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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997 OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 0-22867
CONTINENTAL NATURAL GAS, INC.
(Exact name of registrant as specified in its charter)
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OKLAHOMA 73-1198957
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1437 SOUTH BOULDER, SUITE 1250
TULSA, OKLAHOMA 74119
(Address of principal executive offices) (Zip Code)
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Registrant's telephone number, including area code (918) 582-4700
Securities registered pursuant to Section 12(b) of the Act:
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NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, par value $.01 per share NASDAQ
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Securities registered pursuant to Section 12(g) of the Act:
TITLE OF CLASS
Common Stock, par value $.01 per share
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K [ ].
The aggregate market value of the voting stock held by non-affiliates of
the registrant is $25,133,246.00 based on the March 24, 1998, NASDAQ closing
price of $10.25.
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the close of the latest practicable date.
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CLASS OUTSTANDING ON MARCH 24, 1998
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Common Stock, par value $.01 per share.............. 6,315,000
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DOCUMENTS INCORPORATED BY REFERENCE
The Registrant incorporates by reference in Part III of this Annual Report
portions of its Definitive Proxy Statement or an amendment to this 10-K to be
filed with the Commission within 120 days of December 31, 1997.
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CONTINENTAL NATURAL GAS, INC.
1997 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
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DESCRIPTION PAGE
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PART I
ITEM 1. Business.................................................... 1
General................................................... 1
Definitions............................................... 2
Development of the Business............................... 3
Acquisitions.............................................. 3
Natural Gas, NGL and Electricity Marketing................ 5
Recent Developments....................................... 5
Description of the Business............................... 6
Gathering and Processing.................................. 6
Sales and Marketing....................................... 9
Operational Risks and Insurance........................... 13
Competition............................................... 13
Governmental Regulation................................... 13
Environmental Matters..................................... 16
Employees................................................. 17
ITEM 2. Properties.................................................. 17
Gathering Systems and Processing Plants................... 17
Compression and Storage Facilities........................ 18
Corporate Offices......................................... 18
ITEM 3. Legal Proceedings........................................... 18
ITEM 4. Submission of Matters to a Vote of Security Holders......... 19
PART II
ITEM 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 19
ITEM 6. Selected Financial Data..................................... 20
ITEM 7. Management's Discussion and Analysis of Financial Condition
and Results
of Operations............................................... 22
Results of Operations..................................... 22
Liquidity and Capital Resources........................... 24
Financing Facilities...................................... 24
Seasonality............................................... 25
Forward-Looking Information............................... 25
ITEM 8. Financial Statements and Supplementary Data................. 27
ITEM 9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure.................................... 28
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PART III
ITEM 10. Directors and Executive Officers of the Registrant.......... 28
Executive Officers of the Company......................... 28
ITEM 11. Executive Compensation...................................... 29
ITEM 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 29
ITEM 13. Certain Relationships and Related Transactions.............. 29
PART IV
ITEM 14. Exhibits, Financial Statement Schedules, And Reports on Form
8-K......................................................... 30
Signatures................................................ 31
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PART I
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.
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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.
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"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.
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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.
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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.
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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
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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.
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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.
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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.
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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.
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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
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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
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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
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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
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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
15
<PAGE> 19
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.
16
<PAGE> 20
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:
<TABLE>
<CAPTION>
AVERAGE NATURAL AVERAGE NGL
ACQUIRED GAS THROUGHPUT PRODUCTION
OR PLACED DESIGN --------------- --------------------
INTO SERVICE CAPACITY
AS OF DECEMBER -------- 1997 1996 1997 1996
1997 MMCF/D MMCF/D MMCF/D MGAL/D MGAL/D
-------------- -------- ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
PROCESSING PLANTS
Beaver Plant........... 1990 105 70 65 180 158
Mocane Plant........... 1995 200 65 64 101 106
Spearman Plant......... 1997 40(1) 30 N/A 51(1) N/A
Laverne Plant(2)....... 1997 220(3) 51 N/A 108(3) N/A
Shackleford Plant...... 1997 30(4) 114 N/A 37(4) N/A
Hamlin Plant........... 1997 20(4) 74 N/A 61(4) N/A
GATHERING SYSTEMS
Beaver-Mocane
Gathering............ 1990 195 25 25 N/A N/A
Texas Gathering
Assets............... 1996 188 88 54 N/A N/A
Shackleford System..... 1997 50 11 N/A N/A N/A
Hamlin System.......... 1997 30 7.3 N/A N/A N/A
Vintage System......... 1997 16 6 N/A N/A N/A
</TABLE>
- ---------------
(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
17
<PAGE> 21
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. 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.
18
<PAGE> 22
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. 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. 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.
<TABLE>
<CAPTION>
STOCK PRICE
----------------------
HIGH LOW
---- ---
<S> <C> <C>
1997
Third Quarter............................................... $12 1/2 $11 1/8
Fourth Quarter.............................................. $12 7/8 $10 3/4
1998
First Quarter (through March 24, 1998)...................... $11 1/4 $ 7 3/8
</TABLE>
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.
19
<PAGE> 23
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."
