted any substantive activities. The timing, manner and extent to which the power industry will deregulate, with respect to both wholesale power marketing and retail direct access, is extremely uncertain. Even if the power industry continues to deregulate in a manner beneficial to CES, there can be no assurance that the operations of CES, when and if commenced, will be profitable.
OPERATIONAL RISKS AND INSURANCE
The Company's operations are subject to potential hazards incident to the gathering, processing, separation and storage of natural gas and NGLs, such as explosions, product spills, leaks, emissions and fires. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage, and may result in curtailment or suspension of operations at the affected facility.
The Company maintains general public liability, property and business interruption insurance in amounts that it considers to be adequate for such risks. Such insurance is subject to deductibles that the Company considers reasonable and not excessive. Consistent with the Company's proactive approach to risk management, the Company's pollution liability policies not only provide protection for sudden and accidental
occurrences, but also, subject to the policy terms and conditions, provide protection for gradual pollution incidents occurring over time.
The occurrence of a significant event for which the Company is not fully insured or indemnified, and/or the failure of a party to meet its indemnification obligations, could materially and adversely affect the Company's operations and financial condition. Moreover, no assurance can be given that the Company will be able to maintain adequate insurance in the future at rates it considers reasonable. To date, however, the Company has maintained adequate coverage at reasonable rates and has experienced no material uninsured losses.
COMPETITION
The Company faces intense competition in obtaining natural gas supplies for its gathering and processing operations and in marketing its products and services. Principal competitors include marketing affiliates of interstate pipeline companies, national and local natural gas gatherers and marketers of varying sizes, financial resources and experience. Many of the Company's competitors have capital resources and control supplies of natural gas substantially greater than those of the Company.
The Company competes against other companies in the natural gas processing business both for supplies of natural gas and for customers to which it sells its products. Competition for natural gas supplies is based primarily on price, location of natural gas gathering facilities and gas processing plants, line pressures, operating efficiency, reliability and quality producer relationships. Competition for sales customers is based primarily on price, delivery capabilities, reliability, price flexibility and maintenance of quality customer relationships.
CNG's fractionation business competes against other fractionation facilities that serve local markets. Competitive factors affecting its fractionation business include proximity to customers, quality of NGL products, price, efficiency and reliability of service.
In marketing its products and services, the Company has numerous competitors, including marketing affiliates of major interstate pipelines, major natural gas producers, and local and national gatherers and marketers of widely varying sizes, financial resources and experience. Marketing competition is primarily based upon reliability, transportation, flexibility and price.
GOVERNMENTAL REGULATION
Currently, federal, state and local regulations do not materially affect the purchase and sale of natural gas and the fees received for gathering and processing by the Company. Therefore, except as constrained by competitive factors and contracts, the Company has considerable pricing flexibility. However, federal, state and local laws and regulations, directly or indirectly, govern some aspects of the operations of the Company. These laws and regulations may in the future have a significant impact upon the Company's overall operations.
In 1992, the FERC issued Order 636 which generally opens access to interstate pipelines by requiring the operators of such pipelines to unbundle their transportation services from sales services and allow customers to choose and pay for only the services they require, regardless of whether the customer purchases natural gas from such pipeline or from other suppliers. Order 636 also requires upstream pipelines to permit downstream pipelines to assign upstream capacity to their suppliers, and places analogous, unbundled requirements on the downstream pipelines. This mandated access to interstate pipelines was and is of vital importance to the Company's off-system gas business and to the delivery of natural gas from the Texas Gathering Assets to its processing plants in Oklahoma. A change in such regulation could adversely affect these portions of the Company's business.
The FERC retains jurisdiction over the interstate transportation of natural gas and of liquid hydrocarbons, such as NGLs and product streams derived therefrom. The gathering and processing of natural gas for the removal of liquids currently is not viewed by the FERC as an activity subject to its jurisdiction. If a processing plant's primary function is extraction of NGLs and not natural gas transportation, the FERC has traditionally maintained that the plant is not a facility for transportation or sale for resale of natural gas in
interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act of 1938 (the "NGA").
The NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. Interstate transmission facilities, on the other hand, remain subject to the FERC jurisdiction. The FERC has historically distinguished between these two types of facilities on a fact-specific basis. The Company believes that its gathering facilities and operations meet the current tests that the FERC uses to determine a nonjurisdictional gathering facility status. While certain recent cases have applied these tests in a manner supporting the Company's view that the FERC lacks jurisdiction over its gathering facilities, these cases are, however, still subject to rehearing and appeal. In addition, the FERC's articulation and application of the tests used to distinguish between jurisdictional pipelines and nonjurisdictional gathering facilities have varied over time. While the Company believes the current definitions create nonjurisdictional status for the Company's gathering facilities, no assurance can be given that such facilities will remain classified as natural gas gathering facilities and the possibility exists that the rates, terms, and conditions of the services rendered by those facilities, and the construction and operation of the facilities, will be subject to regulation by the FERC.
Two proceedings had been filed at the FERC alleging that certain aspects of the Company's business were subject to regulation under the NGA (GPM Gas Corporation v. Continental Natural Gas, Inc., Docket No. CP96-495-000; Plant Owners v. Continental Natural Gas, Inc., Docket No. CP96-577-000.) The entities initiating these proceedings alleged that the use of the Company's facilities to receive natural gas from, and deliver natural gas to, interstate pipelines renders those facilities subject to FERC's jurisdiction. On September 12, 1997, the FERC ruled in the Company's favor with respect to the complaint filed by GPM. As a result of the complaint filed by the Plant Owners, the FERC held that CNG's residue line (the "ANR Residue Line") from the outlet of its Beaver Plant to an interconnection with ANR Pipeline Company is subject to FERC jurisdiction as a transmission facility. The FERC's order indicated that the ANR Residue Line would be exempted from certain of the FERC's jurisdictional requirements. The Company has filed an application for a certificate and asked for a waiver of all FERC requirements. That request is pending. If the FERC does not grant the Company's requested waiver, it may limit the rates that the Company charges for service, may preclude the Company from engaging in certain transactions, may impose other obligations on the Company, or may subject the Company to regulation as an interstate pipeline.
Traditionally, the FERC has regulated the rates for gathering service performed by interstate pipelines and their affiliates. In 1995, the FERC held that interstate pipeline affiliates that performed gathering services could have their rates and services deregulated. In addition, the FERC established a two-year default (i.e., transition) period during which the new owners of gathering facilities formerly owned by interstate pipelines would have to provide service at the same rates and on the same terms and conditions as was provided by the pipelines. As a result, many interstate pipelines have transferred their facilities to gathering affiliates or sold them to third-parties. On August 2, 1996, the United States Court of Appeals for the District of Columbia Circuit upheld the FERC's decision to deregulate gathering but voided the two year default period. As a result, there could be numerous additional unregulated gathering companies. Certain of those gathering companies may compete with the Company. Notwithstanding the decision of the D.C. Circuit, many owners of facilities acquired from interstate pipelines have committed to continue providing service at the same rates and on the same terms and conditions during the default period. At the expiration of these default periods, it is possible that the cost of gathering service paid by the Company could increase substantially. In addition, the Company (as a shipper on these systems) could be placed at a competitive disadvantage vis-a-vis the owner of the gathering facilities in acquiring natural gas and NGLs. It should be noted that the Texas Gathering Assets were freed of the FERC-mandated rate controls when their associated default period expired at the end of 1997. As competition permits, the Company intends to increase the rates which it charges for gathering services with respect to the Texas Gathering Assets. Moreover, the Company does not believe that it will be affected by any action taken by the FERC with respect to gathering materially differently than any other producers, gatherers, processors or marketers with which it competes.
Construction of some of the Company's gathering pipelines are subject to federal safety standards promulgated by the Department of Transportation ("DOT") under applicable federal pipeline safety legislation (including the "Pipeline Safety Act"). as supplemented by various state safety statutes and
regulations. In addition, certain of the Company's pipeline operations are subject to DOT reporting requirements. To the Company's belief only the ANR Residue Line and a short segment of pipeline associated with the Shackleford Gathering System are subject to DOT construction standards and reporting requirements. Nonetheless, the Company constructs all of its gathering lines in compliance with DOT construction standards.
