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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
[ ] 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: 0-9808
PLAINS RESOURCES INC.
(Exact name of registrant as specified in its charter)
Delaware 13-2898764
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1600 Smith Street
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 654-1414
Securities registered pursuant to Section 12(b) of the Act:
Title of each class: Name of each exchange on which registered:
Common Stock, par value $.10 per share American Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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 the
filing requirements for the past 90 days. Yes X No
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The aggregate value of the Common Stock held by non-affiliates of the
registrant (treating all executive officers and directors of the registrant,
for this purpose, as if they may be affiliates of the registrant) was
approximately $246,133,643 on February 7, 1997 (based on $15 1/4 per share,
the last sale price of the Common Stock as reported on the American Stock
Exchange Composite Tape on such date).
16,537,324 shares of the registrant's Common Stock were outstanding as of
February 7, 1997.
DOCUMENTS INCORPORATED BY REFERENCE. The information required in Part III of
this Annual Report on Form 10-K is incorporated by reference to the
Registrant's definitive proxy statement to be filed pursuant to Regulation 14A
for the Registrant's Annual Meeting of Stockholders.
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. [ ]
===============================================================================
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PART I
Item 1. BUSINESS
Plains Resources Inc. (the "Company") is an independent energy company
engaged in the acquisition, exploitation, development, exploration and
production of crude oil and natural gas and the marketing, transportation,
terminalling and storage of crude oil. The Company's upstream oil and natural
gas activities are focused in the Los Angeles Basin of California (the "LA
Basin"), the Sunniland Trend of South Florida (the "Sunniland Trend"), the
Illinois Basin in southern Illinois (the "Illinois Basin") and the Gulf Coast
area of Louisiana. The Company's downstream marketing, terminalling and storage
activities are concentrated in Oklahoma, Texas and the Gulf Coast area of
Louisiana. Plains' upstream operations contributed approximately 90% of the
Company's Earnings before interest, taxes, depreciation, depletion and
amortization ("EBITDA") for the fiscal year ending December 31, 1996, while the
Company's downstream activities accounted for the remainder. References to the
Company in this Annual Report on Form 10-K (the "Report") include Plains
Resources Inc. and its subsidiaries, except as the context may otherwise
require.(1)
The Company's business strategy is to increase its proved reserves and
cash flow by exploiting and producing oil and natural gas from its existing
properties, acquiring additional underdeveloped oil properties and exploring
for significant new sources of reserves. The Company concentrates its
exploitation efforts on mature but underdeveloped crude oil producing
properties that meet the Company's targeted criteria. Generally, such
properties were previously owned by major integrated or large independent oil
and natural gas companies, have produced significant volumes since initial
discovery and have significant estimated remaining reserves in place.
Management believes that it has developed a proven record in acquiring and
exploiting underdeveloped crude oil properties where it believes substantial
reserve additions and cash flow increases can be made through improved
production practices and recovery techniques and relatively low risk
development drilling. An integral component of the Company's exploitation
effort is to increase unit operating margins, and therefore cash flow, by
reducing unit production expenses and increasing wellhead price realizations.
The Company seeks to complement these exploitation efforts by pursuing certain
higher risk exploration opportunities which offer potentially higher rewards.
In 1996, the Company formed a joint venture and five year strategic alliance
with 3DX Technologies Inc. ("3DX"), a publicly held company that specializes in
the application of 3-D seismic imaging, to pursue exploration projects. The
Company also seeks to capitalize on downstream opportunities that exist as a
result of inefficiencies within the crude oil markets and the U.S. pipeline and
transportation infrastructure. The Company's marketing of its own crude oil
production takes advantage of the marketing expertise attributable to its
downstream activities. As part of its business strategy, the Company
periodically evaluates, and from time to time has elected to sell, certain of
its mature producing properties that it considers to be nonstrategic or fully
valued. Such sales enable the Company to focus on its core properties, maintain
financial flexibility, control overhead and redeploy the sales proceeds to
activities that have potentially higher financial returns.
During the five-year period ended December 31, 1996, the Company
incurred aggregate acquisition, exploration, development and exploitation costs
of approximately $306.1 million, resulting in proved oil and natural gas
reserve additions (including revisions of estimates but excluding production)
of approximately 136.4 million BOE, or $2.24 BOE, through implementation of its
business strategy. See Item 2, "Properties--Oil and Natural Gas Reserves".
Approximately 87% of these expenditures were directed toward the acquisition,
exploitation and development of proved reserves while approximately 13% were
incurred on exploration activities.
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(1) As used in this Report, "Mcf" means thousand cubic feet, "MMcf" means
million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel,
"MBbl" means thousand barrels, "MMBbl" means million barrels, "Btu" means
British Thermal Unit, "MBtus" means thousand Btus, "BOE" means net barrel of
oil equivalent and "MCFE" means Mcf of natural gas equivalent. Natural gas
equivalents and crude oil equivalents are determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids. A "gross acre" is an acre in which an interest is owned. The number
of "net acres" is the sum of the fractional working interests owned in gross
acres. "Net" oil and natural gas wells are obtained by multiplying "gross"
oil and natural gas wells by the Company's working interest in the
applicable properties. "Present Value of Proved Reserves" means the present
value (discounted at 10%) of estimated future cash flows from proved oil and
natural gas reserves reduced by estimated future operating expenses,
development expenditures and abandonment costs (net of salvage value)
associated therewith (before income taxes), calculated using product prices
in effect on the date of determination, and "Standardized Measure" is such
amount further reduced by the present value (discounted at 10%) of estimated
future income taxes on such cash flows. "NYMEX" means New York Mercantile
Exchange.
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In order to manage its exposure to commodity price risk, the Company
routinely hedges a portion of its crude oil production. For 1997, the Company
has entered into various fixed price and floating price collar arrangements.
Such arrangements generally provide the Company with downside price protection
on approximately 14,000 barrels of oil per day at a NYMEX crude oil spot price
("NYMEX Crude Oil Price") of approximately $19.00 per barrel, but permit the
Company to receive the benefit of increases in the NYMEX Crude Oil Price up to
$24.00 per barrel on 4,000 of such barrels. Thus, based on the Company's average
fourth quarter 1996 oil production rate, these arrangements generally provide
the Company with downside price protection for 80% of its production and upside
price participation for 43% of its production up to $24.00 per barrel, while 20%
of such production and excess volumes, if any, remain unhedged. In addition, the
Company also has a fixed price arrangement on 4,500 barrels per day in 1998 at a
NYMEX Crude Oil Price of $19.24 per barrel. On February 7, 1997, the NYMEX Crude
Oil Price was $22.23 per barrel.
The following table sets forth certain information with respect to the
Company's reserves over the last five years. Such reserve volumes and values
were determined under the method prescribed by the Securities and Exchange
Commission (the " SEC"), which requires the application of year-end oil and
natural gas prices for each year, held constant throughout the projected
reserve life. See Item 2 "Properties--Oil and Natural Gas Reserves" and Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations".
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
1992 1993 1994 1995 1996
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT RATIOS AND PER UNIT AMOUNTS)
Present Value of Proved Reserves ................. $155,360 $134,539 $229,371 $366,780 $764,774(1)
Proved Reserves
Crude oil and natural gas
liquids (Bbls) ................................ 33,390 38,810 61,459 94,408 115,996
Natural gas (Mcf) .............................. 39,861 49,397 51,009 43,110 37,273
Oil equivalent (BOE) ........................... 40,034 47,043 69,960 101,593 122,208(1)
Reserve Replacement Ratio(2) ..................... 1,105% 269% 619% 647%(3) 454%
Reserve Replacement Cost per BOE ................. $ 2.35 $ 5.39 $ 1.49 $ 2.14 $ 1.76
Total upstream capital costs incurred ............ $ 68,209 $ 61,769 $ 40,849 $ 84,012 $ 51,255
Percentage of total upstream capital
costs attributable to:
Acquisition .................................... 56% 40% 48% 71% 7%
Development .................................... 17% 43% 38% 27% 88%
Exploration .................................... 27% 17% 14% 2% 5%
NYMEX Crude Oil Price
at December 31, ................................ $ 19.50 $ 14.17 $ 17.76 $ 19.55 $ 25.92
(1) By comparison, calculating these amounts using the NYMEX Crude Oil Price
in effect at December 31, 1995 ($19.55 per barrel) would result in a
Present Value of Proved Reserves of $452 million and estimated net proved
reserves of 112 million BOE.
(2) The Reserve Replacement Ratio is calculated by dividing (a) the sum of
reserves added during each respective year through purchases of reserves
in place, extensions, discoveries and other additions and the effects of
revisions, if any ("Reserve Additions"), by (b) each respective year's
production.
(3) Pro forma as if the acquisition of the Illinois Basin Properties occurred
on January 1, 1995. Such acquisition closed in December 1995 with an
effective date of November 1, 1995.
(4) Reserve Replacement Cost per BOE for a year is calculated by dividing
upstream costs incurred for such year by such year's Reserve Additions.
ACQUISITION AND EXPLOITATION
Acquisition and Exploitation Strategy
The Company is continually engaged in the exploitation and development of
its existing property base and the evaluation and pursuit of additional
underdeveloped properties for acquisition. The Company focuses on mature but
underdeveloped producing crude oil properties in areas where the Company
believes substantial reserve additions and cash flow increases can be made
through relatively low-risk drilling, improved production practices and
recovery techniques and improved operating margins. Generally, the Company
seeks to increase production rates and improve a property's operating margin by
reducing unit production costs and enhancing the marketing arrangements of the
oil production.
Once the Company identifies a prospective property for acquisition, it
conducts a technical review of existing production and operating practices in
an effort to identify any previously unrecognized value. If the initial studies
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indicate undeveloped potential, the various producing and potentially
productive formations in the area are mapped in detail. Historical production
data is evaluated to determine if additional wells or other capital
expenditures appear necessary to optimize the recovery of reserves from the
property. Geologic and engineering information and operating practices utilized
by operators on offsetting leases are analyzed to identify potential additional
exploitation and development opportunities. A market study is also performed
analyzing product markets, available pipeline connections, access to trading
locations and existing contractual arrangements with the goal of maximizing
sales and profit margins from the area. See "--Product Markets and Major
Customers". A comprehensive plan of exploitation is then prepared and used as a
basis for the Company's offer to purchase.
The Company typically seeks to acquire a majority interest in the
properties it has identified and to act as operator of those properties. The
Company has in the past and may in the future hedge a significant portion of
the acquired production, thereby partially mitigating product price volatility
which could have an adverse impact on exploitation opportunities. If the
Company is successful in purchasing such properties, it then implements its
exploitation plan by modifying production practices, realigning existing
waterflood patterns, drilling wells and performing workovers, recompletions and
other production and reserve enhancements. After the initial acquisition, the
Company may also seek to increase its interest in the properties through
acquisitions of offsetting acreage, farmout drilling arrangements and the
purchase of minority interests in the properties.
By modifying production practices, realigning existing waterflood patterns,
drilling wells and performing workovers, recompletions and other production
enhancements, the Company seeks to increase volumes and expand its reserve
base. The results of such activities are reflected in additions and revisions
to proved reserves. During the five year period ending December 31, 1996, net
additions and revisions to proved reserves totaled 76.2 million BOE or
approximately 338% of cumulative net production for such period. Such reserves
were added at an aggregate average cost of $2.11 per BOE. This activity
excludes reserves added as a result of the Company's acquisition activities.
Reserve additions related solely to the Company's acquisition activities
totaled 60.2 million BOE and were added at an aggregate average cost of $2.42
per BOE.
The Company's properties in its three core areas represent approximately
98% of total proved reserves at December 31, 1996. Such properties were
previously owned and operated by major integrated oil and natural gas companies
and are comprised of underdeveloped crude oil properties believed by the
Company to have significant upside potential that can be evaluated through
development and exploitation activities. During 1997, the Company estimates it
will spend approximately $48 million on the development and exploitation of its
LA Basin, Sunniland Trend and Illinois Basin Properties. Set forth below is a
discussion of such properties:
Current Exploitation Projects
LA Basin Properties. Prior to its acquisition by the Company in May 1992,
Stocker was a sole purpose company formed in 1990 to acquire substantially all
of Chevron's producing oil properties in the LA Basin. Including transaction
costs, the aggregate purchase price paid by the Company for Stocker was
approximately $23 million, consisting of a combination of cash, Common Stock
and warrants. Following the initial acquisition, the Company expanded its
holdings in this area by acquiring additional interests within the existing
fields. In late 1993, the Company acquired all of Texaco Exploration and
Production, Inc.'s interest in the Vickers Lease for approximately $5 million.
The Vickers Lease was located immediately adjacent to one of the Company's
existing properties and was subsequently consolidated into Stocker's existing
operations. All of the Company's properties in the LA Basin are collectively
referred to herein as the "LA Basin Properties". The LA Basin Properties consist
of long-life reserves discovered at various times between 1924 and 1966, and
through December 31, 1996, the LA Basin Properties have produced over 400 MMBbls
of oil and 350 Bcf of natural gas. Since mid-1992, the Company has performed
various exploitation activities, including drilling additional wells, returning
previously marginal wells to economic production, optimizing waterflood
operations, improving artificial lift and facility equipment, reducing unit
production expenses and improving marketing margins. Through these acquisition
and exploitation activities, average daily production from this area, net to the
Company's interest, has increased from approximately 6,650 BOE per day in May
1992 to an average of 9,200 BOE per day during 1996.
The Company has expended approximately $78.9 million in direct acquisition,
development and exploitation capital on the LA Basin Properties. From the
effective dates of acquisition through December 31, 1996, net production
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from such properties totaled 14.5 million BOE, generating cumulative net margin
(oil and natural gas revenue less production expenses) and proceeds from minor
property sales of approximately $109.6 million. Total estimated proved reserves
attributable to the LA Basin Properties have increased from 17.7 million BOE at
initial acquisition to approximately 74.2 million BOE at December 31, 1996. As
a result, the Company's aggregate reserve addition cost to date for the LA
Basin Properties is approximately $.89 per BOE. During 1996, the unit gross
margin for this area averaged $9.05 per BOE. Estimated future net revenues and
the Present Value of Proved Reserves at December 31, 1996, were estimated at
$1.0 billion and $447.7 million, respectively. The Company estimates it will
spend approximately $24 million during 1997 on the further development and
exploitation of the LA Basin Properties.
Sunniland Trend Properties. During the first quarter of 1993, the Company
acquired all of the capital stock of Calumet Florida, Inc. ("Calumet") for
approximately $5 million. Calumet was organized in February 1993 to purchase
and operate a 50% working interest in six producing fields in South Florida
located in the Sunniland Trend previously owned and operated by Exxon. During
1994, Calumet acquired the remaining 50% working interest in the Sunniland
Trend Properties, increasing its working interest to approximately 100% and
adding approximately five million barrels of oil to its proved reserve base at
the acquisition date. The Company's aggregate interest in such properties is
referred to as the "Sunniland Trend Properties". The aggregate purchase price
for the additional 50% interest was approximately $13.6 million, including the
issuance of a five-year warrant valued at $2 million to purchase 750,000 shares
of Common Stock at an exercise price of $6.00 per share. The Sunniland Trend
was discovered by Exxon in 1943 and the properties have produced approximately
90 MMBbls of oil through December 31, 1996. At the time of acquisition,
production from the properties was about 900 barrels of oil per day net to the
Company. As a result of development drilling on the property, the implementation
of exploitation activities designed primarily to repair failed wells and to
increase the fluid lift capacity of certain wells and the acquisition of the
remaining 50% working interest, the Company's net production increased to an
average of 4,700 barrels of oil per day during 1996.
The Company has expended approximately $48.8 million in direct acquisition,
development and exploitation capital on the Sunniland Trend Properties. From
the effective dates of acquisition through December 31, 1996, net production
from such properties totaled 4.4 million BOE, generating cumulative net margin
of approximately $31.9 million. Total estimated proved reserves attributable to
the Sunniland Trend Properties have increased from approximately 5 million BOE
at initial acquisition to approximately 23.9 million BOE at December 31, 1996.
As a result, the Company's aggregate reserve addition cost to date for the
Sunniland Trend Properties is approximately $1.72 per BOE. During 1996, the
unit gross margin for this area averaged $8.69 per BOE. At December 31, 1996,
estimated future net revenues and the Present Value of Proved Reserves were
estimated at $254.9 million and $166.9 million, respectively. During 1997, the
Company estimates it will spend approximately $15 million on the further
development and exploitation of the Sunniland Trend Properties. In addition,
the Company intends to conduct exploration activities in this trend during
1997. See "--Exploration--Current Exploration and Higher Risk Exploitation
Projects--Sunniland Trend".
Illinois Basin Properties. In December 1995, the Company acquired all of
Marathon's producing and nonproducing upstream oil and natural gas assets in
the Illinois Basin (the "Illinois Basin Properties"). This acquisition was
effective as of November 1, 1995. As a result of such acquisition, the Company
added approximately 17.3 MMBbls
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of oil to its proved reserve base. The aggregate purchase price,
including associated closing costs, was $51.5 million, comprised of 798,143
shares of the Common Stock valued at $6.5 million and $45.0 million cash. The
majority of the cash portion was funded with the proceeds of a $42 million bank
facility. The Illinois Basin Properties consist of long-life oil reserves. The
largest field included in the Illinois Basin Properties was discovered in 1905
and has produced over 400 MMBbls of oil through December 31, 1996.
The Company has expended approximately $57.2 million in direct acquisition,
development and exploitation capital on the Illinois Basin Properties. From the
effective date of acquisition through December 31, 1996, net production from
such properties totaled 1.5 million BOE, generating cumulative net margin of
approximately $14.3 million. The Company intends to aggressively exploit these
properties to evaluate additional reserve potential identified during its
acquisition analysis. The Company's exploitation plan for the Illinois Basin
Properties includes improving the unit gross margin by decreasing unit
production expenses and increasing price realizations as well as increasing
production volumes. During 1996, production averaged 3,500 BOE per day, unit
production expenses decreased 30% from prior levels and the historical discount
from the NYMEX benchmark crude oil price was decreased approximately 70%,
thereby increasing price realizations. The Company also began implementing
projects designed to increase production volumes through activities similar to
those employed in its LA Basin Properties. Unit production expenses for these
properties, which averaged $12.00 per BOE in the fourth quarter of 1995
averaged approximately $8.42 per BOE during 1996. As a result of these
operating expense reductions, reduced location price differentials and higher
average oil prices, this area's unit gross margin increased to $10.34 per BOE
during 1996 as compared to $5.37 per BOE at the time of acquisition. Total
estimated proved reserves attributable to the Illinois Basin Properties have
increased from 17.3 million BOE at initial acquisition to approximately 22.1
million BOE at December 31, 1996. As a result, the Company's aggregate reserve
addition cost to date for the Illinois Basin Properties is approximately $2.42
per BOE. Estimated future net revenues and the Present Value of Proved Reserves
at December 31, 1996, were estimated at $287.4 million and $136.7 million
respectively. During 1997, the Company estimates it will spend approximately $9
million implementing its exploitation plan on the Illinois Basin Properties.
General. The Company believes that its properties in its three core areas
hold potential for additional increases in production, reserves and cash flow.
However, the ability of the Company to achieve such increases could be adversely
affected by future decreases in the demand for oil and natural gas, impediments
in marketing production, operating risks, unavailability of capital, adverse
changes in governmental regulations or other currently unforeseen developments.
Accordingly, there can be no assurance that such increases will be achieved.
The Company believes that attractive acquisition opportunities which fit
the Company's criteria will continue to be available as a result of sales of
domestic oil properties by both major and independent oil companies. While the
Company is continually evaluating acquisition opportunities, there can be no
assurance that any of these efforts will be successful. The Company's ability to
continue to acquire attractive properties may be adversely affected by a
reduction in the number of attractive properties offered for sale, increased
competition for properties from other independent oil companies, unavailability
of capital, incorrect estimates of reserves, exploitation potential or
environmental liabilities or other factors. Although the Company has
historically acquired producing properties located only in the continental
United States, it from time to time evaluates, and may in the future seek to
acquire, properties located outside the continental United States.
EXPLORATION
Exploration Strategy
The Company seeks to complement its strategy of acquiring and exploiting
mature but underdeveloped oil properties by dedicating a substantially smaller
portion of its annual capital expenditures to higher risk but potentially
higher reward exploration opportunities. The Company focuses on exploration
opportunities that, if successful, could have a substantial positive impact on
production, cash flow and ultimately proved reserves. However, there can be no
assurance that any of its exploration projects will be successful.
In 1996, the Company and 3DX formed a joint venture to pursue the Company's
existing exploration projects and a five year strategic alliance to jointly
pursue new exploration and exploitation opportunities that are candidates for
the application of 3-D seismic technology. The joint venture covers exploration
activities in the Sunniland Trend, the Illinois Basin and the LA Basin as well
as the Company's current 3-D seismic project at the Four Isle Dome Field in
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Terrebonne Parish, Louisiana. 3DX bears principal responsibility for the
geological and geophysical oversight and project technical management of such
projects. In connection with the joint venture, 3DX acquired 15% to 20% of the
Company's working interests in certain projects, excluding designated
productive areas within each field. 3DX will have the right to participate for
up to 20% in the Company's new exploration and exploitation projects.
Current Exploration and Higher Risk Exploitation Projects
Sunniland Trend. The focus of the Company's exploration effort in the
Sunniland Trend is to identify and evaluate prospects that are analogous to the
existing producing fields in this trend. Although this trend was discovered
around 1940, the Company and its partners are attempting to integrate
historical exploration methods with recent advancements in seismic technology
to evaluate the exploration potential of the Sunniland Trend. The Company
formed a 50/50 joint venture with Meridian Oil Company to conduct exploration
activities in the Sunniland Trend in addition to its relationship with 3DX. The
Company is the operator of this joint venture. During 1996, the Company drilled
one exploratory dry hole in this effort. Preliminary plans for 1997 include
shooting 2-D and/or 3-D seismic on identified leads and drilling up to two
exploratory wells.
Four Isle Dome. The Company, Phillips Petroleum Company ("Phillips") and
Nuevo Energy Company ("Nuevo") entered into an agreement to explore
approximately 20,000 acres in Terrebonne Parish, Louisiana currently held under
seismic option. During 1995, the joint venture conducted a 3-D seismic survey
covering approximately 52 square miles. The area, known as Four Isle Dome, was
discovered in 1934 and has produced to date over 540 Bcf of natural gas and 20
MMBbls of oil. The Company and 3DX hold a 26% and 7% interest, respectively,
while Phillips and Nuevo each hold a 33.3% interest in the project. All of such
interests are subject to a proportionate 25% reduction if the mineral owner,
Louisiana Land and Exploration, elects to participate in a given prospect.
During 1996, the Company drilled one exploratory dry hole in this project. The
Company is the operator of the joint venture and intends to drill up to two
wells in this project during 1997, the first of which was commenced in late
1996.
LA Basin. The Company intends to undertake a pilot drilling program to
evaluate future infill exploitation potential of five distinct reservoirs that
have produced below the primary producing formation in its Inglewood field.
These deeper reservoirs have produced approximately 75 MMbls of oil and 100 Bcf
of gas from approximately 58 wells completed in certain of these reservoirs at
depths ranging from 4,000 to 9,500 feet. Depending on the results of current
technical evaluations and studies, the Company may drill up to five wells to
evaluate the remaining potential of these reservoirs.