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT WHERE OTHERWISE INDICATED)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues
Natural gas sales...................... $289,615 $208,779 $ 95,631 $100,477 $126,583
Natural gas liquids sales.............. 46,224 34,757 24,804 19,572 23,177
Gathering fees......................... 4,449 1,995 -- -- --
Other.................................. 330 1,130 763 260 1,308
-------- -------- -------- -------- --------
Total operating revenue........... 340,618 246,661 121,198 120,309 151,068
Operating costs and expenses
Cost of purchased natural gas.......... 318,283 225,535 107,642 111,038 137,560
Operating expenses..................... 7,096 5,978 4,366 3,930 5,530
General and administrative............. 7,560 5,623 3,840 3,601 3,847
Depreciation, depletion and
amortization......................... 4,089 2,854 1,367 1,505 1,741
-------- -------- -------- -------- --------
Total operating costs and
expenses........................ 337,028 239,990 117,215 120,074 148,678
Operating income.......................... 3,590 6,671 3,983 235 2,390
Other income (expense), net............... (5,479) (2,686) (1,047) 4,648 (1,028)
-------- -------- -------- -------- --------
Income (loss) before income taxes,
extraordinary item and cumulative effect
of accounting change...................... (1,889) 3,985 2,936 4,883 1,362
Income tax (expense) benefit................ 644 3,635 2,174 (127) (47)
-------- -------- -------- -------- --------
Income (loss) before extraordinary item and
cumulative effect of accounting change.... $ (1,245) $ 7,620 $ 5,110 $ 4,756 $ 1,315
======== ======== ======== ======== ========
Net income (loss)........................... $ (1,245) $ 7,193 $ 5,110 $ 4,756 $ 1,695
======== ======== ======== ======== ========
EARNINGS PER SHARE:
Basic:
Income (loss) before extraordinary item
and cumulative effect of accounting
change................................. $ (.31) $ 1.99 $ 1.61 $ 1.47 $ .40
Net income (loss)......................... (.31) 1.87 1.61 1.47 .52
Diluted:
Income (loss) before extraordinary item
and cumulative effect of accounting
change................................. (.31) 1.77 1.59 1.45 .40
Net income (loss)......................... (.31) 1.67 1.59 1.45 .52
Weighted average common shares outstanding:
Basic..................................... 4,739 3,536 3,151 3,194 3,194
Diluted................................... 4,739 4,307 3,185 3,258 3,217
</TABLE>
20
<PAGE> 24
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT WHERE OTHERWISE INDICATED)
<S> <C> <C> <C> <C> <C>
STATEMENT OF CASH FLOWS DATA:
Cash flows provided by (used in) operating
activities............................. $(29,946) $ 23,535 $ 8,825 $ 1,785 $ 12,787
Cash flows provided by (used in) investing
activities............................. (57,022) (30,459) (12,286) 10,188 (1,444)
Cash flows provided by (used in) financing
activities............................. 67,127 23,345 2,325 (7,800) (10,325)
OTHER DATA:
Capital expenditures(1)................... $ 57,065 $ 30,761 $ 12,311 $ 3,097 $ 2,267
EBITDA(2)................................. 7,679 9,525 5,350 1,739 4,132
Natural gas throughput gathered and/or
processed (MMcf/d)..................... 253 182 125 95 93
NGLs production (Mgal/d).................. 349 264 265 249 251
Average NGL price (per gal)............... $ .33 $ .36 $ .26 $ .22 $ .26
BALANCE SHEET DATA:
Property, plant and equipment (net)....... $114,785 $ 61,045 $ 28,346 $ 13,554 $ 22,231
Total assets.............................. 178,934 145,929 58,099 35,264 46,298
Long-term debt, excluding current
portion................................ 73,500 32,946 6,534 3,750 5,626
Capital lease obligations, excluding
current portion........................ 6,226 6,583 2,745 954 2,554
Shareholders' equity...................... 41,419 22,153 16,754 12,153 7,397
</TABLE>
- ---------------
(1) Includes the acquisition of Taurus Energy in 1997.
(2) See definitions Section in this annual report.
21
<PAGE> 25
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.
22
<PAGE> 26
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.
23
<PAGE> 27
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:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Net cash provided by (used in) Operating
activities....................................... $(29,946) $ 23,535 $ 8,825
Net cash provided by (used in) Investing
activities....................................... $(57,022) $(30,459) $(12,286)
Net cash provided by (used in) Financing
activities....................................... $ 67,127 $ 23,345 $ 2,325
</TABLE>
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
24
<PAGE> 28
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.
25
<PAGE> 29
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.
26
<PAGE> 30
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. FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
Reference is made to the consolidated financial statements, the report
thereon and the notes thereto attached hereto as pages F-1 through F-16, which
are hereby incorporated by reference.
27
<PAGE> 31
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
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.
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Gary C. Adams......................... 47 Chairman, President, Chief Executive
Officer and Director(1)
Terry K. Spencer...................... 37 Vice President of Operations and
Director
Scott C. Longmore..................... 38 Vice President of Marketing and
Director
Garry D. Smith........................ 40 Vice President, Controller and
Director(2)
William W. Pritchard.................. 47 Director(1)(2)
William H. Bauch...................... 36 Director(1)(2)
</TABLE>
- ---------------
(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
28
<PAGE> 32
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. 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. 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. 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.
29
<PAGE> 33
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
<TABLE>
<CAPTION>
PAGE(S)
-------
<S> <C> <C>
(1) Continental Natural Gas, Inc. and Subsidiaries Consolidated
Financial Statements:
Report of Independent Public Accountants F-1
Consolidated Balance Sheets as of December 31, 1997 and 1996 F-2
Consolidated Statements of Operations for the years ended F-3
December 31, 1997, 1996 and 1995
Consolidated Statements of Stockholders' Equity for the F-4
years ended December 31, 1997, 1996 and 1995
Consolidated Statements of Cash Flows for the years ended F-5
December 31, 1997, 1996 and 1995
Notes to Consolidated Financial Statements F-6
(2) Financial Statement Schedules:
Continental Natural Gas, Inc. and Subsidiaries
Schedule II -- Valuation and Qualifying Accounts and S-1
Reserves
</TABLE>
- ---------------
All other schedules are omitted because they are not applicable or the required
information is shown in the financial statements or notes thereto.
<TABLE>
<S> <C> <C>
(3) List of Exhibits:
Incorporated herein by reference to the Index to Exhibits.
</TABLE>
(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.