The Company is required by the DOT to conduct drug tests in connection the operation of DOT-regulated facilities. Although not required, the Company currently conducts drug tests of all field personnel in compliance with DOT standards.
Certain activities of the Company could be subject to regulation by the Texas Railroad Commission ("RRC") pursuant to its jurisdiction over common purchasers and natural gas utilities or its jurisdiction over the transportation and gathering of natural gas. CNG is a "common purchaser" under Texas law. It is not presently registered as a "gas utility" though no assurance can be given that it will not at some future time be required to register as such.
Although the RRC does not regulate the activities of the Company at this time, the RRC has authority to regulate the volumes of natural gas purchased by common purchasers and the rates charged for the intrastate transportation, gathering and sale of natural gas by gas utilities in Texas. Under the Gas Utility Regulatory Act and other Texas statutes, the RRC has the duty to ensure that rates for the transportation, gathering and sale of natural gas are just and reasonable and gas utilities are prohibited from charging rates that are unreasonably preferential, prejudicial or discriminatory. The Company believes that its activities are in compliance with applicable laws and regulations.
The Company's Oklahoma operations are subject to regulation by the State of Oklahoma. The majority of these regulations are administered by the Oklahoma Corporation Commission ("OCC"). Any entity engaged in the business of carrying or transporting natural gas by pipeline is declared to be a common carrier under Oklahoma law and is prohibited from any unjust or unlawful discrimination in the carriage, transportation or delivery of natural gas. Although Oklahoma law may be sufficiently broad to permit the OCC to set rates and terms of service for the transportation and delivery of natural gas involving the Company's Oklahoma assets, the OCC has not done so to date. There can be no assurance that the OCC will not do so in the future. Recent Oklahoma legislation prohibits entities which gather natural gas for hire from charging any fee which is unjustly or unlawfully discriminatory. The Company does not expect this legislation to have any significant impact on the Company's operations.
An entity carrying or transporting natural gas by pipeline which is engaged in the business of purchasing natural gas is declared to be a common purchaser under Oklahoma law and is required to purchase without discrimination in favor of persons or price all natural gas in the vicinity of its lines. Ratable purchase is required if a purchaser is unable to purchase all natural gas offered. To date, such legislation has not had any significant effect on the Company's Oklahoma operations.
The OCC and the RCC regulate the amount of natural gas which producers can sell or deliver to the Company. Currently, substantially all natural gas received by the Company in its Oklahoma and Texas operations is produced from wells for which the OCC or RCC establish allowable rates. To date, the Company has not experienced any material reductions in available supplies due to these regulations. Nevertheless, future regulations could materially affect the Company's ability to purchase natural gas supplies.
The Federal Power Act regulates the transmission of electric power in interstate commerce and sales of electric power for resale. The FERC asserts jurisdiction over such sales, but allows electric power marketers such as Continental Energy Services, L.L.C. ("CES") to make wholesale sales at market-based rates. In connection with its Power Marketing Certificate, CES is required to file a reports with the FERC on a quarterly basis.
ENVIRONMENTAL MATTERS
The Company is subject to environmental risks normally incident to the operation and construction of gathering lines, pipelines, plants and other facilities for gathering, processing, treatment, storing and
transporting natural gas and other products. These environmental risks include uncontrollable flows of natural gas, fluids and other substances into the environment, explosions, fires, pollution and other environmental and safety risks. The following is a discussion of certain environmental and safety concerns related to the Company. It is not intended to constitute a complete discussion of the various federal, state and local statutes, rules, regulations, or orders to which the Company's operations may be subject. For example, the Company, without regard to fault, could incur liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (also known as the "Superfund" law), or state counterparts, in connection with the disposal or other releases of hazardous substances and for damage to natural resources. Further, the recent trend in environmental legislation and regulations is toward stricter standards, and this will likely continue in the future.
The Company's activities in connection with the operation and construction of gathering lines, pipelines, plants, storage caverns, and other facilities for gathering, processing, treatment, storing and transporting natural gas and other products are subject to environmental and safety regulation by federal and state authorities, including, without limitation, the state environmental agencies and the EPA, which can increase the costs of designing, installing and operating such facilities. In most instances, the regulatory requirements relate to the discharge of substances into the environment and include measures to control water and air pollution.
Environmental laws and regulations may require the acquisition of a permit or other authorization before certain activities may be conducted by the Company. These laws also include fines and penalties for non-compliance. Further, these laws and regulations may limit or prohibit activities on certain lands lying within wilderness areas, wetlands, areas providing habitat for certain species or other protected areas. The Company is also subject to other federal, state, and local laws covering the handling, storage or discharge of materials used by the Company, or otherwise relating to protection of the environment, safety and health. The Company believes that it is in material compliance with all applicable environmental laws and regulations. The Company periodically conducts environmental assessments of its assets and is not aware of any material environmental problems requiring remediation. Because the requirements imposed by environmental laws and regulations frequently change, the Company is unable to predict the ultimate costs of compliance with such requirements or whether the incurrence of such costs would have a material adverse effect on the operations of the Company.
In March 1992, an environmental site assessment of the Laverne Plant indicated the presence of hydrocarbon contaminated groundwater underlying a portion of the plant site. Under the direction of the Oklahoma Corporation Commission in Cause No. PD-920024760 and based on the results of a pilot remediation project, a plan has been developed to remediate the site utilizing a biofiltration process to be installed during the last half of 1997 at an estimated cost of $1 million. The Company's share of this total cost is expected to be approximately $170,000. Due to various delays occurring prior to the Company's acquisition of its interests in the Laverne Plant, the installation of the biofiltration equipment will not occur until the second or third quarter of 1998.
The Company's aggregate expenditures for compliance with laws and regulations related to the discharge of materials into the environment or otherwise related to the protection of the environment totaled approximately $260,000 in 1997. Total environmental expenditures for both capital and operating maintenance and administrative costs are not expected to exceed $300,000 in 1998.
EMPLOYEES
As of December 31, 1997, the Company had 150 employees. Of these, 96 employees are located in the field (72 of such employees provide general operational and maintenance activities in the Panhandle Area and 24 of such employees provide general operational and maintenance activities in North Central Texas), while the balance are located at CNG's executive offices in Tulsa, Oklahoma, and are engaged in gas marketing activities, plant supervision or accounting and administration. The Company considers its relations with employees to be excellent.
ITEM 2:
ITEM 2: PROPERTIES
GATHERING SYSTEMS AND PROCESSING PLANTS
As of December 31, 1997, the Company had approximately 2,000 miles of natural gas gathering pipelines, interest in six natural gas processing plants, each of which has extraction equipment and two of which have fractionation equipment and 102 compressor units located at 60 field stations and its six plant sites.
The following table provides information concerning the Company's natural gas processing plants and gathering systems:
- ---------------
(1) For the period October through December, 1997.
(2) The Company owns an individual 56% interest in the Laverne Plant. The Company serves as operator of the Laverne Plant.
(3) For the period August through December, 1997.
(4) The Company acquired Taurus Energy Corp. at the end of November 1997. Volumes are for the month of December 1997.
The Company owns approximately 43 acres of land at its Beaver Plant site, approximately 40 acres at its Mocane Plant site, approximately 30 acres at its Spearman Plant site, approximately 10 acres at its Shackleford Plant site and approximately 8 acres at its Hamlin Plant site. Approximately 50 acres are held in connection with operation at the Laverne Plant. While this real property is necessary in order to operate the Company's plants, it does not contribute significantly to the value of the Company.
The Company's gas processing plants are fed directly by a network of low and intermediate pressure steel and polypipe gas gathering pipelines. The Beaver Gathering System consists of approximately 300 miles of pipelines connecting over 100 wells for ultimate delivery to the Company's Beaver and Mocane Plants. Approximately 30% of the Beaver and Mocane Plants' current throughput originates from the Beaver Gathering System. The Company's Texas Gathering Assets extend for approximately 800 miles across the northern Texas Panhandle providing substantial gathering exposure along the western edge of the Anadarko Basin, south of its existing processing plants in the Panhandle Area. Approximately 500 wells are connected to the Texas Gathering Assets for redelivery to the interstate pipelines of either NNG or TW. The Texas Gathering Assets, which are steel pipelines, operate at low pressures.
