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, 1995.
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934.
COMMISSION FILE NUMBER 0-9408
PRIMA ENERGY CORPORATION
(Exact name of Registrant as specified in its charter)
DELAWARE 84-1097578
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1801 BROADWAY, SUITE 500, Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
(303) 297-2100
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act
NONE
Securities registered pursuant to Section 12(g) of the Act
COMMON STOCK, $0.015 PAR VALUE
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been subject
to such filing requirements for the past 90 days.
Yes [ x ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of the Form 10-K or any
amendment to this Form 10-K. [ ]
Aggregate market value of the 2,024,716 shares of Common Stock held by
non-affiliates of the Registrant as of March 15, 1996 was $23,410,779 (based
upon the mean of the closing bid and asked prices on the NASDAQ System).
As of March 15, 1996, Registrant had outstanding 3,880,396 shares of Common
Stock, $0.015 Par Value, its only class of voting stock.
DOCUMENT INCORPORATED BY REFERENCE
Parts of the following document are incorporated by reference to Part III of
the Form 10-K Report: Proxy Statement for the registrant's 1996 Annual
Meeting of Stockholders.
TABLE OF CONTENTS
Item
Page
PART I
1. and 2. BUSINESS and PROPERTIES.................................. 3
3. LEGAL PROCEEDINGS............................................. 13
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........... 14
PART II
5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS........................................... 14
6. SELECTED FINANCIAL DATA....................................... 15
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS........................... 16
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................... 20
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURES.......................... 20
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT........... 21
11. EXECUTIVE COMPENSATION....................................... 21
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT................................................... 21
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............... 21
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K..................................................... 22
<PAGE>
PART I
ITEMS 1 and 2. BUSINESS and PROPERTIES
GENERAL
Prima Energy Corporation (the "Company" or "Prima", which reference
includes the Company's wholly owned subsidiaries) was incorporated in April,
1980 as a start-up company for the purpose of engaging in the exploration
for, and the acquisition, development and production of crude oil and natural
gas and for other related business activities. In October of 1980 the
Company became publicly owned with a $3.6 million common stock offering. In
more recent years, the Company's activities, through its wholly owned
subsidiaries, have expanded to include oil and gas property operations,
oilfield services and natural gas marketing.
In 1986, the Company effected a one-for-fifteen reverse stock split
of the Company's common shares.
On December 18, 1992, the Company elected to change its fiscal year
end from June 30 to December 31, effective December 31, 1992. This change
was made, among other reasons, to enhance comparability of the Company's
results of operations with other oil and gas companies, most of which report
on a calendar year basis.
The Board of Directors of Prima approved a two for one stock split
of the Company's common stock, to shareholders of record on July 22, 1993,
distributed August 2, 1993. As a result, the number of shares of common
stock outstanding increased from 1,940,198 to 3,880,396 on the distribution
date. All share and per share amounts included in this Form 10-K have been
restated to show the retroactive effects of the stock split.
OIL AND GAS OPERATIONS
The Company's oil and gas activities are conducted in the Rocky
Mountain region with its current principal operations centered in the greater
Wattenberg Field area ("Wattenberg Area") in the Denver-Julesburg Basin in
northeastern Colorado. At December 31, 1995, the Company operated 310
producing wells. It is an objective of the Company to operate, when
possible, the oil and gas properties in which it has economic interests. The
Company believes, with the responsibility and authority as operator, it is in
a better position to control costs, safety, and timeliness of work as well as
other critical factors affecting the economics of a well.
The Company's net proved reserves as of December 31, 1995, as
estimated by in-house engineers, consisted of approximately 48 Bcf of natural
gas and 2,700,000 barrels of oil having an estimated pretax discounted
present value of approximately $47.8 million. Approximately 89% of Prima's
year end estimated reserves on a barrel of oil equivalent ("BOE") basis are
attributable to the Wattenberg Area; approximately 77% of the reserves are
proved developed reserves and approximately 74% are attributable to natural
gas reserves.
During 1995, natural gas spot prices in the Rocky Mountain region were
at their lowest levels since the deregulation of natural gas a decade ago.
A combination of mild weather, increased deliverability resulting from
drilling activity and technological advances, and increased Canadian imports
have all contributed to abundant Rocky Mountain natural gas supplies. The
average spot price for natural gas in the Rocky Mountain area during 1995 was
$1.09 per MMBtu, a 29% decline from the 1994 average spot price of $1.54 per
MMBtu. The average spot price for Rocky Mountain natural gas for calendar
years 1992 through 1994 was $1.61 per MMBtu. Due primarily to low natural
gas prices, management elected to defer additional drilling in Wattenberg
until the fourth quarter of 1995 and to reduce its drilling budget. The
drilling program conducted by Prima in the fourth quarter was its smallest in
the Wattenberg Area over the past several years. During 1995, Prima drilled
and completed 10 wells in Wattenberg compared to 44, 35 and 38 in the prior
three years.