30
<PAGE> 34
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ GARY C. ADAMS Chairman, President, Chief March 30, 1998
- ----------------------------------------------------- Executive Officer and
Gary C. Adams Director
/s/ SCOTT C. LONGMORE Vice President, Marketing and March 30, 1998
- ----------------------------------------------------- Director
Scott C. Longmore
/s/ GARRY D. SMITH Vice President, Chief March 30, 1998
- ----------------------------------------------------- Financial Officer and
Garry D. Smith Director
/s/ TERRY K. SPENCER Vice President, Operations March 30, 1998
- ----------------------------------------------------- and Director
Terry K. Spencer
/s/ WILLIAM W. PRITCHARD Director March 30, 1998
- -----------------------------------------------------
William W. Pritchard
/s/ WILLIAM H. BAUCH Director March 30, 1998
- -----------------------------------------------------
William H. Bauch
</TABLE>
31
<PAGE> 35
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
F-1
<PAGE> 36
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1997 1996
------------ ------------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................. $ 1,236,723 $ 21,077,438
Accounts receivable:
Trade, net of allowance for doubtful accounts of
$328,323 and $257,619.................................. 38,183,944 44,930,884
Affiliates.............................................. 7,385,645 5,969,458
Other................................................... 5,532,958 1,150,334
Notes receivable -- affiliates............................ 17,801 17,801
Gas inventory............................................. 1,679,609 3,148,657
Prepaid expenses.......................................... 240,424 164,085
------------ ------------
Total current assets...................................... 54,277,104 76,458,657
Investments (Note 5)........................................ 527,156 655,589
Property and equipment, net (Note 6)........................ 114,785,016 61,045,047
Deferred tax asset.......................................... 7,683,000 7,075,000
Other assets................................................ 1,661,631 694,305
------------ ------------
Total assets................................................ $178,933,907 $145,928,598
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities.................. $ 48,754,852 $ 56,707,979
Affiliate payables........................................ -- 463,884
Contract advances......................................... -- 24,787,831
Current portion of long-term debt......................... 7,500,000 867,000
Current portion of capital lease obligations.............. 1,402,393 1,165,361
------------ ------------
Total current liabilities................................. 57,657,245 83,992,055
Long-term debt.............................................. 73,500,000 32,945,500
Capital lease obligations................................... 6,225,531 6,583,478
Deferred gain on sale-leaseback............................. 132,160 254,154
------------ ------------
Total liabilities........................................... 137,514,936 123,775,187
Commitments and contingencies (Notes 8, 10 and 11)
Shareholders' equity (Note 14):
Preferred stock, $.01 par value, 5,000,000 shares
authorized, none issued................................. -- --
Convertible preferred stock, $1 par value, $40,000
liquidation value, 200 shares authorized, none issued
and outstanding in 1997 and 149 shares issued and
outstanding in 1996..................................... -- 149
Common stock, $.01 par value, 60,000,000 shares authorized
and 6,621,003 shares issued in 1997 and 3,919,156 issued
in 1996................................................. 66,210 39,191
Additional paid-in capital................................ 34,472,280 12,375,528
Retained earnings......................................... 7,987,085 10,042,763
Treasury stock, at cost................................... (204,220) (204,220)
Receivable from stock sale................................ (100,000) (100,000)
Unearned compensation associated with stock options....... (802,384) --
------------ ------------
Total shareholders' equity................................ 41,418,971 22,153,411
------------ ------------
Total liabilities and shareholders' equity.................. $178,933,907 $145,928,598
============ ============
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
F-2
<PAGE> 37
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Natural gas sales........................................... $269,517,385 $196,729,349 $ 95,630,817
Natural gas sales -- related party.......................... 20,097,807 12,049,421 --
Natural gas liquids sales................................... 46,223,919 34,757,184 24,803,858
Gathering fees.............................................. 4,449,071 1,994,711 --
Other....................................................... 329,401 1,130,751 762,770
------------ ------------ ------------
Total operating revenue..................................... 340,617,583 246,661,416 121,197,445
------------ ------------ ------------
Operating costs and expenses:
Cost of purchased gas..................................... 318,283,337 225,535,172 107,641,631
Operating expenses........................................ 7,095,801 5,977,953 4,366,125
General and administrative................................ 7,559,512 5,622,871 3,840,084
Depreciation, depletion and amortization.................. 4,089,037 2,854,624 1,366,544
------------ ------------ ------------
Total operating costs and expenses........................ 337,027,687 239,990,620 117,214,384
------------ ------------ ------------
Operating income............................................ 3,589,896 6,670,796 3,983,061
------------ ------------ ------------
Other income (expense):
Interest income........................................... 527,415 131,947 309,832
Equity in loss of investee................................ (94,065) (136,196) (82,769)
Interest expense.......................................... (5,265,889) (2,702,304) (914,331)
Minority interest......................................... -- -- (403,872)
Other, net................................................ (646,285) 20,827 43,726
------------ ------------ ------------
Total other income (expense).............................. (5,478,824) (2,685,726) (1,047,414)
------------ ------------ ------------
Income (loss) before income taxes and extraordinary item.... (1,888,928) 3,985,070 2,935,647
Income tax benefit.......................................... 644,000 3,635,210 2,174,304
------------ ------------ ------------
Income (loss) before extraordinary item..................... (1,244,928) 7,620,280 5,109,951
Extraordinary loss on retirement of debt (net of income
taxes of $261,842)........................................ -- (427,220) --
------------ ------------ ------------
Net income(loss)............................................ $ (1,244,928) $ 7,193,060 $ 5,109,951
============ ============ ============
Basic earnings per share:
Income (loss) before extraordinary item................... $ (.31) $ 1.99 $ 1.61
============ ============ ============
Net income(loss).......................................... $ (.31) $ 1.87 $ 1.61
============ ============ ============
Diluted earnings per share:
Income (loss) before extraordinary item................... $ (.31) $ 1.77 $ 1.59
============ ============ ============
Net income(loss).......................................... $ (.31) $ 1.67 $ 1.59
============ ============ ============
Weighted average common shares outstanding:
Basic..................................................... 4,738,922 3,536,176 3,151,156
Diluted................................................... 4,738,922 4,306,897 3,185,428