The Company installed two pipelines connecting the Mocane Plant to the Beaver Plant in 1995. These pipelines allow the Company to optimize processing capacity utilization by shifting raw and processed natural gas between the Beaver and Mocane Plants. In addition, the Company has constructed approximately 27 miles
of residue interconnect line, connecting the Beaver Plant to the ANR, WNG and CIG interstate pipelines, thus expanding the markets for the Company's on-system gas.
The Company's operations in the Panhandle Area consist of the Beaver, Mocane, Laverne and Spearman Plants, natural gas gathering systems, compression equipment, NGL storage, fractionation and truck terminal facilities. The Company believes the Panhandle Area has favorable production, supply and market access characteristics. The Panhandle Area is one of the most prolific natural gas producing regions in the continental United States. Production is obtained from several geologic formations. Natural gas fields in the area have produced for many years and currently produce at stabilized low rates of decline that indicate substantial reserves.
The Company's operation in north central Texas consist of the Shackleford Plant and Gathering System and the Hamlin Plant and Gathering System. The Shackleford Gathering System consists of approximately 250 miles of gathering lines connecting approximately 250 wells for ultimate delivery to the Shackleford Plant. The Hamlin Gathering System collects natural gas from approximately 450 wells utilizing 500 miles of pipelines -- gas collected on the Hamlin Gathering System is delivered to the Hamlin Plant for processing.
COMPRESSION AND STORAGE FACILITIES
In connection with the operation of its gathering systems, the Company operates 102 compressor units located at 60 field stations and six plant sites with approximately 63,000 horsepower of natural gas compression. Compressors are used to boost natural gas produced and gathered at low field pressure to higher pipeline pressures. Approximately 31% of the Company's compression capacity is leased under various capital lease agreements. Under such capital lease agreements, the Company makes approximately $1.8 million per year in payments. The terms under such capital leases range from 1998 to 2003 at which time the Company has an option to purchase (generally at a nominal price) the leased equipment. The Company continues to enter into capital lease agreements for compression and other natural gas processing equipment. Under its credit facility, the Company is permitted to incur capital lease obligations which require annual payments of up to $3 million per year.
CORPORATE OFFICES
The Company leases its Tulsa, Oklahoma headquarters under a commercial office lease covering approximately 28,832 square feet, expiring in September 2002. The annual rental payments are approximately $313,589. The Company also has a local marketing office in Houston, Texas and a local operations office in Dallas, Texas.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
As of December 31, 1997, the Company was a defendant in the case of Colorado Interstate Gas Company v. Continental Hydrocarbons, Inc., et al., Case No. 93CV1894 (the "Colorado Lawsuit"). The case pertained to the Company primarily involved claims made by CIG that the Company and Continental Hydrocarbons, Inc. ("CHI"), a former subsidiary of the Company, improperly withheld proceeds from the sale of NGLs processed at the Mocane Plant, defamed CIG and committed other wrongful acts, and, as a result, liable to CIG for unspecified actual and punitive damages. CIG sought damages from the Company in excess of $3 million.
In the first quarter of 1998, the Company and CIG reached a settlement with respect to all claims in the Colorado Lawsuit. Pursuant to the terms of the settlement, the Company paid CIG $2 million in cash. Through September 30, 1997, the Company had established reserves of approximately $1.4 million in connection with CIG's claims. The Company incurred a $600,000 pre-tax charge to earnings in the fourth quarter of 1997 as a result of the settlement. In connection with the settlement, the Company arranged to transport a portion of its natural gas on CIG's Mocane Gathering System -- the Company believes that this arrangement is mutually beneficial to the Company and CIG.
The Company is at various times a party to additional claims and involved in various other litigation and administrative proceedings arising in the normal course of business. The Company believes it is unlikely that the final outcome of any of the claims, litigation or proceedings discussed above to which the Company is a party would have a material adverse effect on the Company's financial position or results of operations; however, due to the inherent uncertainty of litigation, the Company cannot give assurance regarding the effect on the Company of an adverse resolution of any particular claim or proceeding.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders in the fourth quarter of 1997.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of the Company is listed on the NASDAQ stock market under the symbol CNGL. Set forth below is the high and low sales prices of the common stock by calendar quarter for the period August 1, 1997 through March 24, 1998.
On March 24, 1998, the last reported sales price for the common stock, as reported on the NASDAQ Composite Index, was $10.25 and the Company had 15 stockholders of record and approximately 800 beneficial owners.
The Company has not paid any cash dividends on its common stock in the two most recent fiscal years. The Company does not intend to pay any cash dividends on its common stock and anticipates that, for the foreseeable future, it will retain any earnings for use in the operation and expansion of its business. Payment of cash dividends in the future will depend upon the Company's earnings, financial condition, any contractual restrictions (including restrictions contained in agreements relating to the Company's credit facility), restrictions imposed by applicable law, capital requirements and other factors deemed relevant by the Company's Board of Directors. The Company's current credit facility prohibits the payment of dividends until the one-year anniversary of the Company's Amended and Restated Credit Agreement dated November 25, 1997, and, in any event, prohibits payment of dividends in an amount in excess of 10% of the Company's annual consolidated net income.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial and operating data of the Company. The selected consolidated financial data for each of the five years in the period ended December 31, 1997, was derived from the audited consolidated financial statements of the Company. The financial data set forth below should be read in conjunction with the Consolidated Financial Statements and the Notes thereto and "Management's Discussion and Analysis of Financial Condition and Results of Operations."
- ---------------
(1) Includes the acquisition of Taurus Energy in 1997.
(2) See definitions Section in this annual report.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Since its formation, the Company has grown primarily as a result of acquisitions, facilities expansions and connections of additional natural gas reserves to its natural gas gathering systems. Additionally, the Company has increased its natural gas and NGL marketing operations. All historical financial information has been restated to reflect the Company's approximate 136-for-1 stock split effected in July 1997. This discussion and analysis should be read in conjunction with the Consolidated Financial Statements of the Company and the notes thereto included elsewhere in this Annual Report.
RESULTS OF OPERATIONS
The Company's results of operations are determined primarily by the volume of natural gas purchased, processed and resold in its natural gas gathering systems and processing plants. The Company also purchases for resale natural gas unrelated to its gathering or processing business ("off-system gas") which contributes to its profitability. Acquisitions in the first half of 1996, of the Texas Gathering Assets, have had a significant impact on the Company's results of operations for 1997 and 1996.
On November 25, 1997 the Company acquired Taurus Energy Corp. for approximately $42 million. Management believes this acquisition will have a significant impact on the Company's results of operations in the future.
Fluctuations in the price levels of natural gas and natural gas liquids ("NGLs") also affect results of operations since the Company generally receives a portion of the natural gas and NGLs revenue from natural gas throughput. In the fourth quarter of 1997, high natural gas prices relative to NGLs prices created a significant negative impact on operating results. Most of the Company's operating expenses do not vary materially with changes in natural gas throughput volume on existing systems; thus, increases or decreases in volumes on existing systems generally have a direct effect on the Company's profitability. Conversely, operating expenses such as compression rental and compression maintenance expenses vary with volume changes as compressor units are added or removed accordingly.
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Revenues. Total operating revenue increased 38% to $340.6 million for the year ended December 31, 1997 as compared to $246.7 million for the same period in 1996. Total natural gas sales increased 39% to $289.6 million in 1997 from $208.8 million for the same period in 1996 as a result of a $20.5 million price- related increase due to average sales prices of $2.75 per Mcf in 1997 compared to $2.55 per Mcf in 1996 and a $60.3 million volume-related increase due to sales of 288.8 MMcf/d in 1997 compared to 224.1 MMcf/d in 1996. This increase in volume resulted from increases in both off-system and on-system gas marketing sales.
NGL sales increased 33% to $46.2 million for the year ended December 31, 1997 as compared to $34.8 million for the same period last year as a result of a $4.7 million price-related decrease due to average NGL sales prices of $0.33 per gallon in 1997 compared to $0.36 per gallon in 1996 and a $16.1 million volume-related increase due to increased natural gas processing throughput.
The Company earned gathering fees of $4.4 million in 1997 as compared to $2.0 million for the same period in 1996 primarily as a result of the acquisition of the Texas Gathering Assets.