While the Company plans to continue to develop and exploit
opportunities in the Wattenberg Area over the next few years, non-Wattenberg
activities will become an increasingly more important part of the Company's
growth strategy. The Company intends to build upon past success utilizing
the reserve, production and cash flow from core properties to create
additional opportunities. For the foreseeable future, the Company intends
to emphasize:
Further exploitation of the Company's inventory of potential
drillsites and recompletion opportunities based upon its technical
evaluation and activity in the areas where the Company is active.
Acquisition of both developed and undeveloped properties. The
Company regularly reviews opportunities for acquisition of assets or
companies related to the oil and gas industry which could expand or
enhance its existing business. At December 31, 1995, the Company
owned interests in 139,876 gross, 81,342 net undeveloped acres
primarily in the Rocky Mountain region and the Texas Panhandle.
Prospect generation - the Company intends to utilize its own
personnel and outside consultants to develop exploration prospects to
be drilled either solely by the Company or with partners on
lease acreage acquired in Prima's core areas. The Company also
acquires interests in exploratory or development projects through
acquisition or farm-ins.
1995 ACTIVITY
WATTENBERG AREA
The Wattenberg Area is located from approximately 10 to 50 miles
northeast of Denver, Colorado and encompasses an area in excess of 1,000
square miles. The Company has drilled and completed approximately 150 wells
in the area over the last five years. The Company's drilling and production
activities have been centered in a portion of the field where the primary
productive reservoirs are the Codell and Niobrara formations with occasional
production from the J-Sand, Parkman and Sussex formations. The Codell and
Niobrara reservoirs, which blanket large areas of the field, have moderate
porosity and low permeability, and therefore require fracture stimulation to
establish economic production. Recoverable reserves in any individual
wellbore are controlled by reservoir quality, reservoir thickness, the gas-
to-oil ratio, and fracture stimulation techniques. Over the years, the
Company has developed an extensive database of well information and
production history.
During the fall of 1995, the Company commenced a twelve well (11.87
net) drilling program in the Wattenberg Area. At December 31, ten of the
wells had been drilled, one well was drilling and the twelfth well was
drilled the second week in January. As of March 15, 1996, all of the wells
were completed and producing out of the Codell Formation. Additionally,
during 1995 the Company successfully recompleted two wells (2.0 net) in the
Codell Formation.
The Company intends to continue its development and exploitation
activities in the Wattenberg Area, with the timing of the activities largely
dependent on natural gas and oil prices. At December 31, 1995, the Company
owned or controlled nearly 350 potential drillsites in the Wattenberg Area.
A substantial number of these locations are in areas where the Company
believes historical results of older producing wells have either been
uneconomic or marginally economic. The Company's strategy includes drilling
and completing selected wells in these areas over the next few years
utilizing advanced drilling and completion techniques, improved marketing,
and cost controls in an attempt to improve the wells' economics and prove up
additional acreage. There is no assurance that all of these locations will
ultimately be drilled or that those wells drilled will ultimately prove to be
commercially productive. At December 31, 1995, the Company had classified 65
undrilled locations in Wattenberg as proved undeveloped reserves in its year-
end reserve report. Additionally, in Wattenberg the Company had included in
its year end reserve report 54 wells with zones behind pipe which have not
been completed; such wells have been identified as recompletion candidates.
The Company expects to continue its recompletion program by recompleting
several of these wells each year.
WIND RIVER BASIN
During 1994, Prima contributed approximately 27 net acres to the
formation of a 440 acre federal unit, the Cave Gulch Unit, in which Prima
owns a 6% interest. The unit is located on the northeastern margin of the
Wind River Basin in central Wyoming. The unit was formed to target a thick
section of lenticular sandstones in the Fort Union and Lance formations of
Tertiary and Upper Cretaceous age. In August of 1994, the Cave Gulch Federal
Unit #1 was drilled and discovered a significant natural gas field in the
Lance sandstone below the Owl Creek Thrust. The well began flowing on-line
December 2, 1994 at rates of approximately 9 to 10 MMcf of natural gas per
day and 100 barrels of oil per day. After one year of production, the well
continues to produce at these approximate rates.
During 1995, Prima participated with a 6% non-operated working
interest in eight additional wells drilled within the unit. At December 31,
1995, four of the wells were producing, one was shut-in and three were in
various stages of completion. At March 15, 1996, two of the three wells had
been completed and were also producing and the third was being tested.