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
F-3
<PAGE> 38
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
NUMBER OF SHARES RECEIVABLE
-------------------------------- ADDITIONAL RETAINED FROM
PREFERRED COMMON TREASURY PREFERRED COMMON PAID-IN EARNINGS TREASURY STOCK
STOCK STOCK STOCK STOCK STOCK CAPITAL (DEFICIT) STOCK SALE
--------- --------- -------- --------- ------- ----------- ----------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Balance at December
31, 1994............ 1,000 3,457,159 263,435 $ 315,000 $34,571 $12,034,314 $ (74,020) $(156,470) $
Acquisition of
preferred
stock............... (1,000) (315,000)
Purchase of treasury
stock............. 42,568 (47,750)
Common stock dividends
($.01 per share).... (24,217)
Preferred stock
dividends ($122.06
per share).......... (122,062)
Net income............ 5,109,951
------ --------- ------- --------- ------- ----------- ----------- --------- ---------
Balance at December
31, 1995............ 3,457,159 306,003 34,571 12,034,314 4,889,652 (204,220)
Issuance of preferred
stock............... 200 200 199,834
Sale of common stock
to management (Note
14)................. 461,997 4,620 141,380 (100,000)
Redemption of
preferred
stock............... (51) (51) (2,039,949)
Net income............ 7,193,060
------ --------- ------- --------- ------- ----------- ----------- --------- ---------
Balance at December
31, 1996............ 149 3,919,156 306,003 149 39,191 12,375,528 10,042,763 (204,220) (100,000)
Preferred stock
dividends ($5,441
per share).......... (810,750)
Conversion of
preferred stock..... (149) 586,847 (149) 5,869 (5,720)
Sale of common
stock............... 2,115,000 21,150 21,266,916
Grant of stock
options............. 835,556
Net loss.............. (1,244,928)
------ --------- ------- --------- ------- ----------- ----------- --------- ---------
Balance at December
31, 1997............ -- 6,621,003 306,003 -- $66,210 $34,472,280 $ 7,987,085 $(204,220) $(100,000)
====== ========= ======= ========= ======= =========== =========== ========= =========
<CAPTION>
UNEARNED
COMPENSATION
ASSOCIATED
WITH STOCK
OPTIONS TOTAL
------------ -----------
<S> <C> <C>
Balance at December
31, 1994............ $12,153,395
Acquisition of
preferred
stock............... (315,000)
Purchase of treasury
stock............. (47,750)
Common stock dividends
($.01 per share).... (24,217)
Preferred stock
dividends ($122.06
per share).......... (122,062)
Net income............ 5,109,951
----------- -----------
Balance at December
31, 1995............ 16,754,317
Issuance of preferred
stock............... 200,034
Sale of common stock
to management (Note
14)................. 46,000
Redemption of
preferred
stock............... (2,040,000)
Net income............ 7,193,060
----------- -----------
Balance at December
31, 1996............ 22,153,411
Preferred stock
dividends ($5,441
per share).......... (810,750)
Conversion of
preferred stock..... --
Sale of common
stock............... 21,288,066
Grant of stock
options............. (802,384) 33,172
Net loss.............. (1,244,928)
----------- -----------
Balance at December
31, 1997............ $ (802,384) $41,418,971
=========== ===========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
F-4
<PAGE> 39
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)......................................... $ (1,244,928) $ 7,193,060 $ 5,109,951
------------ ------------ ------------
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization................ 4,089,037 2,854,624 1,366,544
Amortization of debt issuance costs..................... 176,505 269,697 128,473
Gain on disposition of assets........................... (121,994) (133,945) (123,793)
Minority interest....................................... -- -- 403,872
Equity in loss of investee.............................. 94,065 136,196 82,769
Deferred income tax benefit............................. (644,000) (4,213,158) (2,220,000)
Noncash compensation on stock issuance.................. -- 46,000 --
Noncash compensation on grant of stock options.......... 33,172
Extraordinary loss on retirement of debt................ -- 427,220 --
Changes in operating assets and liabilities:
Accounts receivable................................... 5,674,543 (35,408,754) (6,716,615)
Gas inventory......................................... 1,469,048 (2,263,410) 85,070
Prepaid expenses...................................... (39,001) (102,979) (42,424)
Accounts payable and accrued liabilities.............. (14,644,628) 31,899,220 11,508,016
Contract advances..................................... (24,787,831) 22,831,776 (756,534)
------------ ------------ ------------
Total adjustments................................... (28,701,084) 16,342,487 3,715,378
------------ ------------ ------------
Net cash provided by (used in) operating activities....... (29,946,012) 23,535,547 8,825,329
------------ ------------ ------------
Cash flows from investing activities:
Capital expenditures...................................... (15,065,245) (30,761,492) (12,310,634)
Acquisition of Taurus Energy Corp......................... (42,000,000) -- --
Proceeds from sale of property and equipment.............. 9,054 308,000 7,000
(Increase) decrease in investments........................ 34,368 (5,361) 54,852
(Increase) decrease in notes receivable --
affiliate............................................... -- -- 98
(Increase) decrease in other assets....................... -- -- (37,500)
------------ ------------ ------------
Net cash used in investing activities..................... (57,021,823) (30,458,853) (12,286,184)
------------ ------------ ------------
Cash flows from financing activities:
Preferred dividends paid.................................. (810,750) -- (146,279)
Sale of common stock...................................... 21,288,066 -- --
Purchase of preferred and Treasury Stock.................. -- -- (362,750)
Principal payments on long-term debt...................... (39,208,402) (45,903,667) (11,125,868)
Proceeds of long-term debt................................ 86,395,902 70,466,167 14,750,000
Cash overdrafts........................................... 1,842,050 -- --
Purchase of warrants...................................... -- -- (315,000)
Debt issuance costs....................................... (1,143,831) (523,688) (141,716)
Principal payments under capital lease obligations........ (1,235,915) (693,935) (333,074)
------------ ------------ ------------
Net cash provided by financing activities................. 67,127,120 23,344,877 2,325,313
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents...... (19,840,715) 16,421,571 (1,135,542)
Cash and cash equivalents at beginning of year............ 21,077,438 4,655,867 5,791,409
------------ ------------ ------------
Cash and cash equivalents at end of year.................. $ 1,236,723 $ 21,077,438 $ 4,655,867
============ ============ ============
Supplemental disclosure of cash flow information:
Interest paid........................................... $ 5,265,889 $ 2,472,515 $ 745,967
============ ============ ============
Income taxes paid....................................... $ 520,000 $ 100,000 $ 100,000
============ ============ ============
</TABLE>
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.
F-5
<PAGE> 40
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.
F-6
<PAGE> 41
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:
<TABLE>
<S> <C>
Current assets.............................................. $ 4,763,752
Gas gathering systems....................................... 42,267,910
Current liabilities......................................... (4,881,662)
-----------
Total acquisition................................. $42,150,000
===========
</TABLE>
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.