Costs and Expenses. Total operating costs and expenses increased 40% to $337.0 million for year ended December 31, 1997 as compared to $240.0 million for the same period in 1996. Total natural gas costs increased 41% to $318.3 million in 1997 from $225.5 million in 1996 as a result of increases in price and volume. The $26.5 million price-related increase (resulting from a change in average purchase prices of $2.68 per Mcf in 1997 from $2.46 per Mcf in 1996) was mitigated by approximately $3.1 million of avoided gathering fees caused by the integration of the Texas Gathering Assets into the Company's processing business. A $66.3 million volume-related increase resulted from purchases of 325.0 MMcf/d in 1997 compared to 251.1 MMcf/d in 1996. This increase in volume resulted primarily from increases in off-system gas marketing purchases.
Operating expenses increased to $7.1 million for the year ended December 31, 1997 from $6.0 million for the same period in 1996. This was due mainly to operating activities from the acquisition of the Texas Gathering Assets and the Laverne Plant.
General and administrative expenses increased 34% to $7.6 million for the year ended December 31, 1997 from $5.6 million in the same period last year. This increase was due primarily to the addition of marketing personnel and administrative support activities related to the Texas Gathering Assets and other acquisitions.
Depreciation, depletion and amortization increased 43% to $4.1 million for the year ended December 31, 1997 from $2.9 million for the same period in 1996 principally due to the acquisition of the Texas Gathering Assets, expansions at the Company's Beaver Plant and the Laverne Plant acquisition.
Other Income (Expense). Interest income increased to $0.5 million for the year ended December 31, 1997 from $0.1 million for the year ended December 31, 1996 due to increased cash investments associated with contract advances received in the fourth quarter of 1996. During these same time periods, interest expense increased 95% to $5.3 million from $2.7 million due primarily to additional debt incurred to finance the acquisition of the Texas Gathering Assets, the Laverne plant and the expansion of the company's existing facilities. In addition, the Company incurred a $600,000 charge in the fourth quarter of 1997 as a result of a litigation settlement.
Income Taxes. The Company had an income tax benefit of $644,000 for the year ended December 31, 1997 as compared to $3.6 million for 1996. For 1997, the Company's tax rate approximates the sum of the federal and state statutory rates while in 1996, the Company's effective tax rate was significantly impacted by its net operating loss carryforwards.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
Revenues. Total operating revenue increased 104% to $246.7 million for the year ended December 31, 1996, compared to $121.2 million for the same period in 1995. Total natural gas sales increased 118% to $208.8 million in 1996 from $95.6 million in 1995 as a result of a $79.1 million price-related increase due to average sales prices of $2.56 per Mcf in 1996, compared to $1.59 per Mcf in 1995 and a $34.1 million volume-related increase due to sales of 224.1 MMcf/d in 1996, compared to 165.1 MMcf/d in 1995. This increase in volume resulted primarily from increases in off-system gas marketing sales.
NGL sales increased 40% to $34.8 million for the year ended December 31, 1996, compared to $24.8 million in 1995, primarily as a result of a $10.0 million price-related increase due to average NGL sales prices of $0.36 per gallon in 1996, compared to $0.26 per gallon in 1995.
The Company earned gathering fees of $2.0 million for the year ended December 31, 1996, as a result of the acquisition of the Texas Gathering Assets in the second quarter of 1996.
Other revenues including sales from oil and gas properties increased to $1.1 million in 1996 from $0.8 million in 1995. All the Company's oil and gas properties were sold to an affiliated entity in the third quarter of 1996 for $0.3 million, which approximated book value. Oil and gas producing activities contributed revenues of $0.6 million and $0.5 million in 1996 and 1995, respectively.
Costs and Expenses. Total operating costs and expenses increased 105% to $240.0 million for the year ended December 31, 1996, compared to $117.2 million for the same period in 1995. Total natural gas costs increased 110% to $225.5 million in 1996 from $107.6 million in 1995 as a result of increases in price and volume. The $85.2 million price-related increase (resulting from a change in average purchase prices of $2.46 per Mcf in 1996 from $1.53 per Mcf in 1995) was mitigated by approximately $0.5 million of avoided gathering fees caused by the integration of the Texas Gathering Assets into the Company's processing business. A $32.7 million volume-related increase resulted from purchases of 251.1 MMcf/d in 1996, compared to 192.6 MMcf/d in 1995. This increase in volume resulted primarily from increases in off-system marketing purchases.
Operating expenses increased 37% to $6.0 million in 1996 from $4.4 million in 1995. This was due mainly to the increased operating activities from acquisition of the Texas Gathering Assets, expansions at the Beaver Plant and inclusion of Mocane Plant operating expenses for the full year.
General and administrative expenses increased 46% to $5.6 million in 1996 from $3.8 million in 1995. This increase was due primarily to the addition of marketing personnel, administrative support activities related to the Texas Gathering Assets and ad valorem tax increases in connection with the acquisition of the Texas Gathering Assets and Beaver Plant expansion projects.
Depreciation, depletion and amortization increased 109% to $2.9 million in 1996 from $1.4 million in 1995 primarily due to the acquisition of the Texas Gathering Assets, expansions at Beaver Plant and inclusion of the Mocane Plant for the full year.
Other Income (Expense). Interest expense increased 196% to $2.7 million in 1996 from $0.9 million in 1995 due primarily to additional debt incurred to finance the acquisition of the Texas Gathering Assets.
Income Taxes. The Company's effective income tax rate in 1996 and 1995 was significantly impacted by its net operating loss carryforwards. For financial statement purposes, recognition of the net operating loss carryforwards resulted in a tax benefit of $3.6 million in 1996 and $2.2 million in 1995. The Company anticipates that its effective tax rate in 1997 will approximate the sum of the federal and state statutory rates. See Note 8 to the Company's financial statements included elsewhere herein.
LIQUIDITY AND CAPITAL RESOURCES
General. The Company's primary sources of liquidity and capital resources historically have been net cash provided by operating activities and bank borrowings. The Company completed an initial public offering of Common Stock on August 6, 1997, selling 2,115,000 shares for $11.25 per share, yielding net proceeds of approximately $21.3 million. The proceeds were used to pay $17.3 million on the Company's term loan facility and $2.0 million on its revolving facility, to pay $0.6 million in accrued dividends on its Convertible Preferred Stock and the remainder for other general corporate purposes.
The following summary table reflects comparative cash flows for the Company for the years ended December 31, 1997, 1996 and 1995:
The decrease in net cash provided by operating activities in 1997 as compared to 1996 was mainly attributable to changes in working capital including the repayment of contract advances totaling $24.3 million. Excluding net changes in working capital components, the Company's operating activities generated cash of $2.4 million in 1997 and $6.6 million in 1996.
Cash used in investing activities for the year ended December 31, 1997 was primarily for the $42 million acquisition of Taurus Energy Corp., expansion projects on the Texas Gathering Assets and the $2.9 million acquisition of a 56% interest in a natural gas processing plant located in Harper County, Oklahoma. Cash used in investing activities for the same period in 1996 was mainly for the acquisition of the Texas Gathering Assets in the second quarter of 1996. In 1995, cash used in investing activities was related primarily to the acquisition of the Mocane Plant and related expenditures for the expansion of the Mocane fractionation facility and dual interconnecting pipelines from the Mocane Plant to the Beaver Plant.
Cash provided by financing activities for the year ended December 31, 1997 resulted mainly from borrowings under the Company's term loan facility and the net proceeds of the Company's initial public offering. Cash provided by financing activities for the same period in 1996 resulted mainly from long-term
borrowing for the acquisition of the Texas Gathering Assets. In 1995, cash provided by financing activities resulted primarily from increased borrowing levels for various capital expenditures.
The Company believes that cash generated from operations will be adequate to fund working capital requirements, debt service payments and planned capital expenditures. Future acquisitions or large capital expenditures in excess of current plans would require additional financing that the Company expects would be available through additional debt facilities.