General. During 1997, the Company estimates it will spend approximately $14
million on exploration and higher risk exploitation activities, principally in
the Sunniland Trend, the LA Basin and Four Isle Dome. While all drilling
activities are subject to numerous risks, the risks associated with exploration
activities and these higher risk exploitation activities are significantly
greater than those associated with the Company's other exploitation and
development activities. There can be no assurance that any of the Company's
current exploration or higher risk exploitation projects will result in the
discovery of proved reserves or the establishment of commercially viable oil or
natural gas production.
The Company has historically conducted a portion of its exploration
activities with outside partners. When deemed appropriate, the Company will
continue to solicit industry and financial partners to participate in
exploration projects on negotiated terms. The level of the Company's capital
expenditures for these projects, and its working and revenue interests, will
vary depending on the amount and terms of such outside participation.
DISPOSITION OF PROPERTIES
The Company periodically evaluates, and from time to time has elected to
sell, certain of its mature producing properties that it considers to be
nonstrategic or fully valued. Such sales enable the Company to focus on its
core properties, maintain financial flexibility, reduce overhead and redeploy
the proceeds therefrom to activities that the Company believes potentially have
a higher financial return. During 1995 and 1996, the Company sold nonstrategic
oil and natural gas properties located primarily in the Gulf Coast areas of
Texas and Louisiana and in Utah for proceeds of $7.4 million and $3.1 million,
respectively. As a result, approximately 98% of the Company's 1996 year-end
proved
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reserve volumes and proved reserve value were associated with its properties in
the LA Basin, Sunniland Trend and Illinois Basin.
DOWNSTREAM ACTIVITIES
The Company's marketing effort involves purchasing crude oil from other
producers and marketing it to the refining sector. The Company aggregates these
purchased volumes with its own production at major crude oil interchanges and
trading locations, which enables it to obtain higher prices for its own
production while realizing profits on the production purchased from others. The
Company owns and operates a two million barrel, above ground crude oil storage
and terminalling facility in Cushing, Oklahoma (the "Cushing Terminal"), the
United States' largest inland crude oil interchange and trading location. This
facility enhances the ability of the Company to profit from its marketing
activities by allowing the Company to take advantage of certain time and quality
arbitrage opportunities and make or take physical delivery of crude oil at
Cushing, the NYMEX designated delivery location. The Company's downstream
activities have expanded significantly, with downstream gross margin (revenues
less direct expenses of purchases, transportation, storage and terminalling)
having increased approximately 672% from $1.2 million in 1991 to $9.5 million in
1996. The Company estimates that approximately 40% to 50% of the tankage
capacity available at the Cushing Terminal was used in 1996; accordingly,
substantial additional capacity is available without the expenditure of
additional capital.
Crude oil is purchased at the wellhead and transported by Company-owned
trucks or third-party transporters to a trading location where the Company
sells the crude oil to a refiner or other purchaser. The Company also purchases
crude oil in the spot market at trading locations. The Company's policy is to
purchase only crude oil for which it has a market and to structure its sales
contracts so that crude oil price fluctuations do not materially affect the
gross margin which it receives. The crude oil marketing business is
characterized by a large volume of transactions with low margins. The Company
has generally maintained a gross margin of approximately 2% in its marketing
activities for each of the years 1992 through 1996. The Company also routinely
analyzes opportunities for possible purchase or construction of gathering and
pipeline systems, processing and storage facilities and various other related
capital investment projects to enhance its profitability in the markets in
which it operates.
The Cushing Terminal was completed in December 1993. The facility was
designed to accommodate the numerous grades of crude oil used by refiners and
consists of two million barrels (fourteen 100,000 barrel tanks and four 150,000
barrel tanks) of above ground shell storage capacity. The Cushing Terminal was
built at a total cost through December 31, 1996, of approximately $31.1 million,
which includes the cost of land acquisition, engineering and environmental
studies, construction-phase interest, pipeline interconnects and an oversized
manifold and pumping system that was designed and constructed to accommodate
expansion up to an aggregate ten million barrels of storage capacity. The
Company estimates that its storage tanks have a useful life in excess of 60
years. The facility is connected to major pipelines into and out of the Cushing
interchange and can operate at a daily throughput rate of approximately 800,000
Bbls.
Cushing is the largest wet barrel trading hub in the United States and the
delivery point for crude oil futures contracts traded on the NYMEX. The Cushing
Terminal has been designated by the NYMEX as an approved delivery location for
crude oil delivered under the NYMEX "light" sweet crude oil futures contract.
The Cushing Terminal was constructed to capitalize on the crude oil supply and
demand imbalance in the Midwest caused by the continued decline of traditional
regional supplies, increasing imports and an inadequate pipeline and terminal
infrastructure. Based upon the Company's analysis of existing storage facilities
at Cushing and the anticipated increase in crude oil volumes to be transported
through Cushing, the Company believes that there will be an increasing demand
for additional storage capacity at Cushing; however, there can be no assurance
that such demand will increase. Because of its initial investment in land,
engineering and environmental studies, pipeline interconnects and the manifold
and pumping system, the cost to construct incremental storage capacity is
estimated at $7.50 to $8.00 per Bbl of shell capacity. The Company generates
revenue from the Cushing Terminal through a combination of storage, reservation
and throughput fees from customers such as (i) refiners and gatherers seeking to
segregate or custom blend crudes for refining feedstocks, (ii) pipelines
requiring segregated tankage for foreign cargoes, (iii) traders who make or take
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delivery under the NYMEX contract, (iv) producers seeking to increase their
marketing alternatives and (v) contango market crude oil trading activities.
OPERATING ACTIVITIES
The following table presents certain information with respect to the
Company's upstream oil and natural gas producing activities and its downstream
marketing, transportation and storage activities during the three years ended
December 31, 1994, 1995 and 1996:
YEAR ENDED DECEMBER 31,
------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
Sales to unaffiliated customers:
Oil and natural gas ..................... $ 57,234 $ 64,080 $ 97,601
Marketing, transportation and storage ... 199,239 339,826 531,698
Operating profits:
Oil and natural gas (1) ................. $ 30,122 $ 34,029 $ 59,085
Marketing, transportation and storage (2) 6,305 6,480 9,621
Identifiable assets:
Oil and natural gas ..................... $204,778 $271,248 $309,107
Marketing, transportation and storage ... 62,126 80,798 121,142
- -----------------
(1) Consists of primarily oil and natural gas sales less production expenses.
(2) Consists of primarily marketing, transportation and storage sales less
purchases, transportation and storage expenses. Includes approximately
$1.5 million and $.1 million during 1994 and 1995, respectively, of
operating profit attributed to contango market transactions.
Operating profits as a percentage of sales are significantly lower for
the Company's marketing, transportation and storage activities than for its oil
and natural gas producing activities because the cost of oil and natural gas
purchased for resale is higher, as a percentage of sales price, than the
Company's cost to produce oil and natural gas.
See "--Downstream Activities".
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General
The Company was incorporated under the laws of the State of Delaware in
1976. The Company's executive offices are located at 1600 Smith Street, Suite
1500, Houston, Texas 77002, and its telephone number is (713) 654-1414.
Product Markets and Major Customers
The revenues generated by the Company's operations are highly
dependent upon the prices of, and demand for, oil and natural gas.
Historically, the markets for oil and natural gas have been volatile and are
likely to continue to be volatile in the future. The price received by the
Company for its oil and natural gas production and the level of such production
are subject to wide fluctuations and depend on numerous factors beyond the
Company's control, including seasonality, the condition of the United States
economy (particularly the manufacturing sector), foreign imports, political
conditions in other oil-producing and natural gas-producing countries, the
actions of the Organization of Petroleum Exporting Countries and domestic
government regulation, legislation and policies. Decreases in the prices of oil
and natural gas have had, and could have in the future, an adverse effect on the
carrying value of the Company's proved reserves and the Company's revenues,
profitability and cash flow. In this regard, it should be noted that oil prices
at December 31, 1996, upon which proved reserve volumes, the Present Value of
Proved Reserves and the Standardized Measure as of such date are based, were at
the highest year-end level since 1990.
In order to manage its exposure to price risks in the marketing of its
oil and natural gas, the Company from time to time enters into fixed price
delivery contracts, floating price collar arrangements, financial swaps and oil
and natural gas futures contracts as hedging devices. To ensure a fixed price
for future production, the Company may sell a futures contract and thereafter
either (i) make physical delivery of its product to comply with such contract
or (ii) buy a matching futures contract to unwind its futures position and sell
its production to a customer. These same techniques are also utilized to manage
price risk for certain production purchased from customers of Plains Marketing.
Such contracts may expose the Company to the risk of financial loss in certain
circumstances, including instances where production is less than expected, the
Company's customers fail to purchase or deliver the contracted quantities of
oil or natural gas, or a sudden, unexpected event materially impacts oil or
natural gas prices. Such contracts may also restrict the ability of the Company
to benefit from unexpected increases in oil and natural gas prices. See Item 2,
"Properties--Oil and Natural Gas Reserves".
Substantially all of the Company's LA Basin crude oil and natural gas
production and its Sunniland Trend and Illinois Basin oil production are
transported by pipelines owned by third parties. The inability or unwillingness
of these pipelines to provide transportation services to the Company for a
reasonable fee could result in the Company having to find transportation
alternatives, increased transportation costs to the Company or involuntary
curtailment of a significant portion of its crude oil and natural gas
production. The Company is currently in dispute with the third party pipeline
company that transports its Sunniland Trend oil production. See Item 3,
"Legal Proceedings".
Certain of the Company's natural gas production has been in the past,
and may be in the future, curtailed from time to time depending on the quality
of the natural gas produced and transportation alternatives. In addition,
market, economic and regulatory factors, including issues regarding the quality
of certain of the Company's natural gas, may in the future adversely affect the
Company's ability to sell its natural gas production.
Before 1985, substantially all of the Company's natural gas production
was sold directly to pipeline companies which were responsible for resale and
transportation of the natural gas to end-users. Since that time, however, with
the adoption of various orders by the Federal Energy Regulatory Commission
("FERC") (see "--Regulation--Transportation and Sale of Natural Gas") and the
deregulation of natural gas pursuant to the Natural Gas Policy Act of 1978
("NGPA") and the Natural Gas Wellhead Decontrol Act of 1989 (the "Decontrol
Act"), the FERC has actively promoted competition in the nationwide market for
natural gas and has encouraged pipelines to significantly reduce their role as
merchants of natural gas and to make transportation services available on an
"open-access", nondiscriminatory basis. Since these regulatory initiatives were
begun, natural gas producers such as the Company have been able to sell their
natural gas supplies directly to utilities and other end-users.
In addition to the regulatory changes discussed above, deregulation of
natural gas prices under the NGPA and the Decontrol Act has increased
competition and volatility of natural gas prices. Since demand for natural gas
is generally highest during winter months, prices received for the Company's
natural gas are subject to seasonal variations and other fluctuations. All of
the Company's natural gas production is currently sold under various
arrangements at spot indexed prices. In certain instances, the Company enters
into financial arrangements to hedge its exposure to spot price fluctuations.
See Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Changing Oil and Natural Gas Prices" and Item 2,
"Properties--Production and Sales".
Koch Oil Company and Basis Petroleum, Inc. ("Basis"), formerly Phibro
Energy USA, Inc., accounted for 16% and 11%, respectively, of the Company's
total revenue (exclusive of interest and other income) during 1996. Customers
accounting for more than 10% of total revenue for 1995 and 1994 were as
follows: 1995 -- Phibro Inc. ("Phibro") --
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16% and Basis -- 12%; 1994 -- Phibro -- 19% and Chevron -- 16%. No other single
purchaser of the Company's products accounted for as much as 10% of total sales
during 1996, 1995 or 1994. Basis and Phibro Inc. are both subsidiaries of
Salomon Inc. Additionally during 1996, Unocal, Marathon Oil Company and Basis
accounted for approximately 51%, 24% and 20%, respectively, of the Company's
oil and natural gas sales. During 1996, Unocal, Marathon Oil Company and Basis
purchased the crude oil from the LA Basin Properties, Illinois Basin Properties
and the Sunniland Trend Properties, respectively. See Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations".
COMPETITION
Oil and Natural Gas Producing Activities
The Company's competitors include major integrated oil and natural gas
companies and numerous independent oil and natural gas companies, individuals
and drilling and income programs. Many of the Company's larger competitors
possess and employ financial and personnel resources substantially greater than
those available to the Company. Such companies are able to pay more for
productive oil and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects than the Company's financial or human resources permit. The Company's
ability to acquire additional properties and to discover reserves in the future
will be dependent upon its ability to evaluate and select suitable properties
and to consummate transactions in a highly competitive environment. In
addition, there is substantial competition for capital available for investment
in the oil and natural gas industry.
Downstream Activities
The Company faces intense competition in purchasing and marketing
crude oil and in the crude oil storage business. Its competitors include the
major integrated oil companies, their marketing affiliates and independent
gatherers, brokers and marketers of widely varying sizes, financial resources
and experience. Some of these competitors have capital resources many times
greater than the Company's and control substantially greater supplies of crude
oil. Although the Company believes that the environmental safeguards and
operating capabilities of the Cushing Terminal are superior to other existing
facilities in Cushing, the Company competes with larger companies that possess
superior financial resources and have an established business presence. Such
advantages could inhibit the development of the Company's business for the
Cushing Terminal.
REGULATION
The Company's operations are subject to extensive and continually
changing regulation, as legislation affecting the oil and natural gas industry
is under constant review for amendment and expansion. Many departments and
agencies, both federal and state, are authorized by statute to issue and have
issued rules and regulations binding on the oil and natural gas industry and
its individual participants. The failure to comply with such rules and
regulations can result in substantial penalties. The regulatory burden on the
oil and natural gas industry increases the Company's cost of doing business
and, consequently, affects its profitability. However, the Company does not
believe that it is affected in a significantly different manner by these
regulations than are its competitors in the oil and natural gas industry. Due
to the myriad and complex federal and state statutes and regulations which may
affect the Company, directly or indirectly, the following discussion of certain
statutes and regulations should not be relied upon as an exhaustive review of
all matters affecting the Company's operations.
Transportation and Sale of Crude Oil
Sales of crude oil and condensate can be made by the Company at market
prices not subject at this time to price controls. However, the price that the
Company receives from the sale of these products is affected by the cost of
transporting the products to market. Commencing in October 1993, the FERC
issued a series of orders (Order No . 561 and 561-A) in which it revised its
regulations governing the rates that may be charged by oil pipelines. The new
rules, which became effective January 1, 1995, provide a simplified, generally
applicable method for regulating such rates by use of an index for setting rate
ceilings. In certain circumstances, the new rules permit oil pipelines to
establish rates using traditional cost of service and other methods of
ratemaking. These rules could increase the cost of transporting
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crude oil and condensate by pipeline. On October 28, 1994, the FERC issued two
separate Orders (Nos. 571 and 572), which adopt additional regulations
governing rates that an oil pipeline may be authorized to charge. Order No. 571
authorizes a pipeline to implement cost-of-service based rates, provided it can
demonstrate that there is a substantial divergence between the actual costs
experienced by the carrier and the indexed rate that the pipeline is directed
to charge under Order No. 561. In Order No. 572, the FERC adopted regulations
that authorize a pipeline to charge market-based rates, provided it can
demonstrate that it lacks significant market power in the market(s) in which it
proposes to charge such rates. These rules have been affirmed by the reviewing
courts.
Transportation and Sale of Natural Gas
Prior to January 1, 1993, various aspects of the Company's natural gas
operations were subject to regulation by the FERC under the Natural Gas Act of
1938 (the "NGA") and the NGPA with respect to "first sales" of natural gas,
including price controls and certificate and abandonment authority regulations.
However, as a result of the enactment of the Decontrol Act, the remaining
"first sales" restrictions imposed by the NGA and the NGPA terminated on
January 1, 1993.
The FERC regulates interstate natural gas pipeline transportation
rates and service conditions, which affect the marketing of natural gas
produced by the Company, as well as the revenues received by the Company for
sales of such natural gas. Since the latter part of 1985, the FERC has adopted
policies intended to make natural gas transportation more accessible to natural
gas buyers and sellers on an open and non-discriminatory basis. The FERC's most
recent action in this area, Order No. 636, reflected the FERC's finding that,
under the then-existing regulatory structure, interstate pipelines and other
natural gas merchants, including producers, did not compete on a "level playing
field" in selling natural gas. Order No. 636 instituted individual pipeline
service restructuring proceedings, designed specifically to "unbundle" those
services (e.g., transportation, sales and storage) provided by many interstate
pipelines so that buyers of natural gas may secure natural gas supplies and
delivery services from the most economical source, whether interstate pipelines
or other parties. The FERC has issued final orders in all of the restructuring
proceedings and has announced its intention to reexamine certain of its
transportation-related policies, including the appropriate manner in which
interstate pipelines release capacity under Order No. 636 and, more recently,
the price which shippers can charge for their released capacity. The FERC has
also adopted a new policy regarding the use of non-traditional methods of
setting rates for interstate natural gas pipelines in certain circumstances as
alternatives to cost of service based rates. A number of pipelines have
obtained FERC authorization to charge negotiated rates as one such alternative.
The Company cannot predict what action the FERC will take in the reexamination
of its transportation-related policies, nor can it accurately predict whether
the FERC's actions will achieve its stated goal of increasing competition in
domestic natural gas markets. However, the Company does not believe that it
will be treated materially differently than other natural gas producers and
marketers with which it competes.
Although the FERC's actions, such as Order No. 636, do not regulate
natural gas producers such as the Company, these actions are intended to foster
increased competition within all phases of the natural gas industry. To date,
the FERC's pro-competition policies have not materially affected the Company's
business or operations. On a prospective basis, however, such orders may
substantially increase the burden on the producers and transporters to nominate
and deliver on a daily basis a specified volume of natural gas. Producers and
transporters which deliver deficient volumes or volumes in excess of such daily
nominations could be subject to additional charges by the pipeline carriers.
The United States Court of Appeals for the District of Columbia Circuit
has affirmed the FERC's Order No. 636 restructuring rule and remanded certain
issues for further explanation or clarification. Numerous petitions seeking
judicial review of the individual pipeline restructuring orders are currently
pending in that Court. Although it is difficult to predict when all appeals of
pipeline restructuring orders will be completed or their impact on the Company,
the Company does not believe that it will be affected by the restructuring rule
and orders any differently than other natural gas producers and marketers with
which it competes.
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Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, the FERC, state
regulatory bodies and the courts. The Company cannot predict when or if any
such proposals might become effective or their effect, if any, on the Company's
operations. The natural gas industry has historically been very heavily
regulated; thus there is no assurance that the less stringent regulatory
approach recently pursued by the FERC and Congress will continue indefinitely
into the future. The regulatory burden on the oil and natural gas industry
increases the Company's cost of doing business and, consequently, affects its
profitability and cash flow. Inasmuch as laws and regulations are frequently
expanded, amended or reinterpreted, the Company is unable to predict the future
cost or impact of complying with such regulations.
Regulation of Production
The production of oil and natural gas is subject to regulation under a
wide range of federal and state statutes, rules, orders and regulations. State
and federal statutes and regulations require permits for drilling operations,
drilling bonds and reports concerning operations. Most states in which the
Company owns and operates properties have regulations governing conservation
matters, including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of the spacing, plugging and abandonment
of wells. Many states also restrict production to the market demand for oil and
natural gas and several states have indicated interest in revising applicable
regulations. The effect of these regulations is to limit the amount of oil and
natural gas the Company can produce from its wells and to limit the number of
wells or the locations at which the Company can drill. Moreover, each state
generally imposes an ad valorem, production or severance tax with respect to
production and sale of crude oil, natural gas and natural gas liquids within
its jurisdiction.
Environmental Regulation
General. Various federal, state and local laws and regulations
governing the discharge of materials into the environment, or otherwise
relating to the protection of the environment, affect the Company's operations
and costs. In particular, the Company's exploration, exploitation and
production operations, its activities in connection with storage and
transportation of crude oil and other liquid hydrocarbons and its use of
facilities for treating, processing or otherwise handling hydrocarbons and
wastes therefrom are subject to stringent environmental regulation. As with the
industry generally, compliance with existing and anticipated regulations
increases the Company's overall cost of business. Such areas affected include
unit production expenses primarily related to the control and limitation of air
emissions and the disposal of produced water, capital costs to drill exploration
and development wells due to solids control and capital costs to construct,
maintain and upgrade equipment and facilities. While these regulations affect
the Company's capital expenditures and earnings, the Company believes that such
regulations do not affect its competitive position in that the operations of its
competitors that comply with such regulations are similarly affected.
Environmental regulations have historically been subject to frequent change by
regulatory authorities, and the Company is unable to predict the ongoing cost to
it of complying with these laws and regulations or the future impact of such
regulations on its operation. A discharge of hydrocarbons or hazardous
substances into the environment could, to the extent such event is not insured,
subject the Company to substantial expense, including both the cost to comply
with applicable regulations and claims by neighboring landowners and other third
parties for personal injury and property damage.
A significant portion of the Miami Fee acreage in Cameron Parish,
Louisiana, is within the Sabine National Wildlife Refuge (the "Refuge"), and
operations therein are subject to the National Wildlife Refuge Administration
Act and the regulations promulgated thereunder (the "Wildlife Refuge Act"). The
Wildlife Refuge Act states that no person may use, occupy, conduct any activity
on or remove property from any area located within a wildlife refuge unless a
permit has been granted for such use, occupation, conduct, activity or removal
of property. The Company currently is obligated to plug and abandon wells
drilled on the Miami Fee acreage in prior years. Such obligations must comply
with the requirements established by the Regional Director to ensure that the
plugging and abandonment of such wells are compatible with the Wildlife Refuge
Act.
Although the Company obtained environmental studies on its properties
in the LA Basin, Sunniland Trend and Illinois Basin, and the Company believes
that such properties have been operated in accordance with standard oil field
practices, certain of the fields have been in operation for more than
approximately 90 years, and current or future local, state and federal
environmental laws and regulations may require substantial expenditures to
comply with such rules and regulations. In December 1995, the Company
negotiated an agreement with Chevron, a prior owner of the LA
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Basin Properties, to remediate sections of the properties impacted by prior
drilling and production operations. Under this agreement, Chevron agreed to
investigate and potentially remediate specific areas contaminated with volatile
organic substances and heavy metals, and the Company agreed to excavate and
remediate crude oil contaminated soils. The Company is obligated to construct
and operate (for the next 14 years) two five-acre bioremediation cells for
crude oil contaminated soils designated for excavation and treatment by
Chevron. While the Company believes that it does not have any material
obligations for operations conducted prior to Stocker's acquisition of the
properties from Chevron, other than its obligation to plug existing wells and
those normally associated with customary oil field operations of similarly
situated properties (such as the Chevron agreement described above), there can
be no assurance that current or future local, state or federal rules and
regulations will not require it to spend material amounts to comply with such
rules and regulations or that any portion of such amounts will be recoverable
from Chevron, either under the December 1995 agreement or the limited indemnity
from Chevron contained in the original purchase agreement.
A portion of the Sunniland Trend Properties is located within the Big
Cypress National Preserve and the Company's operations therein are subject to
regulations administered by the National Park Service ("NPS"). Under such
regulations, a Master Plan of Operations has been approved by the Regional
Director of the NPS. The Master Plan of Operations is a comprehensive plan of
practices and procedures for the Company's drilling and production operations
designed to minimize the effect of such operations on the environment. The
Master Plan of Operations must be modified and permits must be secured from the
NPS for new wells which require the use of additional land for drilling
operations. The Master Plan of Operations also requires that the Company
restore the surface property affected by its drilling and production operations
upon cessation of these activities. The Company does not anticipate that
expenditures required to comply with such regulations will have a material
adverse effect on its current operations.