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31, 1997
------------------------------------------------
LOSS WEIGHTED SHARES
(NUMERATOR) (DENOMINATOR) PER-SHARE AMOUNT
----------- --------------- ----------------
<S> <C> <C> <C>
Loss before extraordinary item........... $(1,244,928)
Less: Preferred stock dividends.......... (223,500)
-----------
Basic earnings per common share.......... $(1,468,428) 4,738,922 $(.31)
=====
Diluted earnings per common share........ $(1,468,428) 4,738,922 $(.31)
=========== ========= =====
</TABLE>
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31, 1996
------------------------------------------------
INCOME WEIGHTED SHARES
(NUMERATOR) (DENOMINATOR) PER-SHARE AMOUNT
----------- --------------- ----------------
<S> <C> <C> <C>
Income before extraordinary item.......... $7,620,280
Less: Preferred stock dividends........... (587,250)
----------
Basic earnings per common share........... $7,033,030 3,536,176 $1.99
=====
Convertible preferred stock............... 587,250 770,721
---------- ----------
Diluted earnings per common share......... $7,620,280 4,306,897 $1.77
========== ========== =====
</TABLE>
F-7
<PAGE> 42
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31, 1995
------------------------------------------------
INCOME WEIGHTED SHARES
(NUMERATOR) (DENOMINATOR) PER-SHARE AMOUNT
----------- --------------- ----------------
<S> <C> <C> <C>
Income before extraordinary item......... $ 5,109,951
Less: Preferred stock dividends.......... (47,250)
-----------
Basic earnings per common share.......... $ 5,062,701 3,151,156 $1.61
=====
Warrants................................. 34,272
----------- ----------
Diluted earnings per common share........ $ 5,062,701 3,185,428 $1.59
=========== ========== =====
</TABLE>
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.
F-8
<PAGE> 43
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:
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Gathering systems and processing plants................. $111,484,065 $ 55,722,149
Compressor equipment.................................... 11,765,463 10,162,571
Furniture, fixtures and other........................... 1,806,788 1,342,984
Less accumulated depreciation, depletion and
amortization.......................................... (10,271,300) (6,182,657)
------------ ------------
Net property and equipment.............................. $114,785,016 $ 61,045,047
============ ============
</TABLE>
7. LONG-TERM DEBT
Long-term debt at December 31, 1997 and 1996 consists of the following:
<TABLE>
<CAPTION>
1997 1996
----------- -----------
<S> <C> <C>
Term loan payable in quarterly installments with a final
maturity in 2002, plus interest at either the bank's
base rate plus .5% or LIBOR plus 2.5% (7.69% at December
31, 1997)............................................... $75,000,000 $33,812,500
Revolving loan payable on December 31, 1999, plus interest
at either the bank's base rate plus .5% or LIBOR plus
2.5% (8.5% at December 31, 1997)........................ 6,000,000 --
Less current portion...................................... (7,500,000) (867,000)
----------- -----------
Long-term debt............................................ $73,500,000 $32,945,500
=========== ===========
</TABLE>
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.
F-9
<PAGE> 44
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:
<TABLE>
<CAPTION>
1997 1996
----------- ----------
<S> <C> <C>
Compressor equipment....................................... $10,220,306 $9,105,261
Less accumulated amortization.............................. (1,131,636) (616,643)
----------- ----------
$ 9,088,670 $8,488,618
=========== ==========
</TABLE>
Future minimum lease payments as of December 31, 1997 under capital leases
are as follows:
<TABLE>
<S> <C>
1998........................................................ $ 2,017,029
1999........................................................ 1,692,929
2000........................................................ 1,661,752
2001........................................................ 1,661,752
2002........................................................ 1,546,229
Thereafter.................................................. 1,017,412
-----------
Future minimum lease payments............................... 9,597,103
Less amount representing interest........................... (1,969,179)
-----------
Present value of future minimum lease payments.............. 7,627,924
Less current portion........................................ (1,402,393)
-----------
Long-term portion........................................... $ 6,225,531
===========
</TABLE>
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:
<TABLE>
<CAPTION>
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Current..................................... $ -- $ 577,948 $ 45,696
Deferred.................................... (644,000) (4,213,158) (2,220,000)
----------- ----------- -----------
$ (644,000) $(3,635,210) $(2,174,304)
=========== =========== ===========
</TABLE>
F-10
<PAGE> 45
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:
<TABLE>
<CAPTION>
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Income tax expense computed by applying
statutory rate............................ (642,235) $ 1,354,924 $ 998,120
State income taxes.......................... (75,557) 159,403 117,425
Other....................................... 73,792 29,506 18,825
Benefit of net operating loss
carryforward.............................. -- (965,885) (1,088,674)
Change in valuation allowance associated
with deferred tax assets.................. -- (4,213,158) (2,220,000)
----------- ----------- -----------
Income tax expense (benefit)................ (644,000) $(3,635,210) $(2,174,304)
=========== =========== ===========
</TABLE>
Deferred tax assets and liabilities at December 31, 1997 and 1996 are
comprised of the following:
<TABLE>
<CAPTION>
1997 1996
----------- -----------
<S> <C> <C>
Deferred tax assets:
Allowance for losses and other.......................... $ 250,712 $ 158,503
Deferred gain on sale leaseback......................... 50,220 96,579
Contract advances....................................... -- 9,419,375
Net operating loss carryforwards........................ 16,202,177 4,448,500
Deferred gain on futures contracts...................... -- 411,573
Alternative minimum tax credit carryforwards............ 768,061 773,851
----------- -----------
Total deferred tax assets............................... 17,271,170 15,308,381
----------- -----------
Deferred tax liabilities:
Depreciation of property and equipment.................. (3,211,487) (2,225,498)
Deferred loss on futures contracts...................... (368,800) --
----------- -----------
Total deferred tax liabilities............................ (3,580,287) (2,225,498)
----------- -----------
Valuation allowance....................................... (6,007,883) (6,007,883)
----------- -----------
Net deferred tax asset.................................... $ 7,683,000 $ 7,075,000
=========== ===========
</TABLE>
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.