At December 31, 1997, the Company had net operating loss carryforwards (NOLs) totaling approximately $42 million for regular tax purposes and $40 million for alternative minimum tax purposes. If not utilized, these carryforwards will expire from 2000 to 2012. Due to the lack of existing legal precedent with respect to the tax rules governing the Company's NOLs, both the availability approximately $10 million of the Company's NOLs and its prior utilization of NOLs (totaling approximately $34 million) may be challenged. Disallowance of the use of the NOLs would result in certain taxes associated with prior utilization of the NOLs being currently payable. In March of 1998, the Company received notification that the Internal Revenue Service plans to audit the Company's 1995 tax return.
Realization of the Company's deferred tax assets is dependent upon the generation of sufficient taxable income prior to the expiration of the NOLs and, for financial reporting purposes, the resolution of the matters noted above. Although realization is not assured, management believes it is more likely than not that the recorded net deferred tax asset will be realized. The amount of the deferred tax asset considered realizable could be increased or decreased by a material amount in the near-term pending resolution of these matters.
Financing Facilities. The Company entered into an Amended and Restated Credit Agreement (the "Credit Agreement") with ING Capital Corporation as of November 25, 1997. The Credit Agreement contains a revolving facility and a term loan facility. The revolving facility has a maximum borrowing base of $25.0 million which had outstanding borrowings of $6.0 million as of December 31, 1997. The revolving facility contains a sub-limit permitting the Company to issue Letters of Credit amounting, in the aggregate, to $18.0 million. As of December 31, 1997, the aggregate amount outstanding under the Letters of Credit was $8.5 million. Under the term loan facility approximately $75.0 million was outstanding as of December 31, 1997. Interest rates under both the revolving facility and term facility are variable, at the Company's election, at: (i) up to 3/4% (depending upon the Company's financial performance) above the greater of (x) the arithmetic average of the prime rates announced by Chase Manhattan Bank, Citibank, N.A. and Morgan Guaranty Trust Company of New York or (y) the federal funds rate as published by the Federal Reserve Bank of New York plus 1/2%; or (ii) 1.375% to 2.5% (depending upon the Company's financial performance) above the London Interbank Offered Rate (LIBOR). Current interest payments on the revolving facility and under the term facility began on December 31, 1997. Repayments of principal under the term facility begin on March 31, 1998.
The Credit Agreement includes covenants regarding various financial and legal matters. A breach of these covenants could constitute a default under the Credit Agreement resulting in the Company's indebtedness becoming immediately due and payable and entitling the lenders under the Credit Agreement to foreclose against collateral pledged by the Company. For the fiscal year ending December 31, 1997, the Company requested and obtained waivers of some of the financial covenants contained in the Credit Agreement. There can be no assurance that the Company's lenders will grant such waivers in the future and, if such waivers are not granted, all of the Company's indebtedness under the Credit Agreement would become immediately due and payable.
The Company had a Letter of Credit and Reimbursement Agreement with Christiania Bank, New York, Branch. Under the Reimbursement Agreement, Christiania Bank initially issued letters of credit in the aggregate amount of approximately $21.0 million to secure the Company's obligation under various contract advances. All letters of credit under this agreement expired during the third quarter of 1997. The Company paid a fee of 1 1/2% per annum for the amount of each Letter of Credit which was issued.
SEASONALITY
The Company's results of operations fluctuate from quarter to quarter, due to variations in the prices and sales volumes of NGL's and natural gas. The Company's primary NGL product is propane, which is used for agricultural and home heating in the Company's market areas. Demand and prices of propane usually increase during the winter season and decrease during the summer season. The Company's principal commodity, natural gas, is used primarily for heating fuel for homes and industry, and for electric power generation. Demand and prices for natural gas usually increase during the winter season. While the Company's gross revenues typically increase or decrease seasonally, profitability from natural gas processing operations is affected by the margins between the cost of natural gas purchased and the sales prices of the NGLs extracted, which may not follow seasonal patterns.
YEAR 2000 STATEMENT
The Company has reviewed the impact of the year 2000 software conversion as it relates to the Company's information systems. Based on this review, the Company believes the financial costs associated with this issue, including internal programming and implementation cost, will not be material. The work needed to implement the necessary changes will be performed by the Company during the last half of 1998 and is scheduled to be effective January 1, 1999.
FORWARD-LOOKING INFORMATION
The Private Securities Litigation Reform Act of 1995 provides a "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the Company.
Where any such forward-looking statement includes a statement of the assumptions or basis underlying such forward-looking statement, the Company cautions that, while it believes such assumptions or basis to be reasonable and makes them in good faith, assumed facts or basis almost always vary from actual results, and the differences between assumed facts or basis and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, the Company, or its management, expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis, but there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished.
Taking into account the foregoing, the following are identified as important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, the Company:
a) The Company's operations are subject to the risks incident to the gathering, transportation, processing and storage of natural gas and NGLs, such as explosions, product spills, leaks and fires, any of which could result in substantial losses to the Company and curtailment or suspension of operations at a Company facility.
b) Increased competition in the natural gas marketing industries, including effects of: decreasing margins as a result of competitive pressures; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; and new pricing structures.
c) Changing market conditions and a variety of other factors associated with physical energy and financial trading activities including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, currency, interest rate and warranty risks.
d) Risks associated with price risk management strategies intended to mitigate exposure to adverse movement in the prices of natural gas on both a global and regional basis.
e) Economic conditions including inflation rates and monetary fluctuations.
f) Trade, monetary , fiscal, taxation, and environmental policies of government, agencies and similar organizations in geographic areas where the Company has a financial interest.
g) Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services.
h) Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission, state public utility commissions, state entities which regulate natural gas transmission, gathering and processing and similar entities with regulatory oversight.
i) Availability or cost of capital such as changes in: interest rates, market perceptions of the energy-related industries, the Company or any of its subsidiaries or security ratings.
j) Factors affecting operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, unusual maintenance or repairs; unanticipated changes to fossil fuel, or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints.
k) Employee workforce factors including changes in key executives, collective bargaining agreements with union employees, or work stoppages.
l) Policies or procedures of regulatory entities.
m) Social attitudes regarding the natural gas and power industries.
n) Identification of suitable investment opportunities to enhance shareholder returns and achieve long-term financial objectives through business acquisitions.
o) Some future project investments made by the Company could take the form of minority interests, which would limit the Company's ability to control the development or operation of the project.
p) Legal and regulatory delays and other unforeseeable obstacles associated with mergers, acquisitions and investments in joint ventures.
q) Costs and other effects of legal and administrative proceedings, settlements, investigations, claims and matters, including but not limited to those described in the Company's initial Registration Statement on Form S-1 filed with the SEC on April 24, 1997, as amended.
r) Other business or investment considerations that may be disclosed from time to time in the Company's Securities and Exchange Commission filings or in other publicly disseminated written documents.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to the consolidated financial statements, the report thereon and the notes thereto attached hereto as pages through, which are hereby incorporated by reference.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Company will provide additional information regarding the Directors and Executive Officers of the Company pursuant to a definitive proxy statement or an amendment to this Form 10-K Annual Report pursuant to General Instruction G(3) of Form 10-K. Such information is hereby incorporated by reference.
EXECUTIVE OFFICERS OF THE COMPANY
Set forth below are the names and positions of the executive officers of the Company.
- ---------------
(1) The named person is a member of the Compensation Committee of the Board of Directors.
(2) The named person is a member of the Audit Committee of the Board of Directors.
GARY C. ADAMS has been the Company's Chairman of the Board since his founding of the Company in 1983. In 1994 he assumed the role of Chief Executive Officer, and in March 1997, was elected President. Mr. Adams is also Chairman of Adams Affiliates, Inc., which is engaged in different segments of the oil and gas industry. Most of Mr. Adams' 25-year career has been spent in the oil and gas industry. Prior to his association with Adams Affiliates, Mr. Adams served as Executive Vice President of OKC Corporation, then a New York Stock Exchange listed company, where he was responsible for its oil and gas operations. Mr. Adams graduated from the University of Kansas in 1973 with a Bachelor of Science degree in Business Administration. Mr. Adams is the son of the late K.S. "Boots" Adams, former Chairman of Phillips Petroleum Company.