January 1996 production rates from unit wells approximated 64 MMcf of
natural gas per day and 350 barrels of oil per day. Approximately 7% of
Prima's year end reserves on a BOE basis were attributable to the Cave Gulch
Unit. The Company owns working interests ranging from 6% to 50% in 4,221
gross, 691 net acres in an approximate radius of two miles from the Cave
Gulch Federal Unit #1. Prima intends to participate for its 6% interest in
any additional unit wells to be drilled in the future.
Currently, the pipelines taking gas from the Cave Gulch area are
operating at capacity. Plans have been announced by the pipeline companies
to expand their take-away capacity and to expand their delivery capabilities
into the mid-continent gas markets. Several of the wells at Cave Gulch are
near raptor nesting areas. Primarily due to the proximity of raptor nesting
sites, the Bureau of Land Management has directed that an Environmental
Impact Statement ("EIS") be prepared covering the Cave Gulch Unit and
surrounding lands. During the period in which this study is being conducted,
drilling activities will be substantially curtailed. Production activities,
however, will continue. The timing of future drilling will be impacted by
the pipeline expansions, completion of the EIS and the timing of obtaining
drilling permits after meeting various governmental regulations and
requirements. It is unlikely that additional wells will be drilled in the
Cave Gulch area prior to the summer of 1996 at the earliest.
Prima has been active in the area of the Cave Gulch discovery since
1987. The Company participated during 1987 and 1988 as a non-operating
working interest owner in the drilling and completion of two gas wells in the
Frontier Formation at depths of approximately 2,700 feet. The wells are
believed to be capable of modest commercial production but have not been
connected to a sales line. Due to the high volumes of natural gas being
produced in the area, pipeline constraints postponed the anticipated
hook-up of these two wells in 1995. The Company owns a 20% interest in the
two wells. The Cave Gulch Federal Unit #1 is approximately two miles from
the shallow Frontier wells.
During the summer of 1995, the Company participated in the drilling
of one shallow operated exploratory well (.375 net) in Natrona County,
Wyoming. This well has been plugged and abandoned. The Company also
participated with a 24% non-operated working interest in the drilling and
attempted completion of the Waltman Federal 43-23 Fort Union test well on the
southern end of the Waltman structure in Natrona County, Wyoming. That well
also is non-commercial, but to date has not been plugged and abandoned.
BONNY FIELD
During the latter part of 1994, Prima and the other working interest
owners at the Bonny Field located in Yuma County, Colorado, entered into a
comprehensive, confidential settlement agreement which resolved years of
disputes and litigation involving this field. As a result of this
settlement, Prima received $1,200,000 in net settlement proceeds and
increased its working interest in the field from approximately 1.5625% to
15.5%, which included the exchange of net profits interests for additional
working interests. Additionally, Prima increased its interest in the
gathering and compression entity, Bonny Gathering Company, from approximately
6.4% to 15.5%. The significant terms of the gas purchase agreement covering
this field have been litigated and the Courts have upheld the working
interest owner positions regarding the contract price (the contract price is
$5.90 per MMBtu), new wells (new wells qualify for the $5.90 per MMBtu
price), market-out (the purchaser does not have a market out), take-or-pay
(the contract provides for 95% take-or-pay) and term (the purchaser is
obligated to continue to purchase the gas beyond the primary term of the
contract, May 2002). The purchaser appealed the Court's ruling on the term
provision. In December of 1995, the Tenth Circuit Court of Appeals affirmed
the District Court's decision on the term provision. In March of 1996, the
purchaser filed a Petition for Writ of Certiorari with the United States
Supreme Court concerning the term provision.
During 1995, the working interest owners drilled 26 development wells
at the Bonny Field. All 26 wells have been completed and are producing in
the Niobrara Formation at a depth of approximately 1,700 feet. Production at
the Bonny Field has increased from approximately 2,000 Mcf per day at
December 31, 1994 to approximately 5,000 Mcf per day at December 31, 1995.
Approximately 4% of Prima s year end reserves were attributable to the Bonny
Field. An additional four development wells have been drilled, completed and
placed on production during the first quarter of 1996. The Company intends
to participate in the ongoing development of the Bonny Field.
OTHER DRILLING ACTIVITY
During 1995, the Company agreed to the formation of a federal unit and
participated for a 6% non-operated working interest in the Eldorado 15-1
exploratory well in White Pine County, Nevada. This high risk well with big
target reserve potential was unsuccessful and has been plugged and abandoned.
In California, Prima participated with a 10% working interest in an
8,000 foot test well on a prospect covering approximately 14,000 gross acres
in the San Joaquin Basin. The well was drilled in December 1995 and tested
in January 1996. The well was not commercially productive and was plugged
and abandoned.