F-11
<PAGE> 46
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
F-12
<PAGE> 47
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:
<TABLE>
<CAPTION>
1997
------
<S> <C>
Net Loss (In thousands):
As reported............................................... $1,245
------
Pro Forma................................................. $1,267
------
Basic Earnings per Share:
As reported............................................... $ (.31)
------
Pro forma................................................. $ (.31)
------
Diluted Earnings per Share:
As reported............................................... $ (.31)
------
Pro Forma................................................. $ (.31)
======
</TABLE>
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.
<TABLE>
<CAPTION>
OUTSTANDING OPTIONS
------------------------------------------------------
WEIGHTED AVERAGE
REMAINING WEIGHTED AVERAGE
EXERCISE PRICES NUMBER OF SHARES CONTRACTUAL LIFE EXERCISE PRICE
- --------------- ---------------- ---------------- ----------------
<S> <C> <C> <C>
$ 6.00 - $ 8.00 176,210 10 $ 6.78
$11.25 - $11.75 31,000 10 $11.41
</TABLE>
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,
F-13
<PAGE> 48
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.
F-14
<PAGE> 49
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.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
---------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
----------- ---------- ----------- ----------
(IN THOUSANDS, EXCEPT WHERE OTHERWISE INDICATED)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1997:
STATEMENTS OF OPERATIONS DATA:
Operating revenues................. $88,527 $66,329 $81,762 $104,000
Operating income(1)................ 2,810 946 905 (1,071)
Net income (loss).................. 987 (140) (118) (1,974)(3)
EARNINGS PER SHARE(2):
Basic:
Net income (loss).................. .24 (.07) (.02) (.31)
Diluted:
Net income (loss).................. .23 (.07) (.02) (.31)
</TABLE>
<TABLE>
<CAPTION>
THREE MONTHS ENDED
---------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
----------- ---------- ----------- ----------
(IN THOUSANDS, EXCEPT WHERE OTHERWISE INDICATED)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1996:
STATEMENTS OF OPERATIONS DATA:
Operating revenues................. $39,320 $42,066 $61,034 $104,241
Operating income(1)................ 1,662 446 774 3,789
Income (loss) before extraordinary
item............................. 1,368 (157) (34) 6,443
Net income (loss).................. 1,368 (157) (34) 6,016
EARNINGS PER SHARE(2):
Basic:
Income (loss) before extraordinary
item............................. .37 (.08) (.05) 1.75
Net income (loss).................. .37 (.08) (.05) 1.63
Diluted:
Income (loss) before extraordinary
item............................. .33 (.08) (.05) 1.49
Net income (loss).................. .33 (.08) (.05) 1.39
</TABLE>
F-15
<PAGE> 50
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.
F-16
<PAGE> 51
SCHEDULE II
CONTINENTAL NATURAL GAS, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
ALLOWANCE FOR DOUBTFUL ACCOUNTS
<TABLE>
<CAPTION>
ADDITIONS
-----------------------
CHARGED
BALANCE AT CHARGED TO TO OTHER DEDUCTIONS BALANCE
BEGINNING COSTS AND ACCOUNTS AND NET AT END OF
DESCRIPTION OF PERIOD EXPENSES RECOVERIES WRITE-OFFS PERIOD
----------- ---------- ---------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1995................ $323 $-- $-- $(70) $253
Year ended December 31, 1996................ $253 $-- $5 $ -- $258
Year ended December 31, 1997................ $258 $70 $-- $ -- $328
</TABLE>
S-1
<PAGE> 52
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT NO. NAME OF EXHIBIT
- ----------- ---------------
<S> <C>
3.1 Amended and Restated Certificate of Incorporation of the Registrant (Incorporated by reference herein
to Exhibit 3.1 to Registration Statement of S-1, File No. 333-25719).
3.2 Amended and Restate Bylaws of the Registrant (Incorporated by reference herein to Exhibit 3.2 to
Registration Statement of S-1, File No. 333-25719).
10.1 Second Restated Employment Agreement between the Registrant and Garry D. Smith to be dated as of the
effective date of this Registration Statement (Incorporated by reference herein to Exhibit 10.1 to
Registration Statement of S-1, File No. 333-25719).1
10.2 Second Restated Employment Agreement between the Registrant and Terry K. Spencer to be dated as of the
effective date of this Registration Statement (Incorporated by reference herein to Exhibit 10.2 to
Registration Statement of S-1, File No. 333-25719).1
10.3 Second Restated Employment Agreement between the Registrant and Scott C. Longmore to be dated as of the
effective date of this Registration Statement (Incorporated by reference herein to Exhibit 10.3 to
Registration Statement of S-1, File No. 333-25719).1
10.4 1997 Stock Plan (Incorporated by reference herein to Exhibit 10.4 to Registration Statement of S-1,
File No. 333-25719).1
10.5 Asset Purchase Agreement dated as of March 13, 1996, by and among Transwestern Gathering Company ("TW
Gathering") as Seller and Registrant as Buyer (Incorporated by reference herein to Exhibit 10.5 to
Registration Statement of S-1, File No. 333-25719).
10.6 Asset purchase Agreement dated as of March 22, 1996, by and among TW Gathering and Enron Gathering
Company ("Enron Gathering") as Sellers and Registrant as Buyer (Incorporated by reference herein to
Exhibit 10.6 to Registration Statement of S-1, File No. 333-25719).
10.7 Asset Purchase Agreement dated as of April 11, 1996, by and among TW Gathering and Enron Gathering as
Sellers and Registrant as Buyer (Incorporated by reference herein to Exhibit 10.7 to Registration
Statement of S-1, File No. 333-25719).
10.8 Contribution Agreement dated as of January 1, 1996, by and among Registrant, Cottonwood Partnership,
Continental Gas Marketing, Inc. and Gary Adams Ranch, Inc (Incorporated by reference herein to Exhibit
10.8 to Registration Statement of S-1, File No. 333-25719).
10.9 Office Lease Agreement (Incorporated by reference herein to Exhibit 10.9 to Registration Statement of
S-1, File No. 333-25719).