SCOTT C. LONGMORE has been Vice President of Marketing of the Company since 1988 and was elected to the Board of Directors of the Company in March 1997. His primary responsibilities are to supervise the acquisition of markets, supplies and storage, the transportation of natural gas and risk management activities. Prior to joining CNG in 1987, Mr. Longmore was employed with Cabot Energy Marketing Corporation, where he served as a gas marketing and supply representative. Mr. Longmore has 12 years of experience in the natural gas marketing business. Prior to Cabot, he was an independent petroleum landman in Oklahoma. Mr. Longmore graduated from the University of Oklahoma in 1982 with a Bachelor of Business Administration degree in Petroleum Land Management.
GARRY D. SMITH has been Vice President and Controller of the Company since 1990 and was elected to the Board of Directors of the Company in March 1997. He is responsible for managing the financial and accounting functions of the Company. Prior to joining CNG in 1988, Mr. Smith served in various capacities at Mustang Fuel Corporation, including managing the financial and oil and gas revenue accounting functions. He received his Bachelor of Science degree in Accounting from Central Oklahoma State University in 1979, and
his Masters of Business from the University of Oklahoma in 1987. Mr. Smith is a Certified Public Accountant and a Certified Management Accountant.
TERRY K. SPENCER has been Vice President of Operations of the Company since 1991 and was elected to the Board of Directors of the Company in March 1997. He is responsible for the management of pipeline and plant operations, engineering design and construction, new project development, reservoir engineering and economic evaluation. Prior to joining CNG in 1989, Mr. Spencer served as Manager of Project Development for Stellar Gas Company and held various engineering-related positions in Delhi Gas Pipeline Corporation. Mr. Spencer earned his Bachelor of Science degree in Petroleum Engineering from the University of Alabama in 1981.
WILLIAM W. PRITCHARD became a member of the Board of Directors of the Company and the Compensation and Audit Committees of the Board on August 6, 1997. Mr. Pritchard has more than 21 years of experience in the domestic and international oil and gas industry. Beginning in 1976, Mr. Pritchard assumed various managerial positions with Parker Drilling Company, a New York Stock Exchange company, serving its domestic and international operations, and in 1984 he became Vice President and General Counsel with Parker Drilling, positions he held until he concluded his tenure at Parker in 1996. Mr. Pritchard became Of Counsel to the law firm of Hall, Estill, Hardwick, Gable, Golden & Nelson P.C. ("Hall, Estill") in 1996 and his corporate practice focuses on acquisitions, contracts, securities law and other legal matters related to the oil and gas industry. Mr. Pritchard received a Bachelor of Arts from the University of Kansas and a Juris Doctorate from the University of Tulsa.
WILLIAM H. BAUCH became a member of the Board of Directors of the Company and the Compensation and Audit Committees on August 6, 1997. Mr. Bauch has been Managing Director in the corporate finance department of CIBC Oppenheimer Corp. (formerly Oppenheimer & Co., Inc.) since 1996. Prior to that, he was a Vice President in the investment banking department of Prudential Securities Incorporated from 1994 to 1996 and a Vice President with Jefferies & Company, Inc. from 1993 to 1994. He holds a Bachelors of Accountancy and Juris Doctorate degrees from the University of Mississippi and a Masters of Law degree from the New York University School of Law.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item will be provided pursuant to a definitive proxy statement or an amendment to this Form 10-K Annual Report pursuant to General Instruction G(3) of Form 10-K. Such information is incorporated by reference in this Form 10-K Annual Report pursuant to General Instruction G(3) of Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item will be provided pursuant to a definitive proxy statement or an amendment to this Form 10-K Annual Report pursuant to General Instruction G(3) of Form 10-K. Such information is incorporated by reference in this Form 10-K Annual Report pursuant to General Instruction G(3) of Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item will be provided pursuant to a definitive proxy statement or an amendment to this Form 10-K Annual Report pursuant to General Instruction G(3) of Form 10-K. Such information is incorporated by reference in this Form 10-K Annual Report pursuant to General Instruction G(3) of Form 10-K.
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:
- ---------------
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
(b) Reports on Form 8-K.
During the fourth quarter of 1996, the Company filed a Current Report on Form 8-K, dated December 9, 1996, reporting under Item 2 the acquisition, dated November 25, 1997 of Taurus Energy Corp.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONTINENTAL NATURAL GAS, INC.
By: /s/ GARY C. ADAMS ---------------------------------- Gary C. Adams Chairman of the Board and Chief Executive Officer
Date: March 30, 1998
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors Continental Natural Gas, Inc. and Subsidiaries
We have audited the accompanying consolidated balance sheets of Continental Natural Gas, Inc. and Subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of operations, shareholders' equity, and cash flows and the related financial statement schedule for the years ended December 31, 1997, 1996 and 1995. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Continental Natural Gas, Inc. and Subsidiaries as of December 31, 1997 and 1996, and the consolidated results of their operations and their cash flows for the years ended December 31, 1997, 1996 and 1995 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma March 27, 1998
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
The accompanying notes are an integral part of the consolidated financial statements.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of the consolidated financial statements.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
The accompanying notes are an integral part of the consolidated financial statements.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Supplemental disclosure of noncash investing and financing activities -- In 1997, 1996, and 1995, the Company incurred $1,115,000, $5,154,349 and $2,416,887, respectively, relating to capital lease obligations for the acquisition of equipment. In 1997, 586,847 shares of common stock were issued as a result of the conversion of 149 shares of convertible preferred stock. In 1996, the Company issued preferred stock and cancelled certain indebtedness to acquire the minority interest ownership of a partnership holding one of the Company's processing plants. Also in 1996, the Company redeemed 51 shares of preferred stock in exchange for the cancellation of indebtedness due from an affiliated entity.
The accompanying notes are an integral part of the consolidated financial statements.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS -- Continental Natural Gas, Inc. and Subsidiaries (the "Company") is involved principally in natural gas gathering, processing and marketing with operations principally in the central United States. The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and its investments in majority-owned partnerships.
CASH EQUIVALENTS -- The Company considers all highly liquid investments with maturities of three months or less at date of purchase to be cash equivalents.
INVENTORY -- Gas inventory is stated at the lower of market or average cost.
PROPERTY AND EQUIPMENT -- The Company's property and equipment is carried at cost and depreciated on the straight-line basis over their estimated useful lives ranging from 3 to 20 years. Gain or loss on disposal of such property and equipment is reflected in operations. Maintenance and repairs are charged to expense as incurred.
The carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable. Assets determined to be impaired based on undiscounted estimated future net cash flows are reduced to estimated fair value. No such reduction in the carrying value of assets has been reflected in the accompanying financial statements.
DEBT ISSUANCE COSTS -- Costs associated with obtaining financing are capitalized and amortized using the straight-line method over the term of the agreement.
REVENUE RECOGNITION -- Revenue is recognized when product is delivered or when services are rendered.
INCOME TAXES -- The Company accounts for income taxes utilizing Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," which requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.
EARNINGS PER SHARE -- In the fourth quarter of 1997, the Company adopted Financial Accounting Standards Board Statement of Financial Accounting Standards No. 128, Earnings per share ("FAS 128"), which requires the presentation of basic and diluted earnings per share (see Note 3). Earnings per share amounts for all previous periods presented have been restated to give effect to the application of FAS 128.
ACCOUNTING ESTIMATES -- The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2. ACQUISITION OF TAURUS ENERGY CORP.
On November 20, 1997, the Company acquired Taurus Energy Corp. for total acquisition costs of $42,150,000. The acquisition has been accounted for as a purchase and the results of Taurus Energy Corporation have been included in the accompanying consolidated financial statements, since the date of acquisition. The acquisition is summarized as following:
Unaudited summary pro forma results of operations for the Company, reflecting the above described acquisition as if it had occurred at the beginning of the years ended December 31, 1997 and December 31, 1996, are as follows, respectively; revenues, $380.1 million and $290.8 million; net income (loss), ($1,531,000) and $7,571,000; and net income (loss) per common share (diluted), $(.37) and $1.76. The pro forma results of operations are not necessarily indicative of the actual results of operations that would have occurred had the purchase actually been made at the beginning of the respective periods nor of the results which may occur in the future.
3. EARNINGS PER SHARE
The following data shows the amounts used in computing earnings per share for income before extraordinary item.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Options on 207,210 shares of common stock with an average exercise price of $7.47 were not included in the computation of diluted earnings per share for 1997 because their effect would have been antidilutive. Contingently issuable options on 204,000 shares of common stock with an exercise price of $.26 were not included in the computation of diluted earnings per share for 1997 and 1996 in accordance with the provisions of FAS 128.