Water. The Oil Pollution Act ("OPA") was enacted in 1990 and amends
provisions of the Federal Water Pollution Control Act of 1972 ("FWPCA") and
other statutes as they pertain to prevention and response to oil spills. The
OPA subjects owners of facilities to strict, joint and potentially unlimited
liability for removal costs and certain other consequences of an oil spill,
where such spill is into navigable waters, along shorelines or in the exclusive
economic zone of the United States. In the event of an oil spill into such
waters, substantial liabilities could be imposed upon the Company. States in
which the Company operates have also enacted similar laws. Regulations are
currently being developed under OPA and state laws that may also impose
additional regulatory burdens on the Company.
The FWPCA imposes restrictions and strict controls regarding the
discharge of produced waters and other oil and natural gas wastes into
navigable waters. Permits must be obtained to discharge pollutants to state and
federal waters. The FWPCA provides for civil, criminal and administrative
penalties for any unauthorized discharges of oil and other hazardous substances
in reportable quantities and, along with the OPA, imposes substantial potential
liability for the costs of removal, remediation and damages. State laws for the
control of water pollution also provide varying civil, criminal and
administrative penalties and liabilities in the case of a discharge of
petroleum or its derivatives into state waters. The EPA has promulgated
regulations that require many oil and natural gas production operations to
obtain permits to discharge storm water runoff. At some facilities, such as the
Sunniland Trend Properties, the Company eliminated this permit requirement by
collecting all potentially contaminated storm water and disposing of it through
the Company's underground injection control ("UIC") disposal wells. At other
facilities, the Company has applied for and obtained any necessary storm water
discharge permits, and is currently in substantial compliance with applicable
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permit conditions. The Company believes that compliance with existing permits
and compliance with foreseeable new permit requirements will not have a
material adverse effect on the Company's financial condition or results of
operations.
Air Emissions. The operations of the Company are subject to the
Federal Clean Air Act and comparable state and local statutes. The Company
believes that its operations are in substantial compliance with such statutes
in all states in which they operate.
Amendments to the Federal Clean Air Act enacted in late 1990 (the "1990
Federal Clean Air Act Amendments") require or will require most industrial
operations in the United States to incur capital expenditures in order to meet
air emission control standards developed by the Environmental Protection Agency
(the "EPA") and state environmental agencies. In particular, the Company's LA
Basin properties are located in an "extreme" non-attainment area for ozone. This
classification will force the local air quality regulatory authority, the South
Coast Air Quality Management District, to adopt stringent controls on all
emissions of nitrogen oxide and volatile organic compounds. As a result of these
future regulations, the Company may incur future capital expenditures to reduce
air emissions from the LA Basin production facilities. In addition, the 1990
Federal Clean Air Act Amendments include a new operating permit for major
sources ("Title V permits"), and several of the Company's facilities may require
permits under this new program. Although no assurances can be given, the Company
believes implementation of the 1990 Federal Clean Air Act Amendments will not
have a material adverse effect on the Company's financial condition or results
of operations.
Solid Waste. The Company generates non-hazardous solid wastes that are
subject to the requirements of the Federal Resource Conservation and Recovery
Act ("RCRA") and comparable state statutes. The EPA is considering the adoption
of stricter disposal standards for non-hazardous wastes. RCRA also governs the
disposal of hazardous wastes. At present, the Company is not required to comply
with a substantial portion of the RCRA requirements because the Company's
operations generate minimal quantities of hazardous wastes. However, it is
anticipated that additional wastes, which could include wastes currently
generated during operations, will in the future be designated as "hazardous
wastes". Hazardous wastes are subject to more rigorous and costly disposal
requirements than are non-hazardous wastes. Such changes in the regulations may
result in additional capital expenditures or operating expenses by the Company.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as "Superfund", imposes liability, without
regard to fault or the legality of the original act, on certain classes of
persons that contributed to the release of a "hazardous substance" into the
environment. These persons include the owner or operator of the site and
companies that disposed or arranged for the disposal of the hazardous
substances found at the site. CERCLA also authorizes the EPA and, in some
instances, third parties to act in response to threats to the public health or
the environment and to seek to recover from the responsible classes of persons
the costs they incur. In the course of its ordinary operations, the Company may
generate waste that may fall within CERCLA's definition of a "hazardous
substance". The Company may be jointly and severally liable under CERCLA for
all or part of the costs required to clean up sites at which such hazardous
substances have been disposed or released into the environment.
The Company currently owns or leases, and has in the past owned or
leased, numerous properties that for many years have been used for the
exploration and production of oil and natural gas. Although the Company has
utilized operating and disposal practices that were standard in the industry at
the time, hydrocarbons or other wastes may have been disposed of or released on
or under the properties owned or leased by the Company or on or under other
locations where such wastes have been taken for disposal. In addition, many of
these properties have been operated by third parties whose treatment and
disposal or release of hydrocarbons or other wastes was not under the Company's
control. These properties and wastes disposed thereon may be subject to CERCLA,
RCRA and analogous state laws. Under such laws, the Company could be required
to remove or remediate previously disposed wastes (including wastes disposed of
or released by prior owners or operators), to clean up contaminated property
(including contaminated groundwater) or to perform remedial plugging operations
to prevent future contamination.
FEDERAL TAXATION
At December 31, 1996, the Company and its subsidiaries, which together
file a consolidated federal income tax return, had federal income tax NOL
carryforwards of approximately $183 million. Of that amount, approximately $16
million is subject to separate return limitation year restrictions and may only
be utilized to the extent certain
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subsidiaries which generated the NOLs have taxable income. At December 31,
1996, the Company had approximately $169 million of alternative minimum tax
("AMT") net operating loss carryforwards available as a deduction against
future AMT income. In addition, the Company had approximately $.7 million of
investment tax credit carryforwards and $7.0 million of percentage depletion
carryforwards at December 31, 1996. The NOL carryforwards expire from 1997
through 2011. The value of these carryforwards depends on the ability of the
Company to generate federal taxable income. In addition, for AMT purposes, only
90% of AMT income in any given year may be offset by AMT NOLs.
The ability of the Company to utilize NOL and investment tax credit
carryforwards to reduce future federal taxable income and federal income tax of
the Company is subject to various limitations under the Internal Revenue Code
of 1986, as amended (the "Code"). The utilization of such carryforwards may be
limited upon the occurrence of certain ownership changes, including the
issuance or exercise of rights to acquire stock, the purchase or sale of stock
by 5% stockholders, as defined in the Treasury Regulations, and the offering of
stock by the Company during any three-year period resulting in an aggregate
change of more than 50% ("Ownership Change") in the beneficial ownership of the
Company.
In the event of an Ownership Change, Section 382 of the Code imposes
an annual limitation on the amount of a corporation's taxable income that can
be offset by these carryforwards. The limitation is generally equal to the
product of (i) the fair market value of the equity of the Company multiplied by
(ii) a percentage approximately equivalent to the yield on long-term tax exempt
bonds during the month in which an Ownership Change occurs. In addition, the
limitation is increased if there are recognized built-in gains during any
post-change year, but only to the extent of any net unrealized built-in gains
(as defined in the Code) inherent in the assets sold. Although no assurances
can be made, the Company does not believe that an Ownership Change has occurred
as of December 31, 1996. Equity transactions after the date hereof by the
Company or by 5% stockholders (including relatively small transactions and
transactions beyond the Company's control) could cause an Ownership Change and
therefore a limitation in the annual limitation of NOLs.
The Company does not expect to report any regular taxable income in
the near future because it expects to utilize its carryforwards and other tax
deductions and credits. However, there is no assurance that the Internal
Revenue Service will not challenge these carryforwards or their utilization.
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Other Business Matters
The Company must continually acquire, explore for, develop or exploit
new oil and natural gas reserves to replace those produced or sold. Without
successful drilling, acquisition or exploitation operations, the Company's oil
and natural gas reserves and revenues will decline. Drilling activities are
subject to numerous risks, including the risk that no commercially viable oil
or natural gas production will be obtained. The decision to purchase, explore,
exploit or develop an interest or property will depend in part on the
evaluation of data obtained through geophysical and geological analyses and
engineering studies, the results of which are often inconclusive or subject to
varying interpretations. See Item 2, "Properties--Oil and Natural Gas
Reserves". The cost of drilling, completing and operating wells is often
uncertain. Drilling may be curtailed, delayed or canceled as a result of many
factors, including title problems, weather conditions, compliance with
government permitting requirements, shortages of or delays in obtaining
equipment, reductions in product prices or limitations in the market for
products. The availability of a ready market for the Company's oil and natural
gas production also depends on a number of factors, including the demand for
and supply of oil and natural gas and the proximity of reserves to pipelines or
trucking and terminal facilities. Natural gas wells may be shut in for lack of
a market or due to inadequacy or unavailability of natural gas pipeline or
gathering system capacity.
Substantially all of the Company's LA Basin crude oil and natural gas
production and its Sunniland Trend and Illinois Basin oil production are
transported by pipelines owned by third parties. The inability or unwillingness
of these pipelines to provide transportation services to the Company for a
reasonable fee could cause the Company to seek transportation alternatives,
which in turn could result in increased transportation costs to the Company or
involuntary curtailment of a significant portion of its crude oil and natural
gas production. The Company is currently in dispute with the third party
pipeline company that transports its Sunniland Trend oil production. See
Item 3, "Legal Proceedings".
The Company's operations are subject to all of the risks normally
incident to the exploration for and the production of oil and natural gas,
including blowouts, cratering, oil spills and fires, each of which could result
in damage to or destruction of oil and natural gas wells, production facilities
or other property, or injury to persons. The relatively deep drilling conducted
by the Company from time to time involves increased drilling risks of high
pressures and mechanical difficulties, including stuck pipe, collapsed casing
and separated cable. The Company's operations in the LA Basin, including
transportation of crude oil by pipelines within the city of Los Angeles, are
especially susceptible to damage from earthquakes and involve increased risks
of personal injury, property damage and marketing interruptions because of the
population density of the area. Although the Company maintains insurance
coverage considered to be customary in the industry, it is not fully insured
against certain of these risks, including, in certain instances, earthquake
risk in the LA Basin, either because such insurance is not available or because
of high premium costs. The occurrence of a significant event that is not fully
insured against could have a material adverse effect on the Company's financial
position.
The revenues generated by the Company's operations are highly
dependent upon the prices of, and demand for, oil and natural gas.
Historically, the prices for oil and natural gas have been volatile and are
likely to continue to be volatile in the future. The price received by the
Company for its oil and natural gas production and the level of such production
are subject to wide fluctuations and depend on numerous factors beyond the
Company's control, including seasonality, the condition of the United States
economy (particularly the manufacturing sector), foreign imports, political
conditions in other oil-producing and natural gas-producing countries, the
actions of the Organization of Petroleum Exporting Countries and domestic
government regulation, legislation and policies. Decreases in the prices of oil
and natural gas have had, and could have in the future, an adverse effect on
the carrying value of the Company's proved reserves and the Company's revenues,
profitability and cash flow. In this regard, it should be noted that oil prices
at December 31, 1996, upon which estimated proved reserve volumes, the Present
Value of Proved Reserves and the Standardized Measure as of such date are
based, were at the highest year-end level since 1990. At December 31, 1996, the
NYMEX Crude Oil Price was $25.92 per barrel, 33% higher than the $19.55 per
barrel at December 31, 1995. Although the Company is not currently
experiencing any significant involuntary curtailment of its crude oil or
natural gas production, market, logistic, economic and regulatory factors may
in the future materially affect the Company's ability to sell its natural gas
production.
In order to manage its exposure to price risks in the marketing of its
oil and natural gas, the Company from time to time enters into fixed price
delivery contracts, floating price collar arrangements, financial swaps and oil
and natural gas futures contracts as hedging devices. To ensure a fixed price
for future production, the Company may sell a futures contract and thereafter
either (i) make physical delivery of its product to comply with such contract
or (ii) buy a matching futures contract to unwind its futures position and sell
its production to a customer. These same techniques are also utilized to manage
price risk for certain production purchased from customers of the Company's
marketing subsidiary, Plains Marketing & Transportation Inc. ("Plains
Marketing"). Such contracts may expose the Company to the risk of financial
loss in certain circumstances, including instances where production is less
than expected, the Company's customers fail to purchase or deliver the
contracted quantities of oil or natural gas, or a sudden, unexpected event
materially impacts oil or natural gas prices. Such contracts may also restrict
the ability of the Company to benefit from unexpected increases in oil and
natural gas prices. See Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Capital Resources, Liquidity and
Financial Condition--Changing Oil and Natural Gas Prices".
17
18
Forward-Looking Statements and Associated Risks. This Report
includes "forward-looking statements" within the meaning of various provisions
of the Securities Act and the Exchange Act. All statements, other than
statements of historical facts, included in this Report which address
activities, events or developments that the Company expects or anticipates will
or may occur in the future, including such things as estimated future net
revenues from oil and natural gas reserves and the present value thereof,
future capital expenditures (including the amount and nature thereof), business
strategy and measures to implement strategy, competitive strengths, goals,
expansion and growth of the Company's business and operations, plans,
references to future success, references to intentions as to future matters and
other such matters are forward-looking statements. These statements are based
on certain assumptions and analyses made by the Company in light of its
experience and its perception of historical trends, current conditions and
expected future developments as well as other factors it believes are
appropriate in the circumstances. However, whether actual results and
developments will conform with the Company's expectations and predictions is
subject to a number of risks and uncertainties, including general economic,
market or business conditions, the opportunities (or lack thereof) that may be
presented to and pursued by the Company, competitive actions by other oil and
natural gas companies, changes in laws or regulations, and other factors, many
of which are beyond the control of the Company. Consequently, all of the
forward-looking statements made in this Report are qualified by these
cautionary statements and there can be no assurance that the actual results or
developments anticipated by the Company will be realized or, even if
substantially realized, that they will have the expected consequences to or
effects on the Company or its business or operations.
Title to Properties
The Company's properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens,
including other mineral encumbrances and restrictions. The Company does not
believe that any of these burdens materially interferes with the use of such
properties in the operation of its business.
The Company believes that it has generally satisfactory title to or rights
in all of its producing properties. As is customary in the oil and natural gas
industry, minimal investigation of title is made at the time of acquisition of
undeveloped properties. Title investigation is made and title opinions of local
counsel are generally obtained only before commencement of drilling operations.
18
19
Employees
As of January 31, 1997, the Company had 201 full-time employees, none of
whom is represented by any labor union. Approximately 93 of such full-time
employees are field personnel involved in oil and natural gas producing
activities, trucking and transport activities and crude oil terminalling and
storage activities.
Item 2. PROPERTIES
The Company is an independent energy company engaged in the acquisition,
exploitation, development, exploration and production of crude oil and natural
gas and the marketing, transportation, terminalling and storage of crude oil.
The Company's upstream oil and natural gas activities are focused in the LA
Basin, the Sunniland Trend, the Illinois Basin and the Gulf Coast area of
Louisiana. The Company's downstream marketing, terminalling and storage
activities are concentrated in Oklahoma, Texas and the Gulf Coast area of
Louisiana. Plains' upstream operations contributed approximately 90% of the
Company's EBITDA for the fiscal year ending December 31, 1996, while the
Company's downstream activities accounted for the remainder. See Item 1,
"Business" for a discussion of the Company's exploration, acquisition,
development and exploitation activities and downstream businesses.
Oil and Natural Gas Reserves
The following tables set forth certain information with respect to the
Company's reserves based upon reserve reports prepared by the independent
petroleum consulting firms of H.J. Gruy and Associates, Inc. with respect to
the LA Basin Properties, Netherland, Sewell & Associates, Inc. with respect to
the Sunniland Trend and other minor properties, and Ryder Scott Company with
respect to the Illinois Basin Properties. Such reserve volumes and values were
determined under the method prescribed by the SEC which requires the
application of year-end prices for each year, held constant throughout the
projected reserve life.
19
20
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------
1994 1995 1996
-------------------- ------------------- -------------------
OIL GAS OIL GAS OIL GAS
(BBL) (MCF) (BBL) (MCF) (BBL) (MCF)
(IN THOUSANDS)
PROVED RESERVES
Beginning balance ............................ 38,810 49,397 61,459 51,009 94,408 43,110
Revisions of previous estimates .............. 16,834 4,365 5,423 2,792 19,424 6,641
Extensions, discoveries, improved recovery and
other additions ............................ 4,362 1,182 15,489 1,730 8,179 1,294
Sale of reserves ............................. (16) (446) (1,227) (9,773) (5) (12,491)
Purchase of reserves in place .............. 5,304 80 17,640 130 45 862
Production ................................... (3,835) (3,569) (4,376) (2,778) (6,055) (2,143)
-------- -------- -------- -------- -------- --------
Ending balance ............................... 61,459 51,009 94,408 43,110 115,996 37,273
======== ======== ======== ======== ======== ========
PROVED DEVELOPED RESERVES
Beginning balance ............................ 30,646 28,436 48,978 30,869 67,266 29,397
======== ======== ======== ======== ======== ========
Ending balance ............................... 48,978 30,869 67,266 29,397 86,515 25,629
======== ======== ======== ======== ======== ========
The following table sets forth the Present Value of Proved Reserves as of
December 31, 1994, 1995 and 1996.
1994 1995 1996
------------- ------------- --------------
(IN THOUSANDS)
Proved developed.................................. $ 191,578 $ 272,634 $ 574,686
Proved undeveloped................................ 37,793 94,146 190,088
------------- ------------- --------------
Total proved.................................... $ 229,371 $ 366,780 $ 764,774
============= ============== ==============
There are numerous uncertainties inherent in estimating quantities and
values of proved reserves and in projecting future rates of production and
timing of development expenditures, including many factors beyond the control
of the Company. Reserve engineering is a subjective process of estimating the
recovery from underground accumulations of oil and natural gas that cannot be
measured in an exact manner, and the accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation and judgment. Because all reserve estimates are to some degree
speculative, the quantities of oil and natural gas that are ultimately
recovered, production and operating costs, the amount and timing of future
development expenditures and future oil and natural gas sales prices may all
differ from those assumed in these estimates. In addition, different reserve
engineers may make different estimates of reserve quantities and cash flows
based upon the same available data. Therefore, the Present Value of Proved
Reserves shown above represents estimates only and should not be construed as
the current market value of the estimated oil and natural gas reserves
attributable to the Company's properties. In this regard, it should be noted
that oil prices at December 31, 1996, upon which estimated proved reserve
volumes, the Present Value of Proved Reserves and the Standardized Measure as of
such date are based, were at the highest year-end level since 1990. At December
31, 1996, the NYMEX Crude Oil Price was $25.92 per barrel, 33% higher than the
$19.55 per barrel at December 31, 1995. The information set forth in the
preceding tables includes revisions of reserve estimates attributable to proved
properties included in the preceding year's estimates. Such revisions reflect
additional information from subsequent exploitation and development activities,
production history of the properties involved and any adjustments in the
projected economic life of such properties resulting from changes in product
prices.
In accordance with the SEC guidelines, the reserve engineers'
estimates of future net revenues from the Company's properties and the present
value thereof are made using oil and natural gas sales prices in effect as of
the dates of such estimates and are held constant throughout the life of the
properties, except where such guidelines permit alternate treatment, including
the use of fixed and determinable contractual price escalations. The crude oil
price in effect at December 31, 1996, is based on the NYMEX Crude Oil Price of
$25.92 per Bbl with variations therefrom based on location and grade of crude
oil. The Company has entered into various fixed and floating
price collar arrangements to fix the NYMEX Crude Oil Price for a significant
portion of its crude oil production. On December 31, 1996, these arrangements
provided for a NYMEX Crude Oil Price for: (i) 12,000 barrels per day through
March 31, 1997, at $18.51 per barrel; (ii) 10,000 barrels per day from April 1,
20
21
1997, through April 30, 1997, at $18.85 per barrel; (iii) 9,000 barrels per day
from May 1, 1997, through June 30, 1997, at $18.85 per barrel; and (iv) 9,100
barrels per day from July 1, 1997, through December 31, 1997, at $18.59 per
barrel. The Company has entered into additional swap arrangements which provide
for a NYMEX Crude Oil Price ceiling of $24.00 per barrel and a price floor of
$19.50 per barrel for 4,000 barrels per day from January 1, 1997, through
December 31, 1997. Combined with an additional arrangement providing for 500
barrels per day from April 1, 1997 through December 31, 1997, at $22.00 per
barrel, these arrangements provide the Company with an average minimum price of
$18.96 per barrel on an average of approximately 14,250 barrels of oil per day
for 1997, but provide the Company with upside price participation for 4,000 of
such barrels up to $24.00 per barrel. At December 31, 1996, the Company also
had a fixed price arrangement on 4,500 barrels per day for 1998 at a NYMEX
Crude Oil Price of $19.24 per barrel. Location and quality differentials
attributable to the Company's properties are not included in the foregoing
prices. The agreements provide for monthly settlement based on the differential
between the agreement price and the actual NYMEX Crude Oil Price. The overall
average prices used in the reserve reports as of December 31, 1996, were $22.22
per Bbl of crude oil, condensate and natural gas liquids and $2.79 per Mcf of
natural gas. See Item 1, "Business--Product Markets and Major Customers".
Prices for natural gas and, to a lesser extent, oil are subject to substantial
seasonal fluctuations and prices for each are subject to substantial
fluctuations as a result of numerous other factors.
Since December 31, 1995, the Company has not filed any estimates of
total proved net oil or natural gas reserves with any federal authority or
agency other than the SEC. See Note 16 to the Company's Consolidated Financial
Statements appearing elsewhere in this Report for certain additional
information concerning the proved reserves of the Company.
PRODUCTIVE WELLS AND ACREAGE
As of December 31, 1996, the Company had working interests in 1,617
gross (1,616 net) active oil wells and 5 gross (1 net) active natural gas
wells. These totals do not include the Company's royalty and overriding royalty
interests in approximately 135 gross (4 net) producing oil and natural gas
wells.
The following table sets forth certain information with respect to the
developed and undeveloped acreage of the Company as of December 31, 1996.
DECEMBER 31, 1996
---------------------------------------------
Developed Acres(1) Undeveloped Acres(2)
--------------------- ---------------------
Gross Net Gross Net(3)
--------- --------- --------- ---------
California .............. 3,891 3,818 10 10
Florida ................. 12,044 11,852 96,257 80,774
Illinois ................ 15,887 13,885 33,653 15,416
Indiana ................. 1,155 854 2,562 1,216
Kansas .................. -- -- 52,433 41,496
Kentucky ................ -- -- 1,321 521
Louisiana(4) ............ 700 117 21,903 11,453
Oklahoma ................ 640 88 -- --
--------- --------- --------- ---------
Total .............. 34,317 30,614 208,139 150,886
========= ========= ========= =========
(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acres are acres on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether such acreage
contains proved reserves.
(3) Less than 2% of total net undeveloped acres are covered by leases that
expire in 1997 and 1998.
(4) Does not include approximately 19,000 gross (5,000 net) acres under
seismic option.