</TABLE>
<PAGE> 53
<TABLE>
<S> <C>
10.10 Credit Agreement between the Registrant and ING Capital Corporation dated December 30, 1996
(Incorporated by reference herein to Exhibit 10.10 to Registration Statement of S-1, File No. 333-
25719).
10.11 Letter of Credit and Reimbursement Agreement between the Registrant and Christiania Bank dated as of
December 27, 1996 (Incorporated by reference herein to Exhibit 10.11 to Registration Statement of S-1,
File No. 333-25719).
10.12 1996 Incentive Stock Option Plan (Incorporated by reference herein to Exhibit 10.12 to Registration
Statement of S-1, File No. 333-25719).
10.13 Agreement dated as of January 1, 1997, between the Registrant and Continental Natural Gas Marketing,
L.L.C. for the sale of natural gas to L.L.C. (Incorporated by reference herein to Exhibit 10.13 to
Registration Statement of S-1, File No. 333-25719).
10.14 Consulting Agreement dated as of April 1, 1997, between the Registrant and Adams Affiliates, Inc. for
the provision of management services by Adams Affiliates to the Registrant (Incorporated by reference
herein to Exhibit 10.14 to Registration Statement of S-1, File No. 333-25719).
10.15 Administrative Services Agreement dated as of April 1, 1997, between the Registrant and Adams
Affiliates, Inc. for the provision of administrative services by the Registrant to Adams Affiliates
(Incorporated by reference herein to Exhibit 10.15 to Registration Statement of S-1, File No. 333-
25719).
10.16 Administrative Services Agreement dated as of April 1, 1997, between the Registrant and Bird Creek
Resources, Inc. under which the Registrant will provide certain administrative services to Bird Creek
Resources, Inc. (Incorporated by reference herein to Exhibit 10.16 to Registration Statement of S-1,
File No. 333-25719).
10.17 Administrative Services Agreement dated as of April 1, 1997, between Bird Creek Resources, Inc. and the
Registrant under which Bird Creek Resources, Inc. will provide certain administrative services to the
Registrant. (Incorporated by reference herein to Exhibit 10.17 to Registration Statement of S-1, File
No. 333-25719).
10.18 Charter Services Agreement dated as of April 1, 1997, between the Registrant and CPA Aviation, Inc.
under which CPA Aviation will provide the Registrant with certain air transportation
services(Incorporated by reference herein to Exhibit 10.18 to Registration Statement of S-1, File No.
333-25719).
10.19 Agreement between the Registrant and Mapco Petroleum, Inc. for the sale of NGLs dated as of July 14,
1994 (Incorporated by reference herein to Exhibit 10.19 to Registration Statement of S-1, File No.
333-25719).
10.20 Amendment dated February 16, 1996, to Firm Throughput Service Agreement (CR# 101124) dated as of
January 26, 1996, between the Registrant and Northern Natural Gas Company ("NNG") together with the
original agreement (Incorporated by reference herein to Exhibit 10.20 to Registration Statement of S-
1, File No. 333-25719).
</TABLE>
<PAGE> 54
<TABLE>
<S> <C>
10.21 Amendments dated November 13, 1996, March 15, 1996, and March 14, 1996 to Transportation Service
Agreement - Form M (No: 24690) dated as of April 1, 1996, between Registrant and Transwestern Pipeline
Company ("TW"), together with the original agreement (Incorporated by reference herein to Exhibit
10.21 to Registration Statement of S-1, File No. 333-25719).
10.22 Amendment dated January 3, 1994, to Transportation Service Agreement No: 20606 dated November 26, 1991,
between Registrant and TW, together with the original agreement (Incorporated by reference herein to
Exhibit 10.22 to Registration Statement of S-1, File No. 333-25719).
10.23 Interconnect and Operating Agreement dated as of March 1, 1996, between Registrant and NNG
(Incorporated by reference herein to Exhibit 10.23 to Registration Statement of S-1, File No. 333-
25719).
10.24 Amendment dated February 16, 1996, to Firm Throughput service Agreement (CR# 101125) between the
Registrant and NNG dated January 26, 1996, together with the original agreement (Incorporated by
reference herein to Exhibit 10.24 to Registration Statement of S-1, File No. 333-25719).
10.25 Interruptible Transportation Service Agreement, Rate Schedule IT-1 between Registrant and NNG dated
August 1, 1992 (Incorporated by reference herein to Exhibit 10.25 to Registration Statement of S-1,
File No. 333-25719).
10.26 Interruptible Throughput Service Agreement, Rate Schedule TI, Throughput Agreement No. 22224, between
Registrant and NNG undated (Incorporated by reference herein to Exhibit 10.26 to Registration
Statement of S-1, File No. 333-25719).
10.27 Agreement and Plan of Merger dated November 24, 1997 by and among Coda Energy, Inc., Taurus Holdings
Corp., Continental Natural Gas, Inc., et al. (Incorporated by reference to Exhibit 2.1 to Current
Report on Form 8-K dated November 25, 1997, File No. 0-22867).
10.28 Amended and Restated Loan Agreement dated November 25, 1997 (Incorporated by reference to Exhibit 10.1
to Current Report on Form 8-K dated November 25, 1997, File No. 0-22867).
21.1 List of Subsidiaries
23.1 Consent of Coopers & Lybrand L.L.P.
27.1 Financial Data Schedules (Year ended December 31, 1997).
27.2 Restated Financial Data Schedules.
</TABLE>
<PAGE> 1
Exhibit 21.1
DESCRIPTION OF SUBSIDIARIES
<TABLE>
<CAPTION>
SUBSIDIARY CORPORATIONS
PARENT SUBSIDIARY INTEREST
- ------ ---------- --------
<S> <C> <C>
Continental Natural Gas, Inc. Continental Holdings Company 100%
Continental Natural Gas, Inc. Gothic Gas Corporation 100%**
SUBSIDIARY LIMITED LIABILITY COMPANIES
PARENT SUBSIDIARY INTEREST
- ------ ---------- --------
Continental Natural Gas, Inc. Continental Natural Gas 99% Ownership Interest*
Gathering, L.L.C.