4. RELATED PARTY TRANSACTIONS
In 1997, 1996 and 1995, the Company provided office space to an affiliated entity and billed it for rentals of $51,075, $40,399 and $40,399, respectively. The Company provided general and administrative services to affiliates and billed them $209,724, $218,253 and $265,351 in 1997, 1996 and 1995, respectively. Additionally, the Company in 1997, 1996 and 1995, was charged by affiliates $14,329, $190,366 and $36,786, respectively, for general and administrative expenses incurred on its behalf and $240,000, $210,000, and $138,000 in 1997, 1996, and 1995 for management services.
The Company purchased gas from Bird Creek Resources ("BCR"), an affiliated entity, totaling $278,161, $316,466 and $125,284 in 1997, 1996 and 1995, respectively. At December 31, 1996, the Company had accounts payable to BCR totaling $463,884. No such amounts were payable at December 31, 1997.
In 1996, the Company sold its oil and gas producing properties to an affiliated entity for approximately $308,000, which approximated book value. Revenues from these properties are included in other revenues and totaled $602,656, and $461,984 for the years ended December 31, 1996 and 1995, respectively.
The Company had natural gas sales totaling $20,097,807 and $12,049,421 in 1997 and 1996 to an affiliated entity, which gas was sold at the Company's cost plus $.02 in 1997 and at cost in 1996. Receivables at December 31, 1997 and 1996 related to these gas sales were $6,351,252 and $4,988,035. During 1996, the Company entered into futures contracts on behalf of another affiliate, with gains or losses or such contracts paid or billed to the affiliate. The Company also had advances receivable from other affiliates totaling $1,034,393 and $981,423 at December 31, 1997 and 1996 respectively.
At December 31, 1997 and 1996, notes receivable from affiliates related to a sale of a gathering system in prior years were $17,801. This note bears interest at 8% and is collateralized by the gathering system.
5. INVESTMENTS
The Company, through two limited partnerships of which it is the general partner, owns a 6.88% interest in a partnership which owns and operates a natural gas gathering system in Texas. The Company's ownership interest is accounted for using the equity method. Accordingly, during 1997, 1996 and 1995, the Company has recognized losses of $94,065, $136,196 and $82,769, respectively, from the investment.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. PROPERTY AND EQUIPMENT
Property and equipment at December 31, 1997 and 1996, consisted of:
7. LONG-TERM DEBT
Long-term debt at December 31, 1997 and 1996 consists of the following:
In November 1997, the Company entered into an Amended and Restated Credit Agreement. The Credit Agreement provides for a term loan facility of $75 million and a revolving credit facility of $25 million, of which up to $18 million may be utilized to support letters of credit. Letters of credit totaling $8.5 million were outstanding related to this credit facility at December 31, 1997. Interest rates under both the revolving facility and term facility are variable, at the Company's election, at: (i) up to 1/4% (depending upon the Company's financial performance) above the greater of (x) the arithmetic average of the prime rates announced by Chase Manhattan Bank, Citibank, N.A. and Morgan Guaranty Trust Company of New York or (y) the federal funds rate as published by the Federal Reserve Bank of New York plus 1/2%; or (ii) 1.375% to 2.5% (depending upon the Company's financial performance) above the London Interbank Offered Rate (LIBOR).
In December 1996, the Company obtained a new credit facility including a term loan of $39 million and a revolving credit facility of $25 million. Letters of credit totalling $6,885,990 were outstanding related to this credit facility at December 31, 1996. At December 31, 1996, no amount was outstanding on the revolving credit facility. Associated with obtaining the new credit facility, the Company retired its prior long-term debt and expensed the remaining unamortized debt issuance costs of $689,062, which expense (net of income taxes of $261,842) is classified as an extraordinary item in the statement of operations. This expense reduced basic and diluted earnings per share by $.12 and $.10, respectively, for the year ended December 31, 1996.
The debt under the agreements is collateralized by inventory, accounts receivable, property and equipment and other assets. The agreement includes various restrictive covenants including the maintenance of specified levels of working capital and net worth, limitations on the incurrence of additional indebtedness and limitations on dividends to shareholders, and includes a subjective acceleration clause. During 1997, the Company was not in compliance with certain covenants of its debt agreement, which were waived by the lender.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 1997, the aggregate amount of long-term debt is payable as follows: $7,500,000 in 1998; $13,500,000 in 1999; $10,000,000 in 2000; $10,000,000 in 2001 and $40,000,000 in 2002. Beginning in 1998, certain additional principal amounts may be due based on the Company's levels of operating cash flows as defined by the agreement.
8. CAPITAL LEASES
Property and equipment include the following property under capital leases at December 31:
Future minimum lease payments as of December 31, 1997 under capital leases are as follows:
9. CONTRACT ADVANCES
In December, 1996, the Company received contract advances totalling approximately $22.8 million related to commitments to sell natural gas and natural gas liquids. The advances did not bear interest and were paid in product delivered over approximately nine months beginning in January 1997.
10. INCOME TAXES
Components of income tax expense (benefit) for the years ended December 31, 1997, 1996 and 1995 are as follows:
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation of the income tax expense computed by applying the federal statutory rate to pre-tax income to the Company's effective income tax expense (benefit) is as follows:
Deferred tax assets and liabilities at December 31, 1997 and 1996 are comprised of the following:
At December 31, 1997, the Company had net operating loss carryforwards (NOLs) totaling approximately $42 million for regular tax purposes and $40 million for alternative minimum tax purposes. If not utilized, these carryforwards will expire from 2000 to 2012. Due to the lack of existing legal precedent with respect to the tax rules governing the Company's NOLs, both the availability of approximately $10 million the Company's NOLs and its prior utilization of NOLs (totaling approximately $34 million) may be challenged. Disallowance of the use of the NOLs would result in certain taxes associated with prior utilization of the NOLs being currently payable. In March of 1998, the Company received notification that the Internal Revenue Service plans to audit the Company's 1995 tax return.
Realization of the Company's deferred tax assets is dependent upon the generation of sufficient taxable income prior to the expiration of the NOLs and, for financial reporting purposes, the resolution of the matters noted above. Although realization is not assured, management believes it is more likely than not that the recorded net deferred tax asset will be realized. The amount of the deferred tax asset considered realizable could be increased or decreased by a material amount in the near-term pending resolution of these matters.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. COMMITMENTS AND CONTINGENCIES
The Company, in the ordinary course of business, enters into fixed price sales contracts of natural gas. At December 31, 1997, the Company had fixed price gas sales contracts for prices ranging between $1.92 and $3.25 for the period January 1, 1998 and July 31, 1999. At December 31, 1996, the Company had fixed price gas sales contracts for prices ranging between $1.83 and $2.46 for the period January 1, 1997 to August 31, 1998.
As of December 31, 1997, the Company has outstanding $8,486,300 of letters of credit from commercial banks related to its purchases and sales of gas and has pledged inventory, accounts receivable, property and equipment and other assets as collateral.
The Company occupies office space and maintains certain compressor equipment under operating leases and incurred rent expense of $2,001,000, $1,932,000 and $1,839,000 in 1997, 1996 and 1995, respectively. Future minimum rental payments under the terms of the leases are $917,171 in 1998; $224,039 in 1999; $218,326 in 2000; $213,644 in 2001; and $106,820 thereafter.
As of December 31, 1997, the Company was a defendant in litigation involving claims made by Colorado Interstate Gas ("CIG"). The case primarily involved claims made by CIG that the Company and Continental Hydrocarbons, Inc. ("CHI"), a former subsidiary of the Company, improperly withheld proceeds from the sale of NGLs processed at the Mocane Plant, and committed other wrongful acts, and, as a result, was liable to CIG for unspecified actual and punitive damages. In February 1998, the Company and CIG reached a settlement with respect to all such claims, agreeing to pay CIG $2 million in cash. Through September 30, 1997, the Company had established reserves of approximately $1.4 million in connection with CIG's claims. The Company incurred a $600,000 pre-tax charge to earnings in the fourth quarter of 1997 as a result of the settlement, which is included in other expense.