21
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DRILLING ACTIVITIES
Certain information with regard to the Company's drilling activities
during the years ended December 31, 1994, 1995 and 1996 is set forth below:
YEAR ENDED DECEMBER 31,
---------------------------------------------------
1994 1995 1996
--------------- --------------- ---------------
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
Exploratory Wells:
Oil ............................. 0.00 0.00 0.00 0.00 0.00 0.00
Natural gas ..................... 0.00 0.00 0.00 0.00 0.00 0.00
Dry ............................. 6.00 4.39 1.00 0.40 2.00 0.63
------ ------ ------ ------ ------ ------
Total ....................... 6.00 4.39 1.00 0.40 2.00 0.63
====== ====== ====== ====== ====== ======
Development Wells:
Oil ............................. 1.00 1.00 0.00 0.00 24.00 24.00
Natural gas ..................... 0.00 0.00 0.00 0.00 0.00 0.00
Dry ............................. 0.00 0.00 1.00 0.50 0.00 0.00
------ ------ ------ ------ ------ ------
Total ....................... 1.00 1.00 1.00 0.50 24.00 24.00
====== ====== ====== ====== ====== ======
Total Wells:
Producing ....................... 1.00 1.00 0.00 0.00 24.00 24.00
Dry ............................. 6.00 4.39 2.00 0.90 2.00 0.63
------ ------ ------ ------ ------ ------
Total ....................... 7.00 5.39 2.00 0.90 26.00 24.63
====== ====== ====== ====== ====== ======
At December 31, 1996, the Company was in the process of drilling 1
gross (.20 net) exploratory well. See Item 1, "Business--Acquisition and
Exploitation" and "--Productive Wells and Acreage" for additional information
regarding exploitation activities, including waterflood patterns, workovers and
recompletions.
PRODUCTION AND SALES
The following table presents certain information with respect to oil
and natural gas production attributable to the Company's properties, the
revenue derived from the sale of such production, average sales prices received
and average production costs during the three years ended December 31, 1994,
1995 and 1996.
YEAR ENDED DECEMBER 31,
---------------------------------
1994 1995 1996
--------- --------- ---------
(IN THOUSANDS, EXCEPT UNIT DATA)
Production:
Crude oil and natural gas liquids (Bbls) ........ 3,835 4,376 6,055
Natural gas (Mcf) ............................... 3,569 2,778 2,143
BOE ............................................. 4,430 4,839 6,412
Revenue:
Crude oil and natural gas liquids ............... $ 52,331 $ 61,241 $ 95,224
Natural gas ..................................... 4,903 2,839 2,377
--------- --------- ---------
Total .......................................... $ 57,234 $ 64,080 $ 97,601
========= ========= =========
Average sales price:
Crude oil and natural gas liquids (per Bbl) ..... $ 13.65 $ 13.99 $ 15.73
Natural gas (per Mcf) ........................... $ 1.37 $ 1.02 $ 1.11
Per BOE ......................................... $ 12.92 $ 13.24 $ 15.22
Production expenses per BOE ...................... $ 6.15 $ 6.25 $ 6.04
22
23
Crude Oil Storage and Terminalling Facility
In December 1993, the Company completed construction on the first phase of
the Cushing Terminal in Cushing, Oklahoma. The first phase of the facility
consists of two million barrels of shell storage capacity comprised of fourteen
100,000 barrel capacity tanks and four 150,000 barrel capacity tanks. See Item
1, "Business -- Downstream Activities".
Other Facilities
The Company currently leases offices containing approximately 46,000
square feet in Houston, Texas.
Item 3. LEGAL PROCEEDINGS
On July 9, 1987, Exxon filed an interpleader action in the United States
District Court for the Middle District of Florida, Exxon Corporation v. E. W.
Adams, et al., Case Number 87-976-CIV-T-23-B. This action was filed by Exxon to
interplead royalty funds as a result of a title controversy between certain
mineral owners in a field in Florida. One group of mineral owners, John W.
Hughes, et al. (the "Hughes Group"), filed a counterclaim against Exxon
alleging fraud, conspiracy, conversion of funds, declaratory relief, federal
and Florida RICO, breach of contract and accounting, as well as challenging the
validity of certain oil and natural gas leases owned by Exxon, and seeking
exemplary and treble damages. In March 1993, but effective November 1, 1992,
Calumet, a wholly-owned subsidiary of the Company, acquired all of Exxon's
leases in the field affected by this lawsuit. In order to address those
counterclaims challenging the validity of certain oil and natural gas leases,
which constitute approximately 10% of the lands underlying this unitized field,
Calumet filed a motion to join Exxon as plaintiff in the subject lawsuit, which
was granted July 29, 1994. In August 1994, the Hughes Group amended its
counterclaim to add Calumet as a counter- defendant. Exxon and Calumet filed a
motion to dismiss the counterclaims. On March 22, 1996, the Court granted
Exxon's and Calumet's motion to dismiss the counterclaims alleging fraud,
conspiracy, and federal and Florida RICO violations and challenging the
validity of certain of the Company's oil and natural gas leases but denied such
motion as to the counterclaim alleging conversion of funds. The Company has
reached an agreement in principle with all parties to settle this case. In
consideration for full and final settlement, and dismissal with prejudice of
all issues in this case, the Company has agreed to pay to the defendants the
total sum of $100,000, and release certain royalty amounts held in suspense and
in the court registry during the pendency of this case. Finalization of this
settlement has been delayed due to a dispute between the defendants over
certain title issues. The defendants have filed motions requesting the Court to
rule on this dispute, but no hearing date has been set. The Company does not
believe that this dispute will adversely affect the settlement reached between
the Company and the defendants.
23
24
Since the Company acquired the Sunniland Trend Properties in 1993,
substantially all crude oil production therefrom has been transported by a
third party pipeline company. The current pipeline service agreement (the
"Pipeline Agreement") will expire on March 31, 1997, unless modified or
extended. Subject to economic and other considerations, such agreement requires
the parties to negotiate in good faith to extend such agreement or enter into a
new agreement. The Company has been in negotiations with the pipeline company
to continue to transport all or a portion of the crude oil production on the
existing pipeline system. However, no agreements have been reached. As
a safeguard against the failure to agree on an extension or modification of the
Pipeline Agreement, the Company entered into a contingent agreement with a
local trucking company to transport part or all its crude oil production by
trucks. Except as noted below, the Company has in place the necessary
facilities to convert to trucking.
Approximately 60% of the Company's Sunniland Trend oil production is
derived from one field, the production from which is transported by its own
proprietary pipeline to a ten acre surface lease held by the Company on lands
owned by the Miccosukee Tribe of Indians of Florida (the "Tribe"). Such lease
is located at the interconnect with the third party's pipeline. In light of the
possibility that the Pipeline Agreement may not be modified or extended, the
Company commenced construction in late January of a storage tank and truck
loading facilities on this lease that would enable it to truck crude oil from
this location. The pipeline company has taken issue with the Company's
assertion of its rights to transport its crude oil production by trucks upon
the termination of the existing contract, alleging that it had recently
acquired an exclusive license to transport production from the Tribe's lands.
The Company notified the pipeline company that it believes these allegations
are without merit and that the exclusive license would be in violation of the
Company's lease with the Tribe. Subsequently, the Tribe's legal representatives
notified the pipeline company that the purported exclusive license claimed by
the pipeline company is void, unenforceable and of no force and effect.
However, the Tribal Chairman has directed the Company to cease its construction
operations on the lease, claiming that prior approval of such operations must
be approved by the Tribe and the Bureau of Indian Affairs (the "BIA"). The
Company believes its construction operations are in compliance with its lease
and that no prior approval is required from the Tribe or the BIA. The Company
is discussing this matter with representatives of the Tribe and is continuing
negotiations with the pipeline company. If these controversies are not
resolved, litigation could result and this portion of the Company's Sunniland
Trend production could be curtailed until trucking can be commenced or the
Company agrees to extend the Pipeline Agreement or enter into a new contract
with the pipeline company. The pipeline company is currently demanding that any
extension of the Pipeline Agreement provide for a rate which is approximately
$.15 per barrel above the current rate and which would be $.80 per barrel
higher than the alternative trucking rate.
The Company, in the ordinary course of business, is a claimant and/or a
defendant in various other legal proceedings in which its exposure,
individually and in the aggregate, is not considered material to the Company.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders, through
solicitation of proxies or otherwise, during the fourth quarter of the fiscal
year covered by this Report.
Executive Officers of the Company
Information regarding the executive officers of the Company is presented
below. All executive officers hold office until their successors are elected
and qualified.
Greg L. Armstrong, President and Chief Executive Officer Officer Since 1981
Mr. Armstrong, age 38, has been President, Chief Executive Officer and a
director of the Company since 1992. He was President and Chief Operating
Officer from October to December 1992, and Executive Vice President and Chief
Financial Officer from June to October 1992. He was Senior Vice President and
Chief Financial Officer from 1991 to June 1992, Vice President and Chief
Financial Officer from 1984 to 1991, Corporate Secretary from 1981 to 1988, and
Treasurer from 1984 to 1987.
William C. Egg, Jr., Senior Vice President Officer Since 1984
Mr. Egg, age 45, has been Senior Vice President of the Company since 1991.
He was Vice President- Corporate Development of the Company from 1984 to 1991
and Special Assistant-Corporate Planning from 1982 to 1984.
Cynthia A. Feeback, Controller and
Principal Accounting Officer Officer Since 1993
Ms. Feeback, age 39, has been Controller and Principal Accounting Officer
of the Company since 1993. She was Controller of the Company from 1990 to 1993
and Accounting Manager from 1988 to 1990.
Phillip D. Kramer, Vice President,
Chief Financial Officer and Treasurer Officer Since 1987
Mr. Kramer, age 41, has been Vice President and Chief Financial Officer of
the Company since 1992. He was Vice President and Treasurer from 1988 to 1992,
Treasurer from 1987 to 1988, and Controller from 1983 to 1987.
24
25
G. M. McCarroll, Vice President-Exploration and Land Officer Since 1989
Mr. McCarroll, age 39, became Vice President-Exploration and Land in
February 1996. He had been Vice President-Land of the Company since 1989,
except for the period of May through July 1991 when he was Vice President of a
land development company in Lafayette, Louisiana. From 1988 to 1989 he was a
consultant to the Company for acquisitions and land functions.
Michael R. Patterson, Vice President and General Counsel Officer Since 1985
Mr. Patterson, age 49, has been Vice President and General Counsel of the
Company since 1985 and Corporate Secretary since 1988.
Harry N. Pefanis, Senior Vice President Officer Since 1988
Mr. Pefanis, age 39, became Senior Vice President in February 1996. He had
been Vice President-Products Marketing of the Company since 1988. From 1987 to
1988 he was Manager of Products Marketing. From 1983 to 1987 he was Special
Assistant for Corporate Planning for the Company. Mr. Pefanis is also President
of Plains Marketing & Transportation Inc., a wholly-owned subsidiary of the
Company.
Mary O. Peters, Vice President - Administration and
Human Resources Officer Since 1991
Ms. Peters, age 48, has been Vice President-Administration and Human
Resources since 1991. She was Manager of Office Administration of the Company
from 1984 to 1991.
25
26
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The Company's $.10 par value common stock ("Common Stock") is listed and
traded on the American Stock Exchange under the symbol "PLX." The number of
stockholders of record of the Common Stock as of February 1, 1997, was 1,503.
For the periods indicated below, the following table sets forth the range
of high and low closing sales prices for the Common Stock as reported on the
American Stock Exchange Composite Tape.
High Low
1995:
1st Quarter ....................................... $ 7 3/4 $ 5 1/2
2nd Quarter ....................................... 9 3/4 7 5/8
3rd Quarter ....................................... 10 3/4 7 5/8
4th Quarter ....................................... 9 6 13/16
1996:
1st Quarter ....................................... $ 9 1/8 $ 7 7/16
2nd Quarter ....................................... 13 8 1/2
3rd Quarter ....................................... 14 7/8 11 3/4
4th Quarter ....................................... 16 5/8 12 7/8
The Company has not paid cash dividends on shares of the Common Stock
since the Company's inception and does not anticipate paying any cash dividends
on the Common Stock in the foreseeable future. In addition, the Company is
prohibited by provisions of the indenture governing the issue of $150 million
10.25% Senior Subordinated Notes Due 2006 (the "10.25% Notes") and the
Revolving Credit Facility from paying dividends on the Common Stock.
26
27
Item 6. SELECTED FINANCIAL DATA
The following selected historical financial information was derived from,
and is qualified by reference to, the Consolidated Financial Statements of the
Company, including the Notes thereto, appearing elsewhere in this Report.
The selected financial data should be read in conjunction with the Consolidated
Financial Statements, including the Notes thereto, and Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations".
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1992 1993 1994 1995 1996
--------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE INFORMATION)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and natural gas sales ............................. $ 38,400 $ 57,507 $ 57,234 $ 64,080 $ 97,601
Marketing, transportation and storage ................. 93,838 128,186 199,239 339,826 531,698
Other ................................................. 413 335 223 319 309
--------- --------- --------- --------- ---------
Total revenue ........................................... 132,651 186,028 256,696 404,225 629,608
--------- --------- --------- --------- ---------
Costs and expenses:
Production expenses ................................... 19,329 28,285 27,220 30,256 38,735
Purchases, transportation and storage ................. 92,107 124,390 193,049 333,460 522,167
General and administrative ............................ 8,592 7,724 6,966 7,215 7,729
Depreciation, depletion and amortization .............. 12,155 36,980(1) 16,305 17,036 21,937
Interest expense ...................................... 3,776 8,847 12,585 13,606 17,286
Litigation settlement ................................. -- -- -- -- 4,000(2)
--------- --------- --------- --------- ---------
Total expenses .......................................... 135,959 206,226 256,125 401,573 611,854
--------- --------- --------- --------- ---------
Income (loss) before income taxes and extraordinary item (3,308) (20,198) 571 2,652 17,754
Income tax expense (benefit) ............................ -- -- -- -- (3,898)
--------- --------- --------- --------- ---------
Income (loss) before extraordinary item ................. (3,308) (20,198) 571 2,652 21,652
Extraordinary item, net of income taxes ................. -- -- -- -- (5,104)(3)
--------- --------- --------- --------- ---------
Net income (loss) ....................................... $ (3,308) $ (20,198) $ 571 $ 2,652 $ 16,548
========= ========= ========= ========= =========
Net income (loss) per common and common equivalent share:
Before extraordinary item ............................. $ (.32) $ (1.77) $ .04 $ .16 $ 1.22
Extraordinary item, net of income taxes ............... -- -- -- -- (.29)
--------- --------- --------- --------- ---------
$ (.32) $ (1.77) $ .04 $ .16 $ .93
========= ========= ========= ========= =========
Weighted average number of common and
common equivalent shares .............................. 10,536 11,438 11,625 15,981 17,732
OTHER FINANCIAL DATA:
Cash flow from operations(4) ............................ $ 8,847 $ 16,782 $ 16,876 $ 19,688 $ 43,942(6)
EBITDA(5) ............................................... 12,623 25,629 29,461 33,294 61,184(6)
Net cash provided by operating activities ............... 11,435 10,397 18,369 16,984 39,008
Net cash used in investing activities ................... 53,104 76,451 40,158 64,398 52,496
Net cash provided by financing activities ............... 63,430 44,688 19,297 52,252 9,876
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
1992 1993 1994 1995 1996
--------- --------- --------- --------- ---------
BALANCE SHEET DATA:
Cash and cash equivalents ..... $ 25,149 $ 4,862 $ 2,791 $ 6,129 $ 2,517
Working capital (deficit) ..... 13,065 (13,986) (4,465) (4,749) (4,843)
Property and equipment, net ... 144,692 191,985 217,602 280,538 311,040
Total assets .................. 199,093 236,667 266,904 352,046 430,249
Long-term debt ................ 100,000 141,600 149,600 205,089 225,399
Other long-term liabilities ... 2,506 967 3,754 1,547 2,577
Redeemable preferred stock .... -- -- 20,937 -- --
Total stockholders' equity .... 63,333 44,997 46,462 77,029 95,572
- ---------------
(1) Includes a $20 million non-cash charge related to a writedown of the
capitalized costs of the Company's proved oil and natural gas properties
due to low crude oil prices at December 31, 1993.
(2) Represents charge related to the settlement of two lawsuits filed in 1992
and 1993. See Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Results of Operations".
(3) Relates to the early redemption in March 1996 of the Company's 12% Senior
Subordinated Notes due 1999.
(4) Net cash provided by operating activities before changes in assets and
liabilities.
(5) EBITDA means earnings before interest, taxes, depreciation, depletion,
amortization and other noncash items. EBITDA is commonly used by debt
holders and financial statement users as a measurement to determine the
ability of an entity to meet its interest obligations. EBITDA is not a
measurement presented in accordance with generally accepted accounting
principles ("GAAP") and is not intended to be used in lieu of GAAP
presentations of results of operations and cash provided by operating
activities.
(6) Excludes nonrecurring items during 1996. Such items include a $4 million
charge for settlement of two lawsuits filed during 1992 and 1993, a
benefit of $11 million related to the reversal of a portion of the
valuation allowance against the Company's deferred tax asset, and an $8.5
million ($5.1 million, net of tax) extraordinary charge from the early
redemption of the Company's 12% Senior Subordinated Notes due 1999.
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Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
For the three years ended December 31, 1996, the Company reported
significant increases in proved reserves, production and cash flow from oil and
natural gas producing activities. Such increases are primarily the result of
exploitation activities in the LA Basin Properties, the acquisition during 1994
of the remaining 50% interest in, and exploitation of, the Sunniland Trend
Properties and the fourth quarter 1995 acquisition and subsequent exploitation
of the Illinois Basin Properties. These three core areas are comprised
primarily of crude oil properties and together account for approximately 98% of
the Company's year-end 1996 proved reserves. See Item 1, "Business--
Acquisition and Exploitation--Current Exploitation Projects".
RESULTS OF OPERATIONS
For the year ended December 31, 1996, the Company reported net income
before nonrecurring items of $14.7 million, or $.83 per share, on total revenue
of $629.6 million. This compares with net income of $2.7 million on total
revenue of $404.2 million in 1995 and net income of $.6 million on total
revenue of $256.7 million in 1994. Earnings before interest, taxes,
depreciation, depletion and amortization ("EBITDA") increased 84% in 1996 to
$61.2 million from the $33.3 million reported in 1995 and 107% from the $29.5
million reported in 1994. Cash flow from operations (cash provided by operating
activities before changes in assets and liabilities) increased to $43.9 million
in 1996, 123% and 160% above the $19.7 million and $16.9 million reported in
1995 and 1994, respectively. Cash flow and EBITDA are also presented before
nonrecurring items. Net cash provided by operating activities was $39.0 million
for the year ended December 31, 1996 ($43 million excluding nonrecurring
items), as compared to $17.0 million for 1995 and $18.4 million in 1994. The
improvement in operating results is primarily attributable to increased
production volumes and expanded unit operating margins in the upstream segment
and continued growth in the downstream segment.
Nonrecurring items in 1996 include an $8.5 million extraordinary
charge ($5.1 million net of tax) associated with the early redemption of the
Company's 12% Senior Subordinated Notes due 1999 (the "12% Notes"), a $4.0
million charge related to the settlement of two lawsuits filed during 1992 and
1993 and an $11.0 million tax benefit related to the reversal of a portion of
the valuation reserve against the Company's net deferred tax asset. After
giving effect to such nonrecurring items, the Company reported net income for
1996 of $16.5 million, or $.93 per share. Before extraordinary items, net
income was $21.7 million or $1.22 per share.
The following table sets forth certain operating information of the
Company for the periods presented:
YEAR ENDED DECEMBER 31,
------------------------------
1994 1995 1996
-------- -------- --------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
AVERAGE DAILY PRODUCTION VOLUMES
Barrels of oil equivalent:
LA Basin (approximately 90% oil) 8.1 8.4 9.2
Sunniland Trend (100% oil) ...... 2.7 3.4 4.7
Illinois Basin (100% oil) ....... -- 0.6 3.5
Other ........................... 1.3 0.9 .1
-------- -------- --------
Total .......................... 12.1 13.3 17.5
======== ======== ========
UNIT ECONOMICS
Average sales price per BOE ...... $ 12.92 $ 13.24 $ 15.22
Production expenses per BOE ...... 6.15 6.25 6.04
-------- -------- --------
Gross margin per BOE ............. 6.77 6.99 9.18
Upstream G&A expenses per BOE .... 1.04 .99 .74
-------- -------- --------
Gross profit per BOE ............. $ 5.73 $ 6.00 $ 8.44
======== ======== ========
Oil and natural gas production volumes in 1996 totaled 6.4 million
BOE, a 33% increase over 1995's level of 4.8 million BOE and a 45% increase
over the 1994 level of 4.4 million BOE. Approximately 94% of 1996's equivalent
production volumes were crude oil. The Company's unit gross margin increased to
$9.18 per BOE in 1996, an improvement of 31% and 36% over the amounts reported
for 1995 and 1994, respectively. Unit gross profit, which deducts all
pre-interest
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cash costs attributable to the upstream segment, was $8.44 per BOE for 1996, up
41% and 47% over the 1995 and 1994 amounts, respectively.
The significant increase in production volumes is attributable to the
Company's acquisition and exploitation activities. As a result of exploitation
activities conducted over the last three years, 1996 average net daily
production from the LA Basin Properties increased to approximately 9,200 BOE
per day, up 800 BOE per day, or 10% over 1995 and 1,100 BOE per day, or 14%
over the 1994 level. Net production from the Company's Sunniland Trend
properties averaged approximately 4,700 barrels of oil per day in 1996, a 38%
increase compared to 3,400 barrels per day in 1995 and 74% over the 2,700
barrels per day in 1994. The Sunniland Trend's 1996 production includes the
impact of production from two key wells drilled and completed in 1996. A
development well was drilled in the Raccoon Point field and was completed and
placed on production in late March. During 1996, daily gross production from
this well averaged around 3,000 barrels of oil per day. A short radius
horizontal well was placed on production in mid-November and averaged
approximately 1,000 barrels of oil per day during 1996. The Company owns a 100%
working interest and an approximate 83% and 86% net revenue interest in each of
these wells, respectively. At December 31, 1996, these wells accounted for
approximately 60% of the Company's daily production from the Sunniland Trend
properties. Due to the high volume of production that is generated by very few
wells in the Sunniland Trend, abrupt or abnormal declines or downtime due to
mechanical, marketing, or other conditions on any of the properties in this
area could have a significant impact on production.
The year to year comparisons of production volumes and unit margins
were affected by sales of nonstrategic properties, the acquisition of the
Company's Illinois Basin properties in the fourth quarter of 1995 and the
acquisition of the remaining 50% interest in the Sunniland Trend properties
effective May 1, 1994. Net production attributable to properties sold totaled
.3 million BOE, or an average of approximately 1,000 BOE per day, during 1995
and .5 million BOE, or an average of approximately 1,300 BOE per day, in 1994.
Oil and natural gas revenues increased to $97.6 million in 1996 as
compared to $64.1 million in 1995 and $57.2 million in 1994 due to increased
production volumes and higher average product prices. The Company's average
product price, which represents a combination of fixed and floating price sales
arrangements and incorporates location and quality discounts from the benchmark
NYMEX Crude Oil Price, increased 15% to $15.22 per BOE in 1996 as compared to
$13.24 in 1995 and approximately 18% as compared to $12.92 per BOE in 1994. The
increased average product price was primarily attributable to increased crude
oil prices, the higher quality Illinois Basin production, a reduction in the
quality and location differentials for the Sunniland Trend and Illinois Basin
production and the December 1995 purchase of a production payment which
previously burdened the price on the LA Basin Properties. Financial swap
arrangements and futures transactions entered into by the Company to hedge
production are included in the foregoing prices. Such transactions had the
effect of decreasing the overall average price per BOE received by the Company
by $2.62 and $.17 in 1996 and 1995, respectively, and increasing the average
price by $.16 for 1994.