Continental Natural Gas, Inc. Continental Hydrocarbons, L.L.C. 99% Ownership Interest*
Continental Natural Gas, Inc. Continental Gas Processing L.L.C. 99% Ownership Interest*
Continental Natural Gas, Inc. Continental Laverne Gas 99% Ownership Interest*
Processing, L.L.C.
Continental Natural Gas, Inc. Continental Spearman Gas 99% Ownership Interest*
Processing, L.L.C.
Continental Natural Gas, Inc. Continental Energy Services, 99% Ownership Interest*
L.L.C.
Continental Natural Gas, Inc. Continental/Oklahoma Natural Gas 99% Ownership Interest*
Gathering, L.L.C.
Continental Natural Gas, Inc. Continental Energy Services, L.L.C. 100% Ownership Interest
Continental Natural Gas, Inc. Continental/Taurus Holdings 100% Ownership Interest
Company, L.L.C.
SUBSIDIARY LIMITED PARTNERSHIP
Continental/Taurus Holdings Continental/Taurus Energy 99% Ownership Interest*
Company, L.L.C. Company, L.P.
(Delaware Limited Partnership)
</TABLE>
* Remaining one percent (1%) interest is held by Continental Holdings Company
** Acquired January 1998
Except as indicated all entities are organized in Oklahoma.
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements
of Continental Natural Gas, Inc. on Form S-8 (File No. 333-43015) of our report
dated March 27, 1998, on our audits of the consolidated financial statements and
financial statement schedule of Continental Natural Gas, Inc. as of December 31,
1997 and 1996, and for the years ended December 31, 1997, 1996 and 1995, which
report is included in this Annual Report on Form 10-K.
/s/ COOPERS & LYBRAND L.L.P.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma
March 30, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED CONDENSED FINANCIAL STATEMENTS OF CONTINENTAL NATURAL GAS, INC. AND
SUBSIDIARIES AND INCLUDES AMENDED FINANCIAL DATA SCHEDULES FOR PRIOR PERIODS
RESTATING EARNINGS PER SHARE DUE TO THE COMPANY'S ADOPTION OF SFAS NO. 128,
"EARNINGS PER SHARE".
</LEGEND>
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> 12-MOS 12-MOS
<FISCAL-YEAR-END> DEC-31-1997 DEC-31-1996
<PERIOD-END> DEC-31-1997 DEC-31-1996
<CASH> 1,237 21,077
<SECURITIES> 0 0
<RECEIVABLES> 51,120<F1> 52,326<F1>
<ALLOWANCES> 328 258
<INVENTORY> 1,680 3,149
<CURRENT-ASSETS> 54,277 76,459
<PP&E> 114,785 61,045
<DEPRECIATION> 114,785 61,045
<TOTAL-ASSETS> 178,934 145,928
<CURRENT-LIABILITIES> 57,657 83,992
<BONDS> 0 0
0 0
0 0
<COMMON> 66 39
<OTHER-SE> 41,353 22,114
<TOTAL-LIABILITY-AND-EQUITY> 178,934 145,928
<SALES> 340,288 245,530
<TOTAL-REVENUES> 340,618 246,661
<CGS> 318,283 225,535
<TOTAL-COSTS> 337,028 239,991
<OTHER-EXPENSES> 5,479 2,686
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 5,479 2,686
<INCOME-PRETAX> (1,889) 3,985
<INCOME-TAX> 644 3,635
<INCOME-CONTINUING> (1,245) 7,620
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 (427)
<CHANGES> 0 0
<NET-INCOME> (1,245) 7,193
<EPS-PRIMARY> (.31) 1.87
<EPS-DILUTED> (.31) 1.67
<FN>
<F1>ACCOUNTS RECEIVABLE IS PRESENTED NET IN THE CONSOLIDATED BALANCE SHEET.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED CONDENSED FINANCIAL STATEMENTS OF CONTINENTAL NATURAL GAS, INC. AND
SUBSIDIARIES AND INCLUDES AMENDED FINANCIAL DATA SCHEDULES FOR PRIOR PERIODS
RESTATING EARNINGS PER SHARE DUE TO THE COMPANY'S ADOPTION OF SFAS NO. 128,
"EARNINGS PER SHARE".
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C> <C> <C>
<PERIOD-TYPE> 3-MOS 6-MOS 9-MOS
<FISCAL-YEAR-END> DEC-31-1997 DEC-31-1997 DEC-31-1997
<PERIOD-END> MAR-30-1997 JUN-30-1997 SEP-30-1997
<CASH> 14,784 5,601 6,287
<SECURITIES> 0 0 0
<RECEIVABLES> 28,330 30,892<F1> 42,857<F1>
<ALLOWANCES> 288 259 259
<INVENTORY> 3,693 1,256 650
<CURRENT-ASSETS> 46,581 37,843 49,876
<PP&E> 0 73,492 69,898
<DEPRECIATION> 0 8,015 2,852
<TOTAL-ASSETS> 117,064 111,119 127,581
<CURRENT-LIABILITIES> 49,354 43,084 54,010
<BONDS> 0 0 0
0 0 0
0 0 0
<COMMON> 39 39 66
<OTHER-SE> 23,101 22,738 43,453
<TOTAL-LIABILITY-AND-EQUITY> 117,064 111,119 127,581
<SALES> 88,512 154,850 236,597
<TOTAL-REVENUES> 88,527 154,856 236,618
<CGS> 81,417 145,670 219,017
<TOTAL-COSTS> 85,717 151,100 231,957
<OTHER-EXPENSES> (295) (438) (555)
<LOSS-PROVISION> 0 0 0
<INTEREST-EXPENSE> 1,466 2,781 3,994
<INCOME-PRETAX> 1,638 1,413 1,222
<INCOME-TAX> 652 566 493
<INCOME-CONTINUING> 986 847 729
<DISCONTINUED> 0 0 0
<EXTRAORDINARY> 0 0 0
<CHANGES> 0 0 0
<NET-INCOME> 987 847 729
<EPS-PRIMARY> .24 .17 .12
<EPS-DILUTED> .23 .17 .11
<FN>
<F1>ACCOUNTS RECEIVABLE IS PRESENTED NET IN THE CONSOLIDATED BALANCE SHEET.
</FN>
</TABLE>