The Company is at various times a party to additional claims and involved in various other litigation and administrative proceedings arising in the normal course of business. The Company believes it is unlikely that the final outcome of any of the claims, litigation or proceedings discussed above to which the Company is a party would have a material adverse effect on the Company's financial position or results of operations.
12. PROFIT SHARING AND THRIFT PLAN
The Company participates with certain affiliates in a defined contribution plan (the "Plan") covering substantially all employees. Under the Plan provisions, the Company contributes 2% of each participant's annual salary, plus up to an additional 3% to match voluntary contributions by employees. Employees may make voluntary contributions of up to 10% of their annual compensation. The Company makes contributions to the Plan each pay period. Total expense for 1997, 1996 and 1995 was approximately $199,000, $141,500 and $106,000, respectively.
13. STOCK OPTIONS
During 1995, the Company granted certain employees phantom stock rights under which certain amounts would be due upon the occurrence of specified events. On February 28, 1996, these phantom stock rights were cancelled and certain members of management were granted stock options for 204,000 shares of common stock. These options become exercisable only if certain performance criteria of the Company are met during the years of 1997 through 1999. The options, if earned, are exercisable at $.26 per share and expire at March 31, 2000. The amount of the options exercisable may also be limited based on the fair value of the Company's common stock at the date of exercise. None of these options vested during 1997.
In June 1997, the Company approved the adoption of an Employee Stock Plan (the "Plan") whereby 600,000 shares of common stock were authorized for issuance under the Plan. Options to purchase
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
207,210 shares of common stock at a weighted average exercise price of $7.47 per share were granted on December 23, 1997, which options become exercisable in 25% increments on February 28, 1998, December 31, 1998, December 31, 1999 and December 31, 2000 and expire after 10 years from the original grant. The Company applies APB 25 in accounting for such stock options. Under this standard, compensation expense is recognized associated with these options as they are earned, based on the fair value of the Company's common stock at the dates they are granted. Accordingly, the Company has recognized approximately $33,000 of compensation expense and approximately $802,000 of unearned compensation. Such unearned compensation will be recognized as an expense over the vesting period of the options.
Based on the provisions of FASB No. 123, "Accounting for Stock-Based Compensation," the grant date fair value of options issued prior to 1997 are not material and, accordingly, disclosure of pro forma information as required by this standard has not been presented for 1996 and 1995. Had compensation been determined on the basis of fair value pursuant to FASB Statement No. 123, net income and earnings per share for 1997 would have been reduced as follows:
The above FASB Statement No. 123 pro forma disclosures are not necessarily representative of the effect FASB No. 123 will have in the pro forma disclosure of future years.
The fair value of each option granted is estimated using the Black-Scholes model. The Company's stock volatility was .25 in 1997 based on previous stock performance. Dividend yield was estimated to remain at zero with a risk free interest rate of 5.7 percent in 1997. Expected life ranged from 5 to 8 years depending on the vesting periods involved and the make up of participating employees. The aggregate fair value of options granted during 1997 under the Stock Option Plan was approximately $1,417,000.
14. SHAREHOLDERS' EQUITY
On January 1, 1996, the Company issued 200 shares of preferred stock in exchange for the minority interest ownership in the Beaver gas processing plant. As the minority interest ownership was held by affiliates of the Company with common ownership, the assets and liabilities associated with the acquired interest have been reflected at their historical amounts. Subsequently, the Company redeemed 51 shares of the preferred stock in exchange for cancellation of indebtedness owed the Company. Dividends on the preferred stock are cumulative from the date of issuance at a rate of 7 1/2% applied to the liquidation value. At December 31, 1996,
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
unpaid dividends totaling $587,250 had accumulated on the Preferred Stock, which dividends were paid in 1997. During 1997, all outstanding preferred stock was converted into 586,847 shares of common stock of the Company.
Also, on February 28, 1996, the Company sold 461,997 shares of common stock of the Company to certain members of Company Management for $100,000 payable in the form of notes receivable with interest at 8%. Based on the fair value of the Company's common stock at this date, compensation expense and a contribution of capital of $46,000 has been recognized in 1996.
On August 6, 1997 the Company completed its initial public offering selling, 2,115,000 shares of common stock for net proceeds of approximately $21.3 million.
15. FINANCIAL INSTRUMENTS
DERIVATIVES -- The Company enters into futures contracts and options related to its buying and selling of natural gas. Specifically, the Company hedges its cost of future purchases of natural gas associated with its fixed price sales commitments. At December 31, 1997, the Company had futures contracts to purchase natural gas totaling approximately $11.6 million for the period from January 1998 to July 1999. At December 31, 1996, the Company had futures contracts to purchase natural gas totaling approximately $6.5 million for the period from January of 1997 to April of 1998. Also at December 31, 1996, the Company had swap contracts whereby the Company had fixed its price with respect to future purchases of natural gas totaling approximately $7.2 million for the period of January of 1997 to August of 1997. At December 31, 1997 and 1996, the Company had deposits totaling $3,827,568 and $962,553, respectively, related to these contracts which are reflected as Accounts Receivable -- Other.
Gains or losses on futures contracts, swaps and options designated as hedges are reported as natural gas sales in the Consolidated Statement of Operations in the same period as the hedged sale of gas occurs. Gains or losses on futures contracts, swaps and options not designated as hedges are recognized as fluctuations occur in the value of the contracts. The effectiveness of hedges is measured by historical and probable future high correlation of changes in the fair value of the hedging instruments with changes in value of the hedged sale of gas. If correlation ceases to exist, hedge accounting is terminated with gains or losses recognized. To date, high correlation has always been achieved on the Company's hedge instruments. All futures contracts at December 31, 1997 and 1996 and swap contracts at December 31, 1996 were designated as hedges. Losses on futures contracts totalling approximately $1.0 million at December 31, 1997 and a gain on future contracts of $1.1 million at December 31, 1996, respectively, have been deferred. At December 31, 1996, the fair value of the swap contracts was approximately $2 million, which amount had also been deferred.
Additionally, the Company periodically enters into futures contracts on behalf of its gas purchasers, with gains or losses on such contracts paid or billed to these customers. At December 31, 1997 and 1996, such contracts were not material.
FAIR VALUE -- Based on the interest rates currently available to the Company for borrowings with similar terms and maturities, long-term debt and capital leases at December 31, 1997 and 1996 approximate fair value.
The estimated fair value of the contract advance liabilities at December 31, 1996, assuming repayment under the scheduled terms of the agreements, was approximately $24.3 million.
The fair value of the Company's futures at December 31, 1997 was a loss of $1.0 million. The fair value of the Company's futures positions and swaps at December 31, 1996 was approximately $1.1 million and $2 million, respectively.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
16. CONCENTRATIONS
Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trade receivables with a variety of companies located in the central United States. Such credit risk is considered by management to be limited due to the large number of customers comprising the Company's customer base. The Company performs ongoing credit evaluations of its customers and generally does not require collateral related to its receivables. The Company's derivative activities also subject it to credit risk. Such credit risk is considered by management to be limited based on its assessment of the financial strength of the individual counterparties to its derivative positions. Additionally, the Company had approximately $8,393,000 and $32,197,000 of cash balances in excess of federally insured limits with banks at December 31, 1997 and 1996, respectively.
In fiscal years 1996 and 1995, one customer accounted for approximately 12% and 23%, respectively, of consolidated revenues. At December 31, 1996, accounts receivable from this customer were $2,429,622. No individual customer accounted for greater than 10% of revenues for the year ended December 31, 1997.
17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table sets forth certain unaudited quarterly financial information for each of the Company's last two years.
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- ---------------
(1) Operating revenues less operating costs and expenses.
(2) Earnings per share are calculated independently for each quarter, and accordingly the sum of the four quarters may not equal the annual earnings per share amounts.
(3) Includes $600,000 loss on settlement of litigation.
18. SUBSEQUENT EVENTS
On January 23, 1998, the Company entered into an agreement with Gothic Energy Corporation ("Gothic") to acquire interests in four natural gathering systems and $6 million of Gothic Senior Redeemable Preferred Stock for a total purchase price of $12 million. The closing of these purchase transactions was consummated in January and March of 1998.
SCHEDULE II
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
ALLOWANCE FOR DOUBTFUL ACCOUNTS
S-1 INDEX TO EXHIBITS