During 1996, the NYMEX Crude Oil Price averaged approximately $22.00
per barrel, up 20% as compared to an average of $18.40 in 1995. Although the
impact of higher commodity prices on the Company's results was limited due to
preexisting hedges, this commodity price increase over the prior year period,
as well as the effect on the Company's downstream operations of the strong
demand for crude oil, had a positive impact on net income before extraordinary
item of approximately $4.1 million and approximately $6.8 million on cash flow
and EBITDA, respectively, for 1996. Of this $6.8 million, approximately $6.2
million is related to unhedged production in the upstream segment and
approximately $.6 million is related to the Company's downstream activities.
Approximately 70% of the Company's crude oil production was hedged throughout
1996 at an average NYMEX Crude Oil Price of approximately $18.04 per barrel,
and accordingly, the Company did not receive the full benefit of the higher
NYMEX Crude Oil Price. The Company routinely hedges a portion of its crude oil
production. See "--Capital Resources, Liquidity and Financial
Condition--Changing Oil and Natural Gas Prices".
Average unit production expenses declined approximately 3% to $6.04
per BOE versus $6.25 per BOE in 1995 and 2% versus $6.15 per BOE in 1994.
However, unit production expenses for each of the Company's three core areas
decreased at greater percentages during 1996 from the 1995 levels, with the LA
Basin declining 4%, the Sunniland Trend declining 18% and the Illinois Basin
declining 30%. Such relationship is caused by the Illinois Basin properties,
which have higher unit production costs than the Company's other two core
properties. The Illinois Basin properties were acquired effective November 1,
1995, thus significantly skewing the weighted average expenses between the two
periods. Unit production expenses for the Illinois Basin properties, which
averaged $12.00 per BOE in the fourth quarter of 1995, averaged
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30
approximately $8.42 per BOE during 1996. The significant reduction in
production expenses for the Illinois Basin properties was a result of
operational modifications implemented throughout 1996. The reductions in
production expenses in the Sunniland Trend and LA Basin were attributable to
increased production from fields with a component of fixed production costs
that do not increase with incremental production, reimbursements received in
1996 for electricity overcharges relating to the LA Basin properties in the
previous year and improved operating practices. Total production expenses
increased to $38.7 million from $30.3 million and $27.2 million in 1995 and
1994, respectively, primarily due to the acquisition of the Illinois Basin
properties.
Unit G&A expense in the upstream segment decreased for the fourth
consecutive year. Unit G&A expense decreased 25% to $.74 per BOE during 1996
from $.99 per BOE during 1995. Unit G&A expense was $1.04 per BOE in 1994,
$1.34 per BOE in 1993 and $2.48 per BOE in 1992. These reductions were directly
attributable to increased production levels and to the Company's ongoing cost
reduction and cost control efforts.
Depreciation, Depletion and Amortization ("DD&A") per BOE declined to
$3.00 in 1996 from $3.02 in 1995 and $3.17 in 1994 primarily as a result of the
Company's acquisition and exploitation activities. Primarily as a result of
increased production levels, total DD&A for the year ended December 31, 1996
was $21.9 million as compared to $17.0 million and $16.3 million in 1995 and
1994, respectively.
The Company's downstream segment reported gross margin (revenues less
direct expenses of purchases, transportation, storage and terminalling) of $9.5
million for the year ended December 31, 1996, reflecting an approximate 50%
increase over the $6.4 million reported for the 1995 period and an approximate
54% increase over 1994. Gross revenues from this segment were $531.7 million,
$339.8 million and $199.2 million for 1996, 1995 and 1994, respectively. Gross
profit (gross margin less downstream G&A expenses) increased 66%, totaling $6.6
million versus $4.0 million in 1995, and 72% versus the $3.8 million in 1994.
Such results are directly attributable to continued growth in base business
activities of marketing and terminalling crude oil and strong crude oil demand
throughout 1996. Aggregate marketing and terminalling volumes averaged 115,000
barrels per day in 1996 versus 88,000 barrels per day in 1995 and 64,000
barrels per day in 1994. Downstream G&A expenses for 1995 and 1994 were
relatively constant at $2.4 million for each period, while the level for 1996
totaled approximately $3.0 million. The increase in downstream G&A expense in
1996 was attributable to the continued expansion of the Company's marketing and
terminalling activities.
Interest expense, net of capitalized interest, for 1996 increased to
$17.3 million as compared to $13.6 million in 1995 and $12.6 million in 1994,
primarily due to higher borrowing levels related to the Company's acquisition,
exploitation, development and exploration activities. During 1996, 1995 and
1994, the Company capitalized $3.6 million, $3.1 million and $2.7 million of
interest, respectively.
The Company and certain of its officers and directors and a former
director and officer were named in two class action lawsuits filed in 1992 and
1993 seeking an aggregate of approximately $90 million in compensatory damages
and punitive damages in an unspecified amount for alleged violations of the
federal securities laws and state common law arising out of certain alleged
misrepresentations and omissions in the Company's disclosure regarding its
onshore natural gas exploration activities. During 1996, the Company settled
such cases for a cash payment of approximately $6.3 million. Approximately $4.1
million of such amount was paid by the Company's insurance carrier and $2.2
million was paid by the Company. Taking into account prior costs incurred by
the Company to defend these suits, and for which the Company agreed to
relinquish its claims for reimbursement against its insurance company, this
settlement resulted in a charge to 1996 first quarter earnings of $4 million.
Effective in 1992, Financial Accounting Standard 109 ("FAS 109")
requires companies to record an asset or a liability, as appropriate for its
net tax position as a result of differences between financial reporting
standards and tax reporting requirements. The Company adopted FAS 109 in 1992
and at such time recorded a net deferred tax asset of approximately $20.8
million, but also recorded a valuation reserve against the full amount of such
asset to reflect management's uncertainty, based on all information then
available, with respect to the realization of such asset.
In the first quarter of 1996, the Company reduced its valuation
allowance resulting in the recognition of an $11 million credit to deferred
income tax expense. Based on recent and anticipated improvement in the
Company's outlook for sustained profitability, management believes that it is
more likely than not that it will generate taxable income sufficient to realize
$11 million of unreserved tax benefits associated with certain of the Company's
net operating loss ("NOL") carryforwards prior to their expiration. The reserve
adjustment incorporates management's assessment of the significant,
30
31
cumulative progress made by the Company over the last four years to reduce unit
expenses, increase unit gross margins and substantially increase its production
and proved reserves through its acquisition and exploitation activities. From
1992 to 1996, unit G&A expenses declined 70%, unit gross profit increased 77%
and production and proved reserves increased 144% and 205%, respectively. Such
reassessment is also reinforced by the refinancing of the 12% Notes in March
1996 and the increased liquidity and flexibility provided by such refinancing.
The remaining deferred tax asset was not recognized primarily due to
limitations imposed by the IRS regarding the utilization of NOLs generated
prior to certain of the Company's subsidiaries being acquired and the
uncertainty of utilizing the Company's investment tax credit ("ITC")
carryforwards. While the Company's tax planning strategies address certain of
these restrictions on the application of subsidiary NOLs, management is
currently uncertain as to the extent such strategies will be successful and
therefore concluded that a reserve for these amounts was appropriate.
Estimates of future taxable income generated using future net cash
flows contained in reserve reports prepared by independent consulting firms in
accordance with regulations prescribed by the SEC also indicate that the
unreserved portion of such deferred tax asset will be realized. Such reserve
data was utilized in calculating the Standardized Measure presented in the
Company's year-end financial statements. See Item 2,"Properties--Oil and
Natural Gas Reserves". Despite the significant turnaround achieved over the
last four years and the current outlook for profitability, due to the
uncertainties in the oil and natural gas industry, including but not limited to
forecasting production, proved reserves, product prices, production expenses
and similar events beyond management's control, there can be no assurance that
the Company will generate any earnings or specific level of continuing
earnings. The Company had carryforwards of approximately $183.4 million of
regular tax NOLs at December 31, 1996, which expire as follows: 1997 - $3.6
million; 1998 - $5.1 million; 1999 - $7.1 million; 2000 - $7.9 million; 2001 -
$4.4 million; 2002 - $11.8 million; 2003 - $9.4 million; 2004 - $0; 2005 - $7.2
million; 2006 - $1.0 million; 2007 - $16.4 million and thereafter through 2011
- - $109.5 million. Approximately $15.7 million of the regular tax NOL
carryforwards at December 31, 1996, may only be utilized to the extent certain
subsidiaries that generated the NOLs have taxable income. See Item 1,
"Business--Federal Taxation".
For the year ended December 31, 1996, the Company recognized a net
deferred tax benefit before extraordinary item of $3.9 million. Such amount
consists of a $7.1 million deferred tax provision on the Company's income
before extraordinary item and the $11 million valuation allowance reduction
previously discussed. In addition, the Company reported a $3.4 million deferred
tax benefit as an extraordinary item. Such deferred tax benefit was attributable
to the $8.5 million pre-tax first quarter extraordinary loss from the early
redemption of the 12% Notes. Although the Company recorded net income for 1995
and 1994, no provision for income taxes was reflected during these years, but
rather the valuation allowance discussed above was adjusted.
CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION
On March 19, 1996, the Company sold $150 million of Senior
Subordinated Notes due 2006, Series A, bearing a coupon rate of 10.25% (the
"Series A 10.25% Notes"). Such notes were issued pursuant to a Rule 144A
private placement at approximately 99.38% of the principal amount thereof to
yield 10.35%. On August 8, 1996, the Company exchanged a total of $149.5
million principal amount of the Series A 10.25% Notes for 10.25% Senior
Subordinated Notes due 2006, Series B, (the "Series B 10.25% Notes"). The
Series B 10.25% Notes are substantially identical (including principal amount,
interest rate, maturity and redemption rights) to the Series A 10.25% Notes for
which they were exchanged, except for certain transfer restrictions relating to
the Series A 10.25% Notes.
The Series A 10.25% Notes and the Series B 10.25% Notes (collectively,
the "10.25% Notes") are redeemable, at the option of the Company, on or after
March 15, 2001 at 105.13% of the principal amount thereof, at decreasing prices
thereafter prior to March 15, 2004, and thereafter at 100% of the principal
amount thereof plus, in each case, accrued interest to the date of redemption.
In addition, prior to March 15, 1999, up to $45 million in principal amount of
the 10.25% Notes are redeemable at the option of the Company, in whole or in
part, from time to time, at 110.25% of the principal amount thereof, with the
Net Proceeds of any Public Equity Offering (as both are defined in the
indenture under which the 10.25% Notes were issued ("the "Indenture")).
The Indenture contains covenants including, but not limited to the
following: (i) limitations on incurrence of additional indebtedness; (ii)
limitations on certain investments; (iii) limitations on restricted payments;
(iv) limitations on dispositions of assets; (v) limitations on dividends and
other payment restrictions affecting subsidiaries; (vi) limitations on
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transactions with affiliates; (vii) limitations on liens; and (viii)
restrictions on mergers, consolidations and transfers of assets. In the event
of a Change of Control and a corresponding Rating Decline, as both are defined
in the Indenture, the Company will be required to make an offer to repurchase
the 10.25% Notes at 101% of the principal amount thereof, plus accrued and
unpaid interest to the date of the repurchase. The 10.25% Notes are unsecured
general obligations of the Company and are subordinated in right of payment to
all existing and future senior indebtedness of the Company and are guaranteed
by all of the Company's principal subsidiaries.
Proceeds from the sale of the 10.25% Notes, net of offering costs,
were approximately $144.6 million and were used to redeem the 12% Notes at 106%
of the $100 million principal amount outstanding and, together with amounts
borrowed under the Revolving Credit Facility, to retire bridge indebtedness
associated with the Illinois Basin acquisition. Prior to redemption, the 12%
Notes had an average remaining life of three years and scheduled maturities of
$50 million in each of 1998 and 1999.
The Company has a $125 million revolving credit facility with a group
of five banks (the "Lenders"). The Revolving Credit Facility is secured by the
oil and natural gas properties of the Company and is guaranteed by all of the
Company's subsidiaries other than PMCT, Inc. ("PMCT"), which guarantees are
secured by substantially all of the oil and natural gas properties of the
Company and its subsidiaries and the stock of all guaranteeing subsidiaries.
The Cushing Terminal is not pledged as security for any of the Company's debt.
The borrowing base is currently set at $125 million and is subject to borrowing
base availability as determined from time to time by the Lenders in good faith,
in the exercise of the Lenders' sole discretion, and in accordance with
customary practices and standards in effect from time to time for oil and
natural gas loans to borrowers similar to the Company. Such borrowing base may
be affected from time to time by the performance of the Company's oil and
natural gas properties and changes in oil and natural gas prices. The Company
incurs a commitment fee of 1/2% per annum on the unused portion of the
borrowing base. The Revolving Credit Facility, as amended, matures on May 1,
1998, at which time the remaining outstanding balance converts to a term loan
which is repayable in twenty equal quarterly installments commencing August 1,
1998, with a final maturity of May 1, 2003. The Revolving Credit Facility bears
interest, at the Company's option of either LIBOR plus 1 3/8% or Prime Rate (as
defined therein). At December 31, 1996, outstanding borrowings under the
Revolving Credit Facility were $72.7 million. An additional $1.0 million was
reserved against the issuance of a standby letter of credit. The Revolving
Credit Facility contains covenants which, among other things, prohibit the
payment of cash dividends, limit the amount of consolidate debt, limit
the Company's ability to make certain loans and investments, and provide
that the Company must maintain a specified relationship between current
assets and current liabilities.
During 1996, Plains Marketing increased its uncommitted secured demand
transactional line of credit (the "Transactional Facility") with five banks to
$90 million. The purpose of the Transactional Facility is to provide standby
letters of credit to support the purchase of crude oil for resale and
borrowings to finance crude oil inventory which has been hedged against future
price risk. The Transactional Facility is secured by all of the assets of
Plains Marketing and is guaranteed by the Company. The Company's guarantee is
secured by a $1.0 million standby letter of credit issued on behalf of the
Company. At December 31, 1996, approximately $39.6 million in letters of credit
were outstanding under the Transactional Facility. None of the Company's
letters of credit under the Transactional Facility have ever been drawn.
Generally, purchases secured by the letters of credit and receivables generated
from the sale of crude oil are settled on a monthly basis.
PMCT has established a $20 million sublimit (the "Sublimit") within
the Transactional Facility for standby letters of credit and borrowings to
finance crude oil purchased in connection with operations at the Cushing
Terminal. Under the terms of the Sublimit, all purchases of crude oil inventory
financed are required to be hedged against future price risk on terms
acceptable to the lenders. Standby letters of credit and borrowings under the
Sublimit are secured by all of the assets of PMCT and are recourse only to the
subsidiary. Letters of credit under the Transactional Facility are issued for
up to seventy day periods and bear fees of 1.5% per annum. Borrowings incur
interest at the borrower's option of either (i) the Base Rate plus 5/8% or (ii)
LIBOR plus 2%. All financings under the Transactional Facility, which expires
in November 1997, are at the discretion of the lenders. Aggregate cash
borrowings by both subsidiaries are limited to $20 million. At December 31,
1996, no letters of credit or borrowings were outstanding under the Sublimit.
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33
At December 31, 1996, the Company had a working capital deficit of
approximately $4.8 million. The Company has historically operated with a
working capital deficit due primarily to ongoing capital expenditures that have
been financed through cash flow and the Revolving Credit Facility. The working
capital deficits at December 31, 1995 and 1994, were $4.7 million and $4.5
million, respectively.
The Company has made and will continue to make, substantial capital
expenditures for the acquisition, exploitation, development, exploration and
production of oil and natural gas reserves. Historically, the Company has
financed these expenditures primarily with cash generated by operations, bank
borrowings, and the sale of subordinated notes, common stock and preferred
stock. The Company intends to make an aggregate of approximately $67 million
in capital expenditures in 1997, including approximately $48 million on the
development and exploitation of its LA Basin, Sunniland Trend and Illinois Basin
properties, approximately $14 million on exploration and higher risk
exploitation activities primarily in the Sunniland Trend and the LA Basin and
approximately $5 million for various other capital items. In addition, the
Company intends to continue to pursue the acquisition of underdeveloped
producing properties. The Company believes that it will have sufficient cash
from operating activities and borrowings under the Revolving Credit Facility to
fund such planned capital expenditures.
Changing Oil and Natural Gas Prices
The Company is affected by changes in crude oil prices which have
historically been volatile. Although the Company has routinely hedged a
substantial portion of its crude oil production and intends to continue this
practice, substantial future crude oil price declines would have a negative
impact on the Company's overall results, and therefore its liquidity.
Furthermore, low crude oil prices could affect the Company's ability to raise
capital on terms favorable to the Company. In order to manage its exposure to
commodity price risk, the Company has routinely hedged a portion of its crude
oil production. For 1997, the Company has entered into various fixed price and
floating price collar arrangements. Such arrangements generally provide the
Company with downside price protection on approximately 14,000 barrels of oil
per day at a NYMEX Crude Oil Price of approximately $19.00 per barrel but
permit the Company to receive the benefit of increases in the NYMEX Crude Oil
Price up to $24.00 per barrel on 4,000 of such barrels per day. Thus, based on
the Company's average fourth quarter 1996 oil production rate, these
arrangements generally provide the Company with downside price protection for
80% of its production and upside price participation for 43% of its production
up to $24.00 per barrel, while 20% of such production and excess volumes, if
any, remain unhedged. In addition, the Company also has a fixed price
arrangement on 4,500 barrels per day for 1998 at a NYMEX Crude Oil Price of
$19.24 per barrel. Management intends to continue to maintain hedging
arrangements for a significant portion of its production. Such contracts may
expose the Company to the risk of financial loss in certain circumstances. See
Item 1, "Business--Product Markets and Major Customers".
Investing Activities
Net cash flows used in investing activities were $52.5 million, $64.4
million and $40.2 million for the years ended December 31, 1996, 1995 and 1994,
respectively. Included in such amounts are payments, net of cash received from
property sales and reimbursements from partners, for acquisition, exploration
and development costs of $49.9 million, $63.9 million and $39.6 million for the
same periods, respectively. Such payments for 1995 include $45.0 million
related to the cash portion of the acquisition of the Illinois Basin Properties
and for 1994 include approximately $12.4 million related to the cash portion of
the acquisition of the remaining 50% interest in the Sunniland Trend
Properties. The Company expended $2.6 million, $1.1 million and $2.1 million in
1996, 1995 and 1994, respectively, for other property additions, primarily for
downstream activities and computer equipment.
33
34
Financing Activities
Net cash provided by financing activities amounted to $9.9 million,
$52.3 million and $19.3 million for 1996, 1995 and 1994, respectively.
Aggregate proceeds from long-term borrowings for these same years were $263.7
million, $83.6 million and $70.0 million, respectively, while payments of
long-term debt were $248.1 million, $32.7 million and $60.5 million for the
respective periods. Financing activities during 1996 include net proceeds of
approximately $144.6 million from the Series A 10.25% Notes, approximately $107
million for the repayment of the 12% Notes, including the 6% call premium and
the net defeasance costs, and approximately $42 million for the repayment of
the Illinois Basin acquisition bridge indebtedness. The Illinois Basin
acquisition indebtedness of $42 million is included in aggregate financing
proceeds for 1995. Remaining long-term debt activity is primarily related to
advances received and payments made on the Revolving Credit Facility. Financing
activities during 1994 include net payments from short-term borrowings of $9.6
million related to the Transactional Facility. Such amounts were borrowed to
finance the purchase of crude oil inventory in 1993 which was sold in 1994.
Financing activities include proceeds from the sale of capital stock of $1.8
million, $.9 million and $20.6 million in 1996, 1995 and 1994, respectively.
Such proceeds in 1996 and 1995 were primarily from the exercise of employee
stock options while the 1994 proceeds were primarily from the issuance of the
preferred stock which was converted into Common Stock in 1995.
Commitments
Although the Company obtained environmental studies on its properties
in the LA Basin, Sunniland Trend and Illinois Basin and the Company believes
that such properties have been operated in accordance with standard oil field
practices, certain of the fields have been in operation for approximately 90
years, and current or future local, state and federal environmental laws and
regulations may require substantial expenditures to comply with such rules and
regulations.
Consistent with normal industry practices, substantially all of the
Company's oil and natural gas leases require that, upon termination of economic
production, the working interest owners plug and abandon non-producing
wellbores, remove tanks, production equipment and flow lines and restore the
wellsite. The Company has estimated that the costs to perform these tasks is
approximately $13 million, net of salvage value and other considerations. Such
estimated costs are amortized to expense through the unit-of-production method
as a component of accumulated depreciation, depletion and amortization. Results
from operations for 1996, 1995 and 1994 include $.8 million, $1.0 million and
$1.1 million, respectively, of expense associated with these estimated future
costs. For valuation and realization purposes of the affected oil and natural
gas properties, these estimated future costs are also deducted from estimated
future gross revenues to arrive at the estimated future net revenues and the
Standardized Measure disclosed in the accompanying Consolidated Financial
Statements.
34
35
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required to be provided in this item is included in the
Consolidated Financial Statements of the Company, including the Notes thereto,
attached hereto as pages F-1 to F-24 and such information is incorporated
herein by reference.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There were no disagreements on accounting and financial disclosure with
the Company's independent accountants.
PART III
Item 10.DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of the Company will be included in the
proxy statement for the 1997 Annual Meeting of Stockholders (the "Proxy
Statement") to be filed within 120 days after December 31, 1996, and is
incorporated herein by reference. Information with respect to the Company's
executive officers is presented in Part I, Item 4 of this Report.
Item 11.EXECUTIVE COMPENSATION
Information regarding executive compensation will be included in the Proxy
Statement and is incorporated herein by reference.
Item 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information, if any, regarding beneficial ownership of the Common Stock
will be included in the Proxy Statement and is incorporated herein by
reference.
Item 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding Certain Relationships and Related Transactions will
be included in the Proxy Statement and is incorporated herein by reference.
PART IV
Item 14.EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
35
36
(a) (1) Financial Statements
The financial statements filed as part of this report are listed in
the "Index to Consolidated Financial Statements" on Page F-1 hereof.
(2) Exhibits
2(a) -- Purchase and Sale Agreement dated
October 31, 1995, between Marathon and Crete, as amended by
that certain Amendment dated December 4, 1995, among
Marathon, Plains Resources Inc. and Plains Illinois Inc.
(incorporated by reference to Exhibit 2.1 to Form 8-K dated
Jan 1996).
3(a) -- Second Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3(a) to the Company's
Annual Report on Form 10-K for the year ended December 31,
1995).
3(b) -- Bylaws of the Company, as amended to date (incorporated by
reference to Exhibit 3(b) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993).
4(a) -- Specimen Common Stock Certificate (incorporated by
reference to Exhibit 4 to the Company's Form S-1
Registration Statement (Reg. No. 33-33986)).
4(c) -- Purchase Agreement for Stock Warrant dated May 16, 1994,
between Plains Resources Inc. and Legacy Resources, Co.,
L.P. (incorporated by reference to Exhibit 4(d) to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1994).
10(a)*-- Employment Agreement dated as of March 1, 1993, between the
Company and Greg L. Armstrong (incorporated by reference to
Exhibit 10(b) to the Company's Annual Report on Form 10-K
for the year ended December 31, 1993).
10(b)*-- The Company's 1991 Management Options (incorporated by
reference to Exhibit 4.1 to the Company's S-8 Registration
Statement (Reg. No. 33-43788)).
10(c)*-- The Company's 1992 Stock Incentive Plan (incorporated by
reference to Exhibit 4.3 to the Company's S-8 Registration
Statement (Reg. No. 33-48610)).
10(d)*-- The Company's Amended and Restated 401(k) Plan.
10(e) -- Restructure Agreement dated February 25, 1991, among
The Aetna Casualty and Surety Company, Aetna Life Insurance
Company and the Company (incorporated by reference to
Exhibit 10(i) to the Company's Annual Report on Form 10-K
for the year ended December 31, 1990).
10(f) -- Uncommitted Secured Transactional Line of Credit Facility
letter agreement dated as of August 23, 1995, between
Plains Marketing & Transportation Inc. and The First
National Bank of Boston, et al. (incorporated by reference
to Exhibit 10(m) of the Company's Annual Report on Form
10-K for the year ended 1995).
10(g) -- Uncommitted Secured Transactional Line of Credit Facility
letter agreement dated August 23, 1995 between PMCT Inc.
and The First National Bank of Boston, et al. (incorporated
by reference to Exhibit 10(n) of the Company's Annual
Report on Form 10-K for the year ended 1995).
10(h) -- Third Amended and Restated Credit Agreement dated as of
April 11, 1996 among the Company and ING (U.S.) Capital
Corporation, et al. (incorporated by reference to Exhibit
10(n) to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 1996).
10(i) -- First Amendment to Third Amended and Restated Credit
Agreement dated as of December 16, 1996, among the Company
and ING (U.S.) Capital Corporation, et al.
10(j) -- Amendment dated as of November 22, 1996 to Uncommitted
Secured Transactional Line of Credit between Plains
Marketing & Transportation Inc. and The First National Bank
of Boston, et al.
10(k) -- Amendment dated as of November 22, 1996 to Uncommitted
Secured Transactional Line of Credit between PMCT and The
First National Bank of Boston, et al.
36
37
10(l)*-- Stock Option Agreement dated August 27, 1996 between the
Company and Greg L. Armstrong.
10(m)*-- Stock Option Agreement dated August 27, 1996 between the
Company and William C. Egg Jr.
10(n) -- First Amendment to the Company's 1992 Stock Incentive Plan.
11(a) -- Statement regarding computation of per share earnings for
the year ended December 31, 1996.
11(b) -- Statement regarding computation of per share earnings for
the year ended December 31, 1995.
11(c) -- Statement regarding computation of per share earnings for
the year ended December 31, 1994.
21 -- Subsidiaries of the Company.
23(a) -- Consent of Price Waterhouse LLP.
23(b) -- Consent of Price Waterhouse LLP.
27 -- Financial Data Schedule
- ----------------
*A management contract or compensation plan.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed during the fourth quarter of 1996.
37
38
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
PLAINS RESOURCES INC.
Date: February 11, 1997 By: /s/ Phillip D. Kramer
-------------------------------------------
Phillip D. Kramer, Vice President and Chief
Financial Officer (Principal Financial
Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Date: February 11, 1997 By: /s/ Greg L. Armstrong
--------------------------------------
Greg L. Armstrong, President,
Chief Executive Officer and Director
(Principal Executive Officer)
Date: February 11, 1997 By: /s/ Robert A. Bezuch
--------------------------------------
Robert A. Bezuch, Director
Date: February 11, 1997 By: /s/ Tom H. Delimitros
--------------------------------------
Tom H. Delimitros, Director
Date: February 11, 1997 By: /s/ Cynthia A. Feeback
--------------------------------------
Cynthia A. Feeback, Controller and
Principal Accounting Officer
(Principal Accounting Officer)
Date: February 11, 1997 By: /s/ William M. Hitchcock
--------------------------------------
William M. Hitchcock, Director
38
39
Date: February 11, 1997 By: /s/ Phillip D. Kramer
---------------------------------------
Phillip D. Kramer, Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: February 11, 1997 By: /s/ Dan M. Krausse
---------------------------------------
Dan M. Krausse, Chairman of the Board
and Director
Date: February 11, 1997 By: /s/ John H. Lollar
---------------------------------------
John H. Lollar, Director
Date: February 11, 1997 By: /s/ Robert V. Sinnott
---------------------------------------
Robert V. Sinnott, Director
Date: February 11, 1997 By: /s/ J. Taft Symonds
---------------------------------------
J. Taft Symonds, Director
The Annual Report to Stockholders of the Company for the year ended
December 31, 1996, and the proxy statement relating to the annual meeting of
stockholders will be furnished to stockholders subsequent to the filing of this
Annual Report on Form 10-K. Such documents have not been mailed to stockholders
as of the date of this report.
39
40
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Accountants . . . . . . . . . . . . . . . . . . . . . F-2
Consolidated Balance Sheets as of December 31, 1995 and 1996 . . . . . . . F-3
Consolidated Statements of Operations for the years ended
December 31, 1994, 1995 and 1996 . . . . . . . . . . . . . . . . . . . F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 1994, 1995 and 1996 . . . . . . . . . . . . . . . . . . . . F-5
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1994, 1995 and 1996 . . . . . . . . . . F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . F-7
F-1
41
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and
Stockholders of Plains Resources Inc.:
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Plains Resources Inc. and its subsidiaries at December 31, 1995 and
1996, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSE LLP
Houston, Texas
February 10, 1997
F-2
42
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
DECEMBER 31,
-----------------------------------
1995 1996
-------------- --------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 6,129 $ 2,517
Accounts receivable 51,632 93,686
Inventory 5,120 4,563
Prepaids and other 751 1,092
-------------- --------------
Total current assets 63,632 101,858
-------------- --------------
PROPERTY AND EQUIPMENT
Oil and natural gas properties - full cost method:
Subject to amortization 328,712 384,019
Not subject to amortization 48,795 41,698
Downstream assets, primarily crude oil terminal and storage facility 32,788 35,122
Other property and equipment 7,789 8,275
-------------- --------------
418,084 469,114
Less allowance for depreciation, depletion and amortization (137,546) (158,074)
-------------- --------------
280,538 311,040
-------------- --------------
OTHER ASSETS 7,876 17,351
-------------- --------------
$ 352,046 $ 430,249
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and other current liabilities $ 56,573 $ 93,242
Interest payable 3,977 5,089
Royalties payable and drilling advances 6,364 7,859
Notes payable and other current obligations 1,467 511
-------------- --------------
Total current liabilities 68,381 106,701
BANK DEBT 98,000 72,700
SUBORDINATED DEBT 100,000 149,121
OTHER LONG-TERM DEBT 7,089 3,578
OTHER LONG-TERM LIABILITIES 1,547 2,577
-------------- --------------
275,017 334,677
-------------- --------------
COMMITMENTS AND CONTINGENCIES (NOTE 11)
STOCKHOLDERS' EQUITY
Common stock, $.10 par value, 50,000,000 shares authorized; issued and
outstanding 16,178,670 shares at December 31, 1995, and 16,518,645 shares
at December 31, 1996 1,618 1,652
Additional paid-in capital 118,090 120,051
Accumulated deficit (42,679) (26,131)
-------------- --------------
77,029 95,572
-------------- --------------
$ 352,046 $ 430,249
============== ==============
See notes to consolidated financial statements.
F-3
43
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
YEAR ENDED DECEMBER 31,
------------------------------------------
1994 1995 1996
----------- ----------- -----------
REVENUE
Oil and natural gas sales $ 57,234 $ 64,080 $ 97,601
Marketing, transportation and storage 199,239 339,826 531,698
Interest and other income 223 319 309
----------- ----------- -----------
256,696 404,225 629,608
----------- ----------- -----------
EXPENSES
Production expenses 27,220 30,256 38,735
Purchases, transportation and storage 193,049 333,460 522,167
General and administrative 6,966 7,215 7,729
Depreciation, depletion and amortization 16,305 17,036 21,937
Interest expense 12,585 13,606 17,286
Litigation settlement -- -- 4,000
----------- ----------- -----------
256,125 401,573 611,854
----------- ----------- -----------
Income before income taxes and extraordinary item 571 2,652 17,754
Income tax expense (benefit) -- -- (3,898)
----------- ----------- -----------
INCOME BEFORE EXTRAORDINARY ITEM 571 2,652 21,652
EXTRAORDINARY ITEM:
(Loss) on early extinguishment of debt, net of tax benefit -- -- (5,104)
----------- ----------- -----------
NET INCOME $ 571 $ 2,652 $ 16,548
=========== =========== ===========
Net income per common and common equivalent share:
Before extraordinary item $ 0.04 $ 0.16 $ 1.22
Extraordinary item -- -- (0.29)
----------- ----------- -----------
$ 0.04 $ 0.16 $ 0.93
=========== =========== ===========
Weighted average number of common and
common equivalent shares 11,625 15,981 17,732
=========== =========== ===========
See notes to consolidated financial statements.
F-4
44
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1994 1995 1996
------------ ------------ -------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 571 $ 2,652 $ 16,548
Items not affecting cash flows from
operating activities:
Depreciation, depletion and amortization 16,305 17,036 21,937
Loss on early extinguishment of debt, net of tax -- -- 5,104
Deferred income taxes -- -- (3,898)
Amortization of debt discount and other -- -- 251
Change in assets and liabilities resulting from operating activities:
Accounts receivable (17,578) (18,598) (41,046)
Inventory 8,050 405 551
Prepaids and other (115) 106 (64)
Accounts payable and other current liabilities 11,119 14,133 37,296
Interest payable 503 347 977
Royalties payable (486) 903 1,352
------------ ------------ -------------
Net cash provided by operating activities 18,369 16,984 39,008
------------ ------------ -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Cash received for the sale of oil and gas properties 314 7,355 3,066
Payment for acquisition, exploration and development costs (39,885) (71,250) (53,011)
Payment for additions to other property and assets (2,130) (1,120) (2,551)
Proceeds from escrow account 1,543 617 --
------------ ------------ -------------
Net cash used in investing activities (40,158) (64,398) (52,496)
------------ ------------ -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt 70,000 83,550 263,723
Proceeds from short-term debt 10,576 -- --
Proceeds from sale of capital stock, options and warrants 20,641 869 1,785
Principal payments of long-term debt (60,500) (32,717) (248,144)
Principal payments of short-term debt (20,214) -- --
Costs incurred to redeem long-term debt -- -- (6,468)
Other (1,206) 550 (1,020)
------------ ------------ -------------
Net cash provided by financing activities 19,297 52,252 9,876
------------ ------------ -------------
Net increase (decrease) in cash and cash equivalents (2,492) 4,838 (3,612)
Cash and cash equivalents, beginning of year 3,783 1,291 6,129
------------ ------------ -------------
Cash and cash equivalents, end of year $ 1,291 $ 6,129 $ 2,517
============ ============ =============
See notes to consolidated financial statements.
F-5
45
PLAINS RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(in thousands, except share data)
$1.30 CUMULATIVE ADDITIONAL
CONVERTIBLE PAID-IN ACCUMULATED
PREFERRED STOCK COMMON STOCK CAPITAL DEFICIT
------------------------ ---------------------- ---------- -----------
SHARES AMOUNT SHARES AMOUNT
---------- ---------- ---------- ----------
BALANCE AT JANUARY 1, 1994 48,070 $ 481 11,567,013 $ 1,157 $ 87,211 $ (43,852)
Warrant issued in connection
with an acquisition -- -- -- -- 2,000 --
Preferred stock dividends -- -- -- -- -- (1,171)
Capital stock issued upon exercise
of options and other -- -- 26,444 2 63 --
Net income for the year -- -- -- -- -- 571
---------- ---------- ---------- ---------- ---------- ----------
BALANCE AT DECEMBER 31, 1994 48,070 481 11,593,457 1,159 89,274 (44,452)
Preferred stock dividends -- -- -- -- -- (879)
Redemption of $1.30 Cumulative
Convertible Preferred Stock (48,070) (481) -- -- -- --
Conversion of Redeemable
Preferred Stock -- -- 3,628,125 363 21,406 --
Issuance of common stock in
connection with an acquisition -- -- 798,143 80 6,447 --
Capital stock issued upon exercise
of options and other -- -- 158,945 16 963 --
Net income for the year -- -- -- -- -- 2,652
---------- ---------- ---------- ---------- ---------- ----------
BALANCE AT DECEMBER 31, 1995 -- -- 16,178,670 1,618 118,090 (42,679)
Capital stock issued upon exercise
of options and other -- -- 339,975 34 1,961 --
Net income for the year -- -- -- -- -- 16,548
---------- ---------- ---------- ---------- ---------- ----------
BALANCE AT DECEMBER 31, 1996 -- $ -- 16,518,645 $ 1,652 $ 120,051 $ (26,131)
========== ========== ========== ========== ========== ==========
See notes to consolidated financial statements.
F-6
46
PLAINS RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION AND PRESENTATION
The consolidated financial statements include the accounts of Plains
Resources Inc. (the "Company"), and its wholly-owned subsidiaries. All
material intercompany accounts and transactions have been eliminated. Certain
reclassifications have been made to the prior year statements to conform with
the current year presentation.
The Company is an independent energy company engaged in the
acquisition, exploitation, development, exploration and production of crude oil
and natural gas and the marketing, transportation, terminalling and storage of
crude oil. The Company's upstream oil and natural gas activities are focused
in the Los Angeles Basin of California (the "LA Basin"), the Sunniland Trend of
South Florida (the "Sunniland Trend"), the Illinois Basin in southern Illinois
and the Gulf Coast area of Louisiana. Its downstream marketing activities are
concentrated in Oklahoma, where it owns a two million barrel, above ground
crude oil terminalling and storage facility (the "Cushing Terminal"), Texas and
the Gulf Coast area of Louisiana.
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 these estimates.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents consist of all demand deposits and funds
invested in highly liquid instruments.
INVENTORY
Crude oil inventory is carried at the lower of cost, as adjusted for
deferred hedging gains and losses, or market value using an average cost
method. Materials and supplies inventory is stated at the lower of cost or
market with cost determined on a first-in, first-out method.
OIL AND NATURAL GAS PROPERTIES
The Company follows the full cost method of accounting whereby all
costs associated with property acquisition, exploration and development
activities are capitalized. Such costs include internal general and
administrative costs such as payroll and related benefits and costs directly
attributable to employees engaged in acquisition, exploration and development
activities. General and administrative costs associated with production,
operations, marketing and general corporate activities are expensed as
incurred. These capitalized costs along with the Company's estimate of future
development and abandonment costs, net of salvage values and other
considerations, are amortized to expense by the unit-of-production method using
engineers' estimates of unrecovered proved oil and natural gas reserves. The
costs of unproved properties are excluded from amortization until the
properties are evaluated. Interest is capitalized on oil and natural gas
properties not subject to amortization and in the process of development.
Proceeds from the sale of properties are accounted for as reductions to
capitalized costs unless such sales involve a significant change in the
relationship between costs and the estimated value of proved reserves, in which
case a gain or loss is recognized. Unamortized costs of proved properties are
subject to a ceiling which limits such costs to the present value of estimated
future cash flows from proved oil and natural gas reserves of such properties
reduced by future operating expenses, development expenditures and abandonment
costs (net of salvage values), and estimated future income taxes thereon (the
"Standardized Measure") (See Note 16).
F-7
47
OTHER PROPERTY AND EQUIPMENT
Other property and equipment is recorded at cost. Acquisitions,
renewals, and betterments are capitalized; maintenance and repairs are
expensed. Depreciation on the Cushing Terminal is provided using the
straight-line method over an estimated useful life of forty years; other
property and equipment is also depreciated using the straight-line method over
estimated useful lives of three to seven years.
DEBT ISSUE COSTS
Costs incurred in connection with the issuance of long-term debt are
capitalized and amortized using the straight-line method over the term of the
related debt. Debt issue costs, net of accumulated amortization, as of
December 31, 1995 and 1996, in the amount of $3.4 million and $5.0 million,
respectively, are included in "Other Assets" in the accompanying Consolidated
Balance Sheets.
FEDERAL AND STATE INCOME TAXES
Income taxes are accounted for in accordance with SFAS No. 109,
"Accounting for Income Taxes." SFAS 109 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.
MARKETING AND TRANSPORTATION
The Company's marketing activities are conducted through its
wholly-owned subsidiary, Plains Marketing & Transportation Inc. ("Plains
Marketing"). Plains Marketing markets principally crude oil of third party
producers as well as crude oil and natural gas produced by the Company.
Marketing and transportation revenue is accrued at the time title to the
product sold transfers to the purchaser and purchases are accrued at the time
title to the product purchased transfers to Plains Marketing. The Company's
policy is to purchase only crude oil for which it has a market and to structure
its sales contracts so that crude oil price fluctuations do not materially
affect the gross margin which it receives.
HEDGING
The Company periodically uses certain instruments to hedge its
exposure to price fluctuations on oil and natural gas transactions. Recognized
gains and losses on hedge contracts are reported as a component of the related
transaction. Results for hedging transactions are reflected in oil and natural
gas sales to the extent related to the Company's oil and natural gas production
and in marketing, transportation and storage revenues to the extent related to
such activities.
STOCK OPTIONS
In October 1995, the Financial Accounting Standards Board issued
Statement No. 123 ("SFAS 123"), "Accounting for Stock Based Compensation". In
accordance with the provisions of SFAS No. 123, the Company applies APB Opinion
25 and related Interpretations in accounting for its stock option plans (See
Note 10).
NOTE 2 -- INVENTORY
Inventory consists of the following:
DECEMBER 31,
----------------------------
1995 1996
----------- ------------
(IN THOUSANDS)
Crude oil $ 2,884 $ 2,536
Materials and supplies 2,236 2,027
----------- ------------
$ 5,120 $ 4,563
=========== ============
F-8
48
Substantially all of the crude oil inventory at December 31, 1995 and 1996,
except for minor amounts of working inventory, was hedged with New York
Mercantile Exchange ("NYMEX") futures contracts or short-term physical delivery
contracts. Deferred gains or losses from inventory hedges are included as part
of the inventory cost and recognized when the related inventory is sold.
NOTE 3 -- LONG-TERM DEBT
Long-term debt consists of the following:
DECEMBER 31,
---------------------------
1995 1996
------------ ------------
(IN THOUSANDS)
Revolving Credit Facility, bearing interest
at weighted average interest rates of 8.2%
and 7.0%, at December 31, 1995 and 1996,
respectively $ 56,000 $ 72,700
Illinois Basin Acquisition Indebtedness,
bearing interest at 7.35%
at December 31, 1995 42,000 --
10 1/4% Senior Subordinated Notes
due 2006, net of unamortized discount
of $.9 million -- 149,121
12% Senior Subordinated Notes due 1999 100,000 --
Other long-term debt 8,533 4,089
------------ ------------
Total long-term debt $ 206,533 $ 225,910
Less current maturities (1,444) (511)
------------ ------------
$ 205,089 $ 225,399
============ ============
REVOLVING CREDIT FACILITY
The Company has a $125 million revolving credit facility (the "Revolving
Credit Facility") with a group of five banks (the "Lenders"). The Revolving
Credit Facility is secured by the oil and natural gas properties of the Company
and is guaranteed by all of the Company's subsidiaries other than PMCT, Inc.
("PMCT"), which guarantees are secured by substantially all of the oil and
natural gas properties of the Company and its subsidiaries and the stock of all
guaranteeing subsidiaries. The Cushing Terminal is not pledged as security for
any of the Company's debt. The borrowing base under the Revolving Credit
Facility at December 31, 1996, is set at $125 million and is subject to
borrowing base availability as determined from time to time by the Lenders in
good faith, in the exercise of the Lenders' sole discretion, and in accordance
with customary practices and standards in effect from time to time for oil and
natural gas loans to borrowers similar to the Company. Such borrowing base may
be affected from time to time by the performance of the Company's oil and
natural gas properties and changes in oil and natural gas prices. The Company
incurs a commitment fee of 1/2% per annum on the unused portion of the
borrowing base. The Revolving Credit Facility, as amended, matures on May 1,
1998, at which time the remaining outstanding balance converts to a term loan
which is repayable in twenty equal quarterly installments commencing August 1,
1998, with a final maturity of May 1, 2003. The Revolving Credit Facility
bears interest, at the Company's option of either LIBOR plus 1 3/8% or Prime
Rate (as defined therein). At December 31, 1996, outstanding borrowings under
the Revolving Credit Facility were $72.7 million. An additional $1 million was
reserved against the issuance of a standby letter of credit.
The Revolving Credit Facility contains covenants which, among other
things, prohibit the payment of cash dividends, limit the amount of
consolidated debt, limit the Company's ability to make certain loans and
investments, and provide that the Company must maintain a specified
relationship between current assets and current liabilities.
10.25% SENIOR SUBORDINATED NOTES DUE 2006
On March 19, 1996, the Company sold $150 million of Senior Subordinated
Notes due 2006, Series A, bearing a coupon rate of 10.25% (the "Series A 10.25%
Notes"). Such notes were issued pursuant to a Rule 144A private placement at
approximately 99.38% of the principal amount thereof to yield 10.35%. On
August 8, 1996, the Company exchanged a total of $149.5 million principal
amount of the Series A 10.25% Notes for 10.25% Senior Subordinated Notes due
2006, Series B, (the "Series B 10.25% Notes"). The Series B 10.25% Notes are
substantially
F-9
49
identical (including principal amount, interest rate, maturity and redemption
rights) to the Series A 10.25% Notes for which they were exchanged, except for
certain transfer restrictions relating to the Series A 10.25% Notes.
The Series A 10.25% Notes and the Series B 10.25% Notes (collectively, the
"10.25% Notes") are redeemable, at the option of the Company, on or after March
15, 2001 at 105.13% of the principal amount thereof, at decreasing prices
thereafter prior to March 15, 2004, and thereafter at 100% of the principal
amount thereof plus, in each case, accrued interest to the date of redemption.
In addition, prior to March 15, 1999, up to $45 million in principal amount of
the 10.25% Notes are redeemable at the option of the Company, in whole or in
part, from time to time, at 110.25% of the principal amount thereof, with the
Net Proceeds of any Public Equity Offering (as both are defined in the
indenture under which the 10.25% Notes were issued (the "Indenture")).
The Indenture contains covenants including, but not limited to the
following: (i) limitations on incurrence of additional indebtedness; (ii)
limitations on certain investments; (iii) limitations on restricted payments;
(iv) limitations on dispositions of assets; (v) limitations on dividends and
other payment restrictions affecting subsidiaries; (vi) limitations on
transactions with affiliates; (vii) limitations on liens; and (viii)
restrictions on mergers, consolidations and transfers of assets. In the event
of a Change of Control and a corresponding Rating Decline, as both are defined
in the Indenture, the Company will be required to make an offer to repurchase
the 10.25% Notes at 101% of the principal amount thereof, plus accrued and
unpaid interest to the date of the repurchase. The 10.25% Notes are unsecured
general obligations of the Company and are subordinated in right of payment to
all existing and future senior indebtedness of the Company and are guaranteed
by all of the Company's principal subsidiaries.
Proceeds from the sale of the 10.25% Notes, net of offering costs, were
approximately $144.6 million and were used to redeem the Company's 12% Senior
Subordinated Notes due 1999 (the "12% Notes") at 106% of the $100 million
principal amount outstanding and to retire $42 million of bridge bank
indebtedness which was incurred in December 1995 in connection with the
acquisition of all of the upstream oil and gas assets of Marathon Oil Company
("Marathon") in the Illinois Basin (the "Illinois Basin Properties"). The 12%
Notes were redeemed in April 1996, and the Company recognized an extraordinary
loss of $8.5 million, $5.1 million net of deferred income tax, in connection
therewith. Prior to redemption, the 12% Notes had an average remaining life of
three years and scheduled maturities of $50 million in each of 1998 and 1999.
OTHER LONG-TERM DEBT
Included in other long-term debt at December 31, 1995 and 1996 is $4.6
million and $4.1 million, respectively, related to the 1995 acquisition of a
production payment burdening certain of the Company's LA Basin properties.
Such other long-term debt has maturities of approximately $.5 million per year
in each of the years 1997 through 2004.
The aggregate amount of maturities of all long-term indebtedness for
the next five years is: 1997 - $.5 million, 1998 - $7.8 million, 1999 - $15.1
million, 2000 - $15.1 million and 2001 - $15.1 million.
NOTE 4 -- UNCOMMITTED SECURED TRANSACTIONAL GUIDANCE FACILITY
Plains Marketing has a $90 million Uncommitted Secured Demand
Transactional Line of Credit (the "Transactional Facility") with five banks.
The purpose of the Transactional Facility is to provide standby letters of
credit to support the purchase of crude oil for resale and borrowings to
finance crude oil inventory which has been hedged against future price risk.
The Transactional Facility is secured by all of the assets of Plains Marketing,
primarily accounts receivable and crude oil inventory, and is guaranteed by the
Company. The Company's guarantee is secured by a $1 million standby letter of
credit issued on behalf of the Company under the Revolving Credit Facility. At
December 31, 1996, approximately $39.6 million in letters of credit were
outstanding under the Transactional Facility.
PMCT, a wholly owned subsidiary of the Company, has established a $20
million sublimit (the "Sublimit") within the Transactional Facility for standby
letters of credit and borrowings to finance crude oil purchased in connection
with operations at the Cushing Terminal. Under the terms of the Sublimit, all
purchases of crude oil inventory financed are required to be hedged against
future price risk on terms acceptable to the lenders. Standby
F-10
50
letters of credit and borrowings under the Sublimit are secured by all of the
assets of PMCT and are recourse only to PMCT. At December 31, 1996, no letters
of credit or borrowings were outstanding under the Sublimit.
Letters of credit under the Transactional Facility are generally
issued for up to seventy day periods and bear fees of 1.5% per annum.
Borrowings incur interest at the borrower's option of either (i) the Prime Rate,
as defined, plus 5/8% or (ii) LIBOR plus 2%. All financings under the
Transactional Facility, which expires in November 1997, are at the discretion
of the lenders. Aggregate cash borrowings by both subsidiaries are limited to
$20 million.
NOTE 5 -- CAPITAL STOCK
COMMON STOCK
The Company has authorized capital stock consisting of 50 million
shares of Common Stock, $.10 par value, and 2 million shares of preferred
stock, $1.00 par value. At December 31, 1996, there were 16.5 million shares
of common stock ("Common Stock") issued and outstanding and no shares of
preferred stock outstanding.
STOCK WARRANTS AND OPTIONS
At December 31, 1996, the Company had warrants outstanding which
entitle the holders thereof to purchase an aggregate 850,000 shares of Common
Stock. Per share exercise prices and expiration dates for the warrants are as
follows: 100,000 shares at $7.50 expiring in 2000 and 750,000 shares at $6.00
expiring in 1999.
The Company has various stock option plans for its employees and
directors (See Note 10).
$1.30 PREFERRED STOCK
On October 31, 1995, all outstanding shares of the Company's $1.30
Cumulative Convertible Preferred Stock (the "$1.30 Preferred Stock") were
redeemed for $10 per share plus unpaid and accrued dividends of $.0325 per
share. The Company paid a total of $496,000, including unpaid dividends, to
redeem the $1.30 Preferred Stock.
REDEEMABLE PREFERRED STOCK
In July 1994, the Company sold in a private placement 200,000 shares
of its Series C Cumulative Convertible Preferred Stock (the "Series C Preferred
Stock") for net proceeds of approximately $20 million. On January 2, 1995, the
Company paid a dividend on the Series C Preferred Stock for the period of July
14, 1994, through December 31, 1994. The dividend amount of approximately
$937,000 was paid by issuing 9,370 additional shares of the Series C Preferred
Stock. On May 25, 1995, all 209,370 outstanding shares of the Series C
Preferred Stock, including accrued dividends, were converted into approximately
3.6 million shares of Common Stock. As a result of this conversion and the
redemption of the $1.30 Preferred Stock, all outstanding preferred stock has
been eliminated.
NOTE 6 -- EARNINGS PER SHARE
Primary earnings per share is based on the weighted average number of
common and common equivalent shares of Common Stock outstanding. Common
equivalent shares include employee stock options and warrants when dilutive.
Fully diluted earnings per share is based on the weighted average number of
common and common equivalent shares in addition to all other convertible
securities, when dilutive. The assumed conversion of these securities had a
dilutive effect of less than 3% for all periods presented and, accordingly, is
not reflected herein. For purposes of the earnings per share calculation,
Common Stock issued upon the conversion of the Series C Preferred
F-11
51
Stock is included in the weighted average number of shares outstanding
effective January 1, 1995. Additionally, 1994 earnings per share includes the
dilutive effect of additional shares of Series C Preferred Stock issued in 1995
as payment of 1994 accrued dividends (See Note 5).
NOTE 7 -- INCOME TAXES
The Company's deferred income tax assets (liabilities) at December 31,
1995 and 1996 consist of the tax effect of income tax carryforwards and
differences related to the timing of recognition of certain acquisition,
exploration, and development costs for financial and tax reporting as follows:
DECEMBER 31,
------------------------
1995 1996
---------- -----------
(IN THOUSANDS)
Deferred tax assets:
Tax credit carryforwards $ 988 $ 934
Percentage depletion carryforward 2,380 2,450
Net operating loss ("NOL") carryforwards 55,798 64,186
---------- -----------
59,166 67,570
Deferred tax liabilities:
Acquisition, exploration and development costs (40,871) (51,431)
----------- ------------
Net deferred tax asset 18,295 16,139
Valuation allowance (18,295) (8,376)
---------- -----------
$ -- $ 7,763
========== ===========
In the first quarter of 1996, the Company reduced its valuation
allowance resulting in the recognition of an $11 million credit to deferred
income tax expense. Based on recent and anticipated improvement in the
Company's outlook for sustained profitability, management believes that it is
more likely than not that it will generate taxable income sufficient to realize
$11 million of unreserved tax benefits associated with certain of the Company's
NOL carryforwards prior to their expiration. The reserve adjustment
incorporates management's assessment of the significant, cumulative progress
made by the Company over the last four years to reduce unit expenses, increase
unit gross margins and substantially increase its production and proved
reserves through its acquisition and exploitation activities. Such
reassessment is also reinforced by the first quarter 1996 settlement of
litigation and the refinancing of the Company's $100 million 12% Notes and the
increased liquidity and flexibility provided by such refinancing.
The remaining deferred tax asset was not recognized primarily due to
limitations imposed by the IRS regarding the utilization of NOLs generated
prior to certain of the Company's subsidiaries being acquired and the
uncertainty of utilizing the Company's investment tax credit ("ITC")
carryforwards. While the Company's tax planning strategies address certain of
these restrictions on the application of subsidiary NOLs, management is
currently uncertain as to the extent such strategies will be successful and
therefore concluded that a reserve for these amounts was appropriate.
At December 31, 1996, the Company had carryforwards of approximately
$183.4 million of regular tax NOL's, $7 million of statutory depletion, $.7
million of ITC and $.2 million of alternative minimum tax ("AMT") credit. Of
these amounts, utilization of approximately $15.7 million of the NOL
carryforwards and $.5 million of the ITC carryforwards are limited to certain
companies within the consolidated group. At December 31, 1996, the Company had
approximately $168.6 million of AMT NOL carryforwards available as a deduction
against future AMT income. The NOL carryforwards expire from 1997 through 2011.
F-12
52
Set forth below is a reconciliation between the income tax provision
computed at the United States statutory rate on income before income taxes and
the income tax provision per the accompanying Consolidated Statements of
Operations:
DECEMBER 31,
------------------------
1995 1996
----------- ----------
(IN THOUSANDS)
U.S. federal income tax provision at
statutory rate $ 902 $ 6,214
Reduction of valuation allowance against deferred
tax asset -- (11,000)
State income taxes -- 888
Utilization of tax attributes previously included
in allowance and other (902) --
----------- ----------
Income taxes on income before extraordinary item $ -- $ (3,898)
Income tax benefit allocated to extraordinary item -- (3,403)
----------- ----------
$ -- $ (7,301)
=========== ==========
In accordance with certain provisions of the Tax Reform Act of 1986, a
change of greater than 50% of the beneficial ownership of the Company within a
three-year period (an "Ownership Change") will place an annual limitation on
the Company's ability to utilize its existing tax carryforwards. Under the
Final Treasury Regulations issued by the Internal Revenue Service, the Company
does not believe that an Ownership Change has occurred as of December 31, 1996.
NOTE 8 -- ACQUISITIONS AND DISPOSITIONS
On December 22, 1995, Plains Illinois Inc., a wholly owned subsidiary
of the Company, acquired the Illinois Basin Properties, effective November 1,
1995. The aggregate purchase price was approximately $51.5 million including
associated transaction costs, of which approximately $6.5 million was paid for
by the issuance of 798,143 shares of Common Stock and the remaining $45 million
was paid in cash. The cash portion of the purchase price was financed through
a combination of advances under the Revolving Credit Facility and $42 million
of bridge bank indebtedness (See Note 3). The Illinois Basin Properties
include three Marathon operated oil fields, various nonoperated producing
properties and all of Marathon's oil and natural gas mineral interests, surface
fee and undeveloped leasehold within the Illinois Basin as well as Marathon's
geological, geophysical and engineering database for the entire region. At the
acquisition date, the Illinois Basin Properties added approximately 17.3
million barrels to the Company's proved oil reserves.
The following unaudited information reflects pro forma results of
operations as if the acquisition of the Illinois Basin Properties occurred on
January 1, 1995:
YEAR ENDED
DECEMBER 31, 1995
---------------------
HISTORICAL PRO FORMA
----------- ---------
Revenue (in thousands) $404,225 $ 426,294
Net income (in thousands) $ 2,652 $ 9,589
Net income per common and common equivalent share $ 0.16 $ 0.57
In December 1995, Stocker Resources Inc. ("Stocker"), a wholly-owned
subsidiary of the Company, acquired from Chevron USA ("Chevron") a production
payment burdening certain of Stocker's LA Basin properties. The production
payment had a face amount of approximately $30 million and was accounted for in
prior periods as an overriding royalty interest. Stocker also acquired a
fifteen year term mineral interest in certain of its LA Basin properties and
F-13
53
approximately ten acres of surface fee lands in Los Angeles County. These
assets were acquired in connection with a settlement agreement resolving
certain outstanding issues between Chevron and Stocker. In return for the
conveyance of the foregoing assets, Stocker agreed to forgive certain amounts
due it, dismiss existing lawsuits related to such claims and issue to Chevron a
ten year note for $4.6 million. The settlement also provides for a
modification of Stocker's existing contractual obligations to Chevron to plug
inactive wells, that Stocker continue its present activities to remediate oil
contaminated soil from existing wellsites on an accelerated basis, and for the
Company to guarantee the performance of such obligations.
During 1995 and 1996, the Company sold certain non-strategic oil and
natural gas properties located primarily in the Gulf Coast areas of Texas and
Louisiana and in Utah for net proceeds of approximately $7.4 million and $3.1
million respectively.
During 1994, Calumet Florida Inc. ("Calumet"), a wholly-owned
subsidiary of the Company, acquired the remaining 50% working interest in its
Sunniland Trend properties, increasing its working interest to approximately
100% and adding approximately five million barrels of oil to its proved reserve
base at the acquisition date. Operating results from the additional 50%
interest in the Sunniland Trend properties are included in the accompanying
financial statements effective May 1, 1994. The aggregate purchase price,
including acquisition costs, was approximately $13.6 million including the
issuance of a five year warrant to purchase 750,000 shares of Common Stock at
an exercise price of $6.00 per share. The acquisition was initially financed
by an $11.5 million bridge loan which was repaid in July 1994 with proceeds
from the sale of the Series C Preferred Stock (See Note 5).
NOTE 9 -- RETIREMENT PLAN
Effective June 1, 1996, the Company's Board of Directors adopted a
nonqualified retirement plan (the "Plan") for certain officers of the Company.
Benefits under the Plan are based on salary at the time of adoption, vest over
a 15 year period and are payable over a 15 year period commencing at age 60.
The Plan is unfunded.
Net pension expense for the year ended December 31, 1996, is comprised
of the following components (in thousands):
Service cost - benefits earned during the period $ 44
Interest on projected benefit obligation 31
Amortization of prior service cost 22
---------
Net pension expense $ 97
=========
The following schedule reconciles the funded status of the Plan with
amounts reported in the Company's balance sheet at December 31, 1996 (in
thousands).
Actuarial present value of benefit obligations:
Vested benefits $ 563
Nonvested benefits 191
---------
Accumulated benefit obligation $ 754
=========
Projected benefit obligation for service rendered to date $ 754
Plan assets at fair value --
---------
Projected benefit obligation in excess of plan assets 754
Prior service cost not yet recognized in net periodic pension expenses (657)
---------
Net pension liability 97
Adjustment required to recognize minimum liability 657
---------
Accrued pension cost liability recognized in the balance sheet $ 754
=========
The weighted-average discount rate used in determining the projected benefit
obligation was 8%.
F-14
54
NOTE 10 -- STOCK COMPENSATION PLANS
Historically, the Company has used stock options as a long-term
incentive for its employees, officers and directors under various stock option
plans. The exercise price of options granted to employees is equal to or
greater than the market price of the underlying stock on the date of grant.
Accordingly, consistent with the provisions of Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25"), no
compensation expense has been recognized in the accompanying financial
statements.
During 1996, the Company's shareholders approved the Company's 1996
Stock Incentive Plan, under which a maximum of 1.5 million shares of Common
Stock were reserved for issuance. The Company also has options outstanding
under its 1991 and 1992 plans, under which a maximum of 2.0 million shares of
Common Stock were reserved for issuance. Generally, terms of the options
provide for an exercise price of not less than the market price of the
Company's stock on the date of the grant, a pro rata vesting period of two to
four years and an exercise period of five to ten years.
In addition, during 1996, the Company granted performance options to
purchase a total of 500,000 shares of Common Stock to two executive officers.
Terms of the options provide for an exercise price of $13.50, the market price
on the date of grant, and an exercise period of five years. The performance
options vest when the price of the Common Stock trades at or above $24 per
share for any 20 trading days in any 30 consecutive trading day period or upon
a change in control if certain conditions are met.
A summary of the status of the Company's stock options as of December
31, 1996, 1995, and 1994, and changes during the years ending on those dates
are presented below:
1994 1995 1996
------------------------- ------------------------ -------------------------
WEIGHTED- WEIGHTED- WEIGHTED-
SHARES AVERAGE SHARES AVERAGE SHARES AVERAGE
FIXED OPTIONS (000) EXERCISE PRICE (000) EXERCISE PRICE (000) EXERCISE PRICE
- ----------------------------------- -------- -------------- --------- -------------- ---------- --------------
Outstanding at beginning of year 1,642 $ 6.40 1,519 $ 6.40 1,728 $ 6.40
Granted -- $ -- 365 $ 6.25 1,060 $ 11.34
Exercised (19) $ 5.00 (147) $ 5.92 (285) $ 6.26
Forfeited (104) $ 6.67 (9) $ 6.68 (68) $ 6.63
------ ----- ------
Outstanding at end of year 1,519 $ 6.39 1,728 $ 6.40 2,435 $ 8.56
====== ===== ======
Options exercisable at year-end 1,202 $ 6.28 1,233 $ 6.40 1,289 $ 6.78
====== ===== ======
Weighted-average fair value of
options granted during the year N/A $2.18 $ 3.19
In October 1995, the Financial Accounting Standards Board issued SFAS
No. 123, Accounting for Stock-Based Compensation. SFAS No. 123 establishes
financial accounting and reporting standards for stock-based employee
compensation. The pronouncement defines a fair value based method of
accounting for an employee stock option or similar equity instrument. SFAS No.
123 also allows an entity to continue to measure compensation cost for those
instruments using the intrinsic value-based method of accounting prescribed by
APB 25. The Company has elected to follow APB 25 and related Interpretations
in accounting for its employee stock options because, as discussed below, the
alternative fair value accounting provided for under SFAS No. 123 requires the
use of option valuation models that were not developed for use in valuing
employee stock options. Under APB 25, because the exercise price of the
Company's employee stock options equals the market price of the underlying
stock on the date of grant, no compensation expense has been recognized in the
accompanying financial statements. The Company will recognize compensation
expense under APB 25 in the future for the two performance options described
above, if certain conditions are met and such options vest.
Pro forma information regarding net income and earnings per share is
required by SFAS No.123 and has been determined as if the Company had accounted
for its employee stock options under the fair value method as provided therein.
The fair value for the options was estimated at the date of grant using a
Black-Scholes option pricing model with the following weighted-average
assumptions: risk-free interest rates of 7.5% for 1995 and 6.0% for 1996; a
volatility factor of the expected market price of the Company's common stock of
.36; no expected dividends; and weighted-average expected option lives of 3.5
years in 1995 and 2.7 years in 1996.
F-15
55
The Black-Scholes option valuation model and other existing models
were developed for use in estimating the fair value of traded options that have
no vesting restrictions and are fully transferable. In addition, option
valuation models require the input of and are highly sensitive to subjective
assumptions including the expected stock price volatility. Because the
Company's employee stock options have characteristics significantly different
from those of traded options, and because changes in the subjective input
assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not provide a reliable single measure of the
fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. Set forth
below is a summary of the Company's net income and earnings per share as
reported and pro forma as if the fair value based method of accounting defined
in SFAS No. 123 had been applied. The pro forma information is not meant to be
representative of the effects on reported net income for future years, because
as provided by SFAS 123, only the effects of awards granted in 1995 and 1996
are considered in the pro forma calculations.
1995 1996
----------------------------- -----------------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA
------------ ------------ ------------ ------------
Net income (in thousands) $ 2,652 $ 2,497 $ 16,548 $ 16,161
Earnings per share $ 0.16 $ 0.15 $ 0.93 $ 0.91
The following table summarizes information about stock options
outstanding at December 31, 1996:
WEIGHTED-
AVERAGE WEIGHTED-
NUMBER REMAINING AVERAGE NUMBER WEIGHTED-
OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE AVERAGE
RANGE OF EXERCISE PRICES AT 12/31/96 LIFE PRICE AT 12/31/96 EXERCISE PRICE
- --------------------------- ----------- ----------- ---------- ----------- --------------
$ 5.25 to $ 6.75 1,191 5.5 years $ 6.16 981 $ 6.12
$ 7.50 to $ 7.81 514 6.2 years $ 7.65 244 $ 7.57
$ 10.50 to $ 15.63 730 4.2 years $ 13.12 64 $ 12.36
-------- ---------
$ 5.25 to $ 15.63 2,435 5.3 years $ 8.56 1,289 $ 6.78
======== =========
During 1996, pursuant to a Board of Directors' resolution, the Company
contributed approximately 18,000 shares of Common Stock at a weighted average
price of $11.35 per share on behalf of participants in the Company's 401(k)
Savings Plan, representing a matching contribution by the Company for up to 50%
of an employee's contribution.
NOTE 11 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION
COMMITMENTS AND CONTINGENCIES
Minimum commitments in connection with office space and computer
equipment leased by the Company are: 1997 and 1998 - $1.0 million annually;
1999 - $.9 million; thereafter - $.8 million. Rental payments made under the
terms of similar arrangements totaled approximately $1.1 million in 1996 and
$1.2 million in each of the years ended December 31, 1995 and 1994.
In connection with its crude oil marketing, Plains Marketing provides
certain purchasers and transporters with irrevocable standby letters of credit
to secure the Company's obligation for the purchase of crude oil (See Note 4).
Generally, these letters of credit are issued for up to seventy day periods and
are terminated upon completion of each transaction. At December 31, 1996,
Plains Marketing had outstanding letters of credit of approximately $39.6
million. Such letters of credit are secured by the crude oil inventory and
accounts receivable of Plains Marketing
F-16
56
and are guaranteed by the Company. To date, no amounts have been drawn on such
letters of credit issued by the Company.
Under the amended terms of the asset purchase agreement between
Stocker and Chevron, commencing with the year beginning January 1, 2000, and
each year thereafter, Stocker is required to plug and abandon 20% of the then
remaining inactive wells, which currently aggregate approximately 250. To the
extent the Company elects not to plug and abandon the number of required wells,
the Company is required to escrow an amount equal to the greater of $25,000 per
well or the actual average plugging cost per well in order to provide for the
future plugging and abandonment of such wells. In addition, Stocker is
required to expend a minimum of $600,000 per year in each of the ten years
beginning January 1, 1996, and $300,000 per year in each of the succeeding five
years to remediate oil contaminated soil from existing well sites, provided
there are remaining sites to be remediated. In the event Stocker does not
expend the required amounts during a calendar year, Stocker is required to
contribute an amount equal to 125% of the actual shortfall to an escrow
account. Stocker may withdraw amounts from such escrow account to the extent
it expends excess amounts in a future year.
Although the Company obtained environmental studies on its properties
in the LA Basin, Sunniland Trend and Illinois Basin and the Company believes
that such properties have been operated in accordance with standard oil field
practices, certain of the fields have been in operation for more than 90 years,
and current or future local, state and federal environmental laws and
regulations may require substantial expenditures to comply with such rules and
regulations. In connection with the purchase of the Stocker Properties,
Stocker received a limited indemnity from Chevron for certain conditions if
they violate applicable local, state and federal environmental laws and
regulations in effect on the date of such agreement. While the Company
believes that it does not have any material obligations for operations
conducted prior to Stocker's acquisition of the properties from Chevron, other
than its obligation to plug existing wells and those normally associated with
customary oil field operations of similarly situated properties, there can be
no assurance that current or future local, state or federal rules and
regulations will not require it to spend material amounts to comply with such
rules and regulations or that any portion of such amounts will be recoverable
under the Chevron indemnity.
Consistent with normal industry practices, substantially all of the
Company's oil and natural gas leases require that, upon termination of economic
production, the working interest owners plug and abandon non-producing
wellbores, remove tanks, production equipment and flow lines and restore the
wellsite. The Company has estimated that the costs to perform these tasks is
approximately $13 million, net of salvage value and other considerations. Such
estimated costs are amortized to expense through the unit-of-production method
as a component of accumulated depreciation, depletion and amortization
("DD&A"). Results from operations for 1994, 1995 and 1996 include $1.1
million, $1 million and $.8 million, respectively, of expense associated with
these estimated future costs. For valuation and realization purposes of the
affected oil and natural gas properties, these estimated future costs are also
deducted from estimated future gross revenues to arrive at the estimated future
net revenues and the Standardized Measure disclosed in Note 16.
As is common within the industry, the Company has entered into various
commitments and operating agreements related to the exploration and development
of and production from certain proved oil and natural gas properties. It is
management's belief that such commitments will be met without a material
adverse effect on the Company's financial position.
INDUSTRY CONCENTRATION
Financial instruments which potentially subject the Company to
concentrations of credit risk consist principally of trade receivables. The
Company's accounts receivable are primarily from purchasers of oil and natural
gas products and exploration and production companies which own interests in
properties operated by the Company. This industry concentration has the
potential to impact the Company's overall exposure to credit risk, either
positively or negatively, in that the customers may be similarly affected by
changes in economic, industry or other conditions. The Company generally
requires letters of credit for receivables from customers which are not
considered investment grade, unless the credit risk can otherwise be mitigated.
There are a limited number of alternative methods of transportation
for the Company's production. Substantially all of the Company's LA Basin
crude oil and natural gas production and its Sunniland Trend and Illinois
F-17
57
Basin oil production are transported by pipelines owned by third parties. The
inability or unwillingness of these pipelines to provide transportation
services to the Company for a reasonable fee could result in the Company having
to find transportation alternatives, increased transportation costs to the
Company or involuntary curtailment of a significant portion of its crude oil
and natural gas production which could have a negative impact on future
results.
NOTE 12 -- LITIGATION
The Company and certain of its officers and directors and a former
director and officer were named in two class action lawsuits filed in 1992 and
1993 seeking an aggregate of approximately $90 million in compensatory damages
and punitive damages in an unspecified amount for alleged violations of the
federal securities laws and state common law arising out of certain alleged
misrepresentations and omissions in the Company's disclosure regarding its
onshore natural gas exploration activities. During 1996, the Company settled
such cases for a cash payment of approximately $6.3 million. Approximately
$4.1 million of such amount was paid by the Company's insurance carrier and
$2.2 million was paid by the Company. Taking into account prior costs incurred
by the Company to defend these suits and for which the Company agreed to
release its claims for reimbursement from its insurance carrier, this
settlement resulted in a charge to 1996 first quarter earnings of $4 million.
On July 9, 1987, Exxon filed an interpleader action in the United
States District Court for the Middle District of Florida, Exxon Corporation v.
E. W. Adams, et al., Case Number 87-976-CIV-T-23-B. This action was filed by
Exxon to interplead royalty funds as a result of a title controversy between
certain mineral owners in a field in Florida. One group of mineral owners,
John W. Hughes, et al. (the "Hughes Group"), filed a counterclaim against Exxon
alleging fraud, conspiracy, conversion of funds, declaratory relief, federal
and Florida RICO, breach of contract and accounting, as well as challenging the
validity of certain oil and natural gas leases owned by Exxon, and seeking
exemplary and treble damages. In March 1993, but effective November 1, 1992,
Calumet, a wholly-owned subsidiary of the Company, acquired all of Exxon's
leases in the field affected by this lawsuit. In order to address those
counterclaims challenging the validity of certain oil and natural gas leases,
which constitute approximately 10% of the lands underlying this unitized field,
Calumet filed a motion to join Exxon as plaintiff in the subject lawsuit, which
was granted July 29, 1994. In August 1994, the Hughes Group amended its
counterclaim to add Calumet as a counter-defendant. Exxon and Calumet filed a
motion to dismiss the counterclaims. On March 22, 1996, the Court granted
Exxon's and Calumet's motion to dismiss the counterclaims alleging fraud,
conspiracy, and federal and Florida RICO violations and challenging the
validity of certain of the Company's oil and natural gas leases but denied such
motion as to the counterclaim alleging conversion of funds. The Company has
reached an agreement in principle with all parties to settle this case. In
consideration for full and final settlement, and dismissal with prejudice of
all issues in this case, the Company has agreed to pay to the defendants the
total sum of $100,000, and release certain royalty amounts held in suspense and
in the court registry during the pendency of this case. Finalization of this
settlement has been delayed due to a dispute between the defendants over
certain title issues. The defendants have filed motions requesting the Court to
rule on this dispute, but no hearing date has been set. The Company does not
believe that this dispute will adversely affect the settlement reached between
the Company and the defendants.
The Company, in the ordinary course of business, is a claimant and/or
a defendant in various other legal proceedings in which its exposure,
individually and in the aggregate, is not considered material to the
consolidated financial statements.
NOTE 13 -- MAJOR CUSTOMERS
Koch Oil Company and Basis Petroleum, Inc. ("Basis"), formerly Phibro
Energy USA Inc., accounted for 16% and 11%, respectively, of the Company's
total revenue (exclusive of interest and other income) during 1996. Customers
accounting for more than 10% of total revenue for 1995 and 1994 were as
follows: 1995 -- Phibro Inc. ("Phibro") -- 16% and Basis -- 12%; 1994 --
Phibro -- 19% and Chevron -- 16%. Basis and Phibro Inc. are both subsidiaries
of Salomon Inc. No other single purchaser of the Company's products accounted
for as much as 10% of total sales during 1996, 1995 or 1994. Additionally
during 1996, Unocal, Marathon and Basis accounted for approximately 51%, 24%
and 20%, respectively, of the Company's oil and gas sales. During 1996,
Unocal, Marathon and Basis purchased the crude oil from the LA Basin
Properties, Illinois Basin Properties and the Sunniland Trend Properties,
respectively.
F-18
58
NOTE 14 -- FINANCIAL INSTRUMENTS
DERIVATIVES
The Company has only limited involvement with derivative financial
instruments, as defined in SFAS No. 119, "Disclosure About Derivative Financial
Instruments and Fair Value of Financial Instruments" and does not use them for
speculative trading purposes. The Company's principle objective is to hedge
exposure to price volatility on crude oil and natural gas. These arrangements
expose the Company to credit risk (as to counterparties) and to risk of adverse
price movements in certain cases where the Company's production is less than
expected.
The Company has entered into various fixed and floating price collar
arrangements to fix the NYMEX crude oil spot price ("NYMEX Crude Oil Price")
for a significant portion of its crude oil production. On December 31, 1996,
these arrangements provided for a NYMEX Crude Oil Price for: (i) 12,000 barrels
per day through March 31, 1997, at $18.51 per barrel; (ii) 10,000 barrels per
day from April 1, 1997, through April 30, 1997, at $18.85 per barrel; (iii)
9,000 barrels per day from May 1, 1997, through June 30, 1997, at $18.85 per
barrel; and (iv) 9,100 barrels per day from July 1, 1997, through December 31,
1997, at $18.59 per barrel. The Company has entered into additional swap
arrangements which provide for a NYMEX Crude Oil Price ceiling of $24.00 per
barrel and a price floor of $19.50 per barrel for 4,000 barrels per day from
January 1, 1997, through December 31, 1997. Combined with an additional
arrangement providing for 500 barrels per day from April 1, 1997 through
December 31, 1997, at $22.00 per barrel, these arrangements provide the Company
with an average minimum price of $18.96 per barrel on an average of
approximately 14,250 barrels of oil per day for 1997, but provide the Company
with upside price participation for 4,000 of such barrels up to $24.00 per
barrel. At December 31, 1996, the Company also had a fixed price arrangement
on 4,500 barrels per day for 1998 at a NYMEX Crude Oil Price of $19.24 per
barrel. Location and quality differentials attributable to the Company's
properties are not included in the foregoing prices. The agreements provide
for monthly settlement based on the differential between the agreement price
and the actual NYMEX Crude Oil Price. Gains or losses on the crude oil swaps
are recognized in the month of related production and are included in oil and
natural gas sales.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following disclosure of the estimated fair value of financial
instruments is made in accordance with the requirements of SFAS No. 107,
"Disclosures About Fair Value of Financial Instruments". The estimated fair
value amounts have been determined by the Company using available market
information and valuation methodologies described below. Considerable
judgement is required in interpreting market data to develop the estimates of
fair value. The use of different market assumptions or valuation methodologies
may have a material effect on the estimated fair value amounts.
F-19
59
The carrying values of items comprising current assets and current
liabilities approximate fair values due to the short-term maturities of these
instruments. Crude oil futures contracts permit settlement by delivery of the
crude oil and, therefore, are not financial instruments, as defined. The
carrying amounts and fair values of the Company's other financial instruments
are as follows:
DECEMBER 31,
-------------------------------------------------
1995 1996
---------------------- ----------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- -------- --------
(IN THOUSANDS)
DEBT:
Bank debt $ 98,000 $ 98,000 $ 72,700 $ 72,700
Subordinated debt 100,000 105,250 149,121 160,500
Other long-term debt 8,533 8,624 3,578 3,578
OFF BALANCE SHEET FINANCIAL
INFORMATION:
Unrealized loss on crude oil
swap agreements -- 5,438(1) -- 15,472(1)
- ---------------
(1) These amounts represent the calculated excess of the NYMEX Crude Oil
Price over hedge arrangements for future production of the Company's
properties as of December 31, 1995 and 1996. Such hedges, and therefore
the unrealized loss, have been fully deducted from estimated future
gross revenues to arrive at the estimated future net revenues and the
Standardized Measure disclosed in Note 16.
The carrying value of bank debt approximates its fair value as
interest rates are variable, based on prevailing market rates. The fair value
of subordinated debt was based on quoted market prices based on trades of
subordinated debt. Other long-term debt was valued by discounting the future
payments using the Company's incremental borrowing rate.
NOTE 15 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Selected cash payments and noncash activities were as follows:
YEAR ENDED DECEMBER 31,
------------------------------------
1994 1995 1996
--------- -------- --------
(IN THOUSANDS)
Cash paid for interest (net of amount
capitalized) $ 12,082 $ 13,259 $ 16,309
========= ======== ========
Noncash investing and financing
activities:
Series C Preferred Stock Dividends $ 937 $ -- $ --
========= ======== ========
Conversion of Series C Preferred $ -- $ 21,769 $ --
========= ======== ========
Detail of properties acquired for other
than cash:
Fair value of acquired assets $ 13,600 $ 56,100 $ --
Debt issued and liabilities assumed -- (4,600) --
Capital stock and warrants issued (1,250) (6,527) --
--------- -------- --------
Cash paid $ 12,350 $ 44,973 $ --
========= ======== ========
F-20
60
NOTE 16 -- OIL AND NATURAL GAS ACTIVITIES
COSTS INCURRED
The Company's oil and natural gas acquisition, exploration and development
activities are primarily conducted in the United States. The following table
summarizes the costs incurred in connection therewith during the last three
years.
YEAR ENDED DECEMBER 31,
---------------------------
1994 1995 1996
------- ------- -------
(IN THOUSANDS)
Property acquisition costs:
Unproved properties $ 6,150 $18,136 $ 728
Proved properties 13,222 41,194 3,087
Exploration costs 5,907 2,001 2,433
Exploitation and
development costs 15,570 22,681 45,007
------- ------- -------
$40,849 $84,012 $51,255
======= ======= =======
CAPITALIZED COSTS
The following table presents the aggregate capitalized costs subject
to amortization relating to the Company's oil and natural gas acquisition,
exploration, exploitation and development activities, and the aggregate related
DD&A.
DECEMBER 31,
-----------------------
1995 1996
---------- ----------
(IN THOUSANDS)
Proved properties $ 328,712 $ 384,019
Accumulated DD&A (131,063) (150,300)
---------- ----------
$ 197,649 $ 233,719
========== ==========
The DD&A rate per equivalent unit of production was $3.17, $3.02 and
$3.00 for the years ended December 31, 1994, 1995 and 1996, respectively.
COSTS NOT SUBJECT TO AMORTIZATION
The following table summarizes the categories of costs which comprise
the amount of unproved properties not subject to amortization.
DECEMBER 31,
-----------------------
1995 1996
---------- ----------
(IN THOUSANDS)
Acquisition costs $ 35,550 $ 31,940
Exploration costs 5,075 3,210
Capitalized interest 8,170 6,548
---------- ----------
$ 48,795 $ 41,698
========== ==========
Unproved property costs not subject to amortization consist mainly of
acquisition and lease costs and seismic data related to unproved areas. The
Company will continue to evaluate these properties over the lease terms;
however, the timing of the ultimate evaluation and disposition of a significant
portion of the properties has not been determined. Costs associated with
seismic data and all other costs will become subject to amortization as the
prospects to which they relate are evaluated. Approximately 14%, 38% and 9% of
the balance in unproved properties at December 31, 1996, related to additions
made in 1994, 1995, and 1996, respectively.
During 1994, 1995 and 1996, the Company capitalized $2.7 million, $3.1
million and $3.6 million, respectively, of interest related to costs of
unproved properties in the process of development.
SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED)
The following information summarizes the Company's net proved reserves
of oil (including condensate and natural gas liquids) and natural gas and the
present values thereof for the three years ended December 31, 1996. The
F-21
61
following reserve information is based upon reports of the independent
petroleum consulting firms of H.J. Gruy and Company with respect to the LA
Basin properties, Netherland, Sewell & Associates, Inc. with respect to the
Sunniland Trend Properties and other minor properties and Ryder Scott Company
with respect to the Illinois Basin Properties. The estimates are in accordance
with regulations prescribed by the Securities and Exchange Commission
(the "SEC").
In management's opinion, the reserve estimates presented herein, in
accordance with generally accepted engineering and evaluation principles
consistently applied, are believed to be reasonable. However, there are
numerous uncertainties inherent in estimating quantities and values of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the Company.
Reserve engineering is a subjective process of estimating the recovery from
underground accumulations of oil and natural gas that cannot be measured in an
exact manner, and the accuracy of any reserve estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. Because all reserve estimates are to some degree speculative, the
quantities of oil and natural gas that are ultimately recovered, production and
operating costs, the amount and timing of future development expenditures and
future oil and natural gas sales prices may all differ from those assumed in
these estimates. In addition, different reserve engineers may make different
estimates of reserve quantities and cash flows based upon the same available
data. Therefore, the Standardized Measure shown below represents estimates
only and should not be construed as the current market value of the estimated
oil and natural gas reserves attributable to the Company's properties. In this
regard, the information set forth in the following tables includes revisions of
reserve estimates attributable to proved properties included in the preceding
year's estimates. Such revisions reflect additional information from
subsequent exploitation and development activities, production history of the
properties involved and any adjustments in the projected economic life of such
properties resulting from changes in product prices.
ESTIMATED QUANTITIES OF OIL AND NATURAL GAS RESERVES (UNAUDITED)
The following table sets forth certain data pertaining to the
Company's proved and proved developed reserves for the three years ended
December 31, 1996.
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------------------
1994 1995 1996
----------------- ----------------- -----------------
OIL GAS OIL GAS OIL GAS
(BBL) (MCF) (BBL) (MCF) (BBL) (MCF)
------- -------- -------- ------- -------- -------
(IN THOUSANDS)
PROVED RESERVES
Beginning balance 38,810 49,397 61,459 51,009 94,408 43,110
Revisions of previous estimates 16,834 4,365 5,423 2,792 19,424 6,641
Extensions, discoveries, improved
recovery and other additions 4,362 1,182 15,489 1,730 8,179 1,294
Sale of reserves in-place (16) (446) (1,227) (9,773) (5) (12,491)
Purchase of reserves in-place 5,304 80 17,640 130 45 862
Production (3,835) (3,569) (4,376) (2,778) (6,055) (2,143)
------- -------- -------- ------- -------- -------
Ending balance 61,459 51,009 94,408 43,110 115,996 37,273
======= ======== ======== ======= ======== =======
PROVED DEVELOPED RESERVES
Beginning balance 30,646 28,436 48,978 30,869 67,266 29,397
======= ======== ======== ======= ======== =======
Ending balance 48,978 30,869 67,266 29,397 86,515 25,629
======= ======== ======== ======= ======== =======
F-22
62
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
The Standardized Measure of discounted future net cash flows relating
to proved oil and natural gas reserves is presented below:
DECEMBER 31,
--------------------------------------
1994 1995 1996
---------- ---------- ----------
(IN THOUSANDS)
Future cash inflows $ 894,434 $1,513,145 $2,681,007
Future development costs (62,695) (107,995) (111,785)
Future production expense (414,741) (692,008) (977,551)
Future income tax expense (69,911) (157,110) (437,654)
---------- ---------- ----------
Future net cash flows 347,087 556,032 1,154,017
Discounted at 10% per year (144,143) (251,191) (575,436)
---------- ---------- ----------
Standardized measure of
discounted future net cash flows $ 202,944 $ 304,841 $ 578,581
========== ========== ==========
The Standardized Measure of discounted future net cash flows
(discounted at 10%) from production of proved reserves was developed as
follows:
1. An estimate was made of the quantity of proved reserves and the future
periods in which they are expected to be produced based on year-end
economic conditions.
2. In accordance with SEC guidelines, the engineers' estimates of future net
revenues from the Company's proved properties and the present value
thereof are made using oil and natural gas sales prices in effect as of
the dates of such estimates and are held constant throughout the life of
the properties, except where such guidelines permit alternate treatment,
including the use of fixed and determinable contractual price escalations.
The crude oil price in effect at December 31, 1996, is based on the NYMEX
Crude Oil Price of $25.92 per barrel with variations therefrom based on
location and grade of crude oil. On February 7, 1997, the NYMEX Crude Oil
Price was $22.23 per barrel. The Company has entered into various fixed
price and floating price collar arrangements to fix or limit the NYMEX
Crude Oil Price for a significant portion of its crude oil production.
These prices are included in the reserve reports through the term of the
arrangements (See Note 14). The overall average prices used in the
reserve reports as of December 31, 1996, were $22.22 per barrel of crude
oil, condensate and natural gas liquids and $2.79 per Mcf of natural gas.
3. The future gross revenue streams were reduced by estimated future
operating costs (including production and ad valorem taxes) and future
development and abandonment costs, all of which were based on current
costs.
4. The reports reflect the estimated present value (discounted at 10%) of
future net revenue from the Company's proved oil and natural gas reserves
to be $229.4 million, $366.8 million and $764.8 million at December 31,
1994, 1995 and 1996, respectively. SFAS No. 69 requires the Company to
further reduce these estimates by an amount equal to the present value of
estimated income taxes which might be payable by the Company in future
years to arrive at the Standardized Measure. Future income taxes were
calculated by applying the statutory federal income tax rate to pretax
future net cash flows, net of the tax basis of the properties involved and
utilization of available tax carryforwards.
F-23
63
The principal sources of changes in the Standardized Measure of future
net cash flows for the three years ended December 31, 1996, are as follows:
YEAR ENDED DECEMBER 31,
---------------------------------------
1994 1995 1996
---------- ----------- -----------
(IN THOUSANDS)
Balance, beginning of year $ 130,489 $ 202,944 $ 304,841
Sales, net of production expenses (30,014) (33,824) (58,866)
Net change in sales and transfer
prices, net of production expenses 29,840 26,968 275,200
Changes in estimated future
development costs (9,477) (3,228) (5,188)
Extensions, discoveries and improved
recovery, net of costs 14,928 59,050 50,013
Previously estimated development costs
incurred during the year 2,995 3,136 19,662
Purchase of reserves in-place 16,919 64,214 2,253
Sales of reserves in-place (426) (11,381) (3,357)
Revision of quantity estimates 71,188 24,533 145,815
Accretion of discount 13,454 22,937 36,678
Net change in income taxes (22,377) (35,512) (124,254)
Changes in estimated timing of
production and other (14,575) (14,996) (64,216)
---------- ----------- -----------
Balance, end of year $ 202,944 $ 304,841 $ 578,581
========== =========== ===========
NOTE 17 -- QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table shows summary financial data for 1995 and 1996.
QUARTER ENDED
----------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
----------- ---------- ------------ -----------
1995 (IN THOUSANDS, EXCEPT PER SHARE DATA)
- ----
Revenues $ 93,647 $ 95,256 $ 103,607 $ 111,715
Operating profits $ 9,500 $ 10,312 $ 9,744 $ 10,953
Net income $ 319 $ 914 $ 483 $ 936
Net income per share $ .02 $ .06 $ .03 $ .06
1996
- ----
Revenues $ 123,513 $ 155,930 $ 169,245 $ 180,920
Operating profits $ 13,360 $ 18,353 $ 17,616 $ 19,377
Income before extraordinary item $ 9,216 $ 4,614 $ 3,486 $ 4,336
Net income $ 709 $ 6,502 $ 5,001 $ 4,336
Net income per share
Before extraordinary item $ .54 $ .26 $ .20 $ .24
Extraordinary item (.50) .11 .08 --
----------- ---------- ---------- ----------
$ .04 $ .37 $ .28 $ .24
=========== ========== ========== ==========
F-24
64
INDEX TO EXHIBITS
2(a) -- Purchase and Sale Agreement dated
October 31, 1995, between Marathon and Crete, as amended by
that certain Amendment dated December 4, 1995, among
Marathon, Plains Resources Inc. and Plains Illinois Inc.
(incorporated by reference to Exhibit 2.1 to Form 8-K dated
Jan 1996).
3(a) -- Second Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3(a) to the Company's
Annual Report on Form 10-K for the year ended December 31,
1995).
3(b) -- Bylaws of the Company, as amended to date (incorporated by
reference to Exhibit 3(b) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993).
4(a) -- Specimen Common Stock Certificate (incorporated by
reference to Exhibit 4 to the Company's Form S-1
Registration Statement (Reg. No. 33-33986)).
4(c) -- Purchase Agreement for Stock Warrant dated May 16, 1994,
between Plains Resources Inc. and Legacy Resources, Co.,
L.P. (incorporated by reference to Exhibit 4(d) to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1994).
10(a)*-- Employment Agreement dated as of March 1, 1993, between the
Company and Greg L. Armstrong (incorporated by reference to
Exhibit 10(b) to the Company's Annual Report on Form 10-K
for the year ended December 31, 1993).
10(b)*-- The Company's 1991 Management Options (incorporated by
reference to Exhibit 4.1 to the Company's S-8 Registration
Statement (Reg. No. 33-43788)).
10(c)*-- The Company's 1992 Stock Incentive Plan (incorporated by
reference to Exhibit 4.3 to the Company's S-8 Registration
Statement (Reg. No. 33-48610)).
10(d)*-- The Company's Amended and Restated 401(k) Plan.
10(e) -- Restructure Agreement dated February 25, 1991, among
The Aetna Casualty and Surety Company, Aetna Life Insurance
Company and the Company (incorporated by reference to
Exhibit 10(i) to the Company's Annual Report on Form 10-K
for the year ended December 31, 1990).
10(f) -- Uncommitted Secured Transactional Line of Credit Facility
letter agreement dated as of August 23, 1995, between
Plains Marketing & Transportation Inc. and The First
National Bank of Boston, et al. (incorporated by reference
to Exhibit 10(m) of the Company's Annual Report on Form
10-K for the year ended 1995).
10(g) -- Uncommitted Secured Transactional Line of Credit Facility
letter agreement dated August 23, 1995 between PMCT Inc.
and The First National Bank of Boston, et al. (incorporated
by reference to Exhibit 10(n) of the Company's Annual
Report on Form 10-K for the year ended 1995).
10(h) -- Third Amended and Restated Credit Agreement dated as of
April 11, 1996 among the Company and ING (U.S.) Capital
Corporation, et al. (incorporated by reference to Exhibit
10(n) to the Company's Quarterly Report on Form 10-Q for
the quarter ended March 31, 1996).
10(i) -- First Amendment to Third Amended and Restated Credit
Agreement dated as of December 16, 1996, among the Company
and ING (U.S.) Capital Corporation, et al.
10(j) -- Amendment dated as of November 22, 1996 to Uncommitted
Secured Transactional Line of Credit between Plains
Marketing & Transportation Inc. and The First National Bank
of Boston, et al.
10(k) -- Amendment dated as of November 22, 1996 to Uncommitted
Secured Transactional Line of Credit between PMCT and The
First National Bank of Boston, et al.
65
10(l)*-- Stock Option Agreement dated August 27, 1996 between the
Company and Greg L. Armstrong.
10(m)*-- Stock Option Agreement dated August 27, 1996 between the
Company and William C. Egg Jr.
10(n) -- First Amendment to the Company's 1992 Stock Incentive Plan.
11(a) -- Statement regarding computation of per share earnings for
the year ended December 31, 1996.
11(b) -- Statement regarding computation of per share earnings for
the year ended December 31, 1995.
11(c) -- Statement regarding computation of per share earnings for
the year ended December 31, 1994.
21 -- Subsidiaries of the Company.
23(a) -- Consent of Price Waterhouse LLP.
23(b) -- Consent of Price Waterhouse LLP.
27 -- Financial Data Schedule
- ----------------
*A management contract or compensation plan.