PRODUCTION
The Company's net natural gas production averaged 11,775 Mcf per day
for the year ended December 31, 1995 compared to 11,156 Mcf per day for the
year ended December 31, 1994 and 10,252 Mcf per day during the year ended
December 31, 1993. Net oil production averaged 729 barrels per day for the
year ended December 31, 1995 compared to 811 barrels per day during the year
ended December 31, 1994 and 674 barrels per day during the year ended
December 31, 1993. The table below summarizes information with respect to
the Company's producing oil and gas properties for each of these periods.
Years Ended December 31,
1995 1994 1993
Quantities Sold:
Natural gas (net Mcf)............... 4,298,000 4,072,000 3,742,000
Oil (net barrel).................... 266,000 296,000 246,000
Average Sales Price:
Natural Gas (per Mcf)............... $ 1.61 $ 1.76 $ 1.88
Oil (per barrel).................... $ 17.19 $ 14.90 $ 16.50
Average production (lifting)
costs per equivalent barrel (1)..... $ 2.21 $ 2.44 $ 2.68
(1) Natural gas production has been converted to a common unit of
production (barrel of oil) on the basis of relative energy content (six Mcf
of natural gas to one barrel of oil).
RESERVES
The table below sets forth the Company's estimated quantities of
proved reserves, all of which were located in the continental United States,
and the present value of estimated future net cash flows from these reserves on
a non-escalated basis, except as provided by contract. The quantities and
values are based on prices in effect at December 31, 1995, averaging $18.73
per barrel of oil and $1.88 per Mcf of natural gas. The future net cash
flows were discounted by ten percent per year as of the end of each of the
last three fiscal periods. The ten percent discount factor is specified by
the Securities and Exchange Commission and is not necessarily the most
appropriate discount rate, and present value, no matter what rate is used, is
materially affected by assumptions as to timing of future production, which
may prove to be inaccurate. For further information concerning the reserves
and the discounted future net cash flows from these reserves, see Note 12 of
the Notes to Consolidated Financial Statements.
December 31,
1995 1994 1993
Estimated proved natural gas
reserves (Mcf).................. 47,711,000 46,202,000 42,638,000
Estimated proved oil reserves
(barrels)....................... 2,734,000 3,009,000 2,702,000
Present value of estimated future
net cash flows (before future
income tax expense)............. $47,785,000 $47,671,000 $42,110,000
Standardized measure of discounted
future net cash flows............ $39,180,000 $38,095,000 $34,935,000
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. The data in the above table represents estimates
only. Oil and gas reserve engineering must be recognized as a subjective
process of estimating underground accumulations of oil and natural gas that
cannot be measured in an exact way. The accuracy of any reserve estimate is
a function of the quality of available data and engineering and geological
interpretation and judgment. Results of drilling, testing and production
after the date of the estimate may justify revisions. Accordingly, reserve
estimates are often materially different from the quantities of oil and
natural gas that are ultimately produced. There has been no major discovery
or other favorable or adverse event that is believed to have caused a
significant change in estimated proved reserves subsequent to December 31,
1995.
Since January 1, 1995, the Company has filed Department of Energy
Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by operators
of domestic oil and gas properties. There are differences between the
reserves as reported on Form EIA-23 and reserves as reported herein. Form
EIA-23 requires that operators report on total proved developed reserves for
operated wells only and that the reserves be reported on a gross operated
basis rather than on a net interest basis.
PRODUCTIVE WELLS
The following table summarizes total gross and net productive wells for
the Company at December 31, 1995.
Productive Wells
Oil Gas
Gross(1) Net(2) Gross(1) Net(2)
Operated:
Colorado................. 8 7.1 301 228.3
Wyoming.................. 0 0.0 1 0.9
Non-operated:
Colorado................. 1 0.2 132 21.9
Oklahoma................. 2 0.2 0 0
Utah..................... 0 0.0 2 0.4
Texas.................... 0 0.0 1 0.5
Wyoming.................. 0 0.0 5 0.3
Total (3)............... 11 7.5 442 252.3
Additionally, the Company has a royalty interest in 134 of the gross
wells reported above in which it owns a working interest. Also, the Company
has royalty interests in an additional 34 gross wells which are not included
in the above table.
(1) A gross well is a well in which a working interest is held. The
number of gross wells is the total number of wells in which a working
interest is owned.
(2) A net well is deemed to exist when the sum of fractional ownership
interests in gross wells equals one. The number of net wells is the
sum of the fractional working interests owned in gross wells expressed
as whole numbers and fractions thereof.
(3) Wells are classified as oil wells or gas wells according to their
predominate production stream. The totals include 185 dual or triple
completions. Multiple completions are counted as one well.
DEVELOPED AND UNDEVELOPED ACREAGE
At December 31, 1995, the Company held acreage as set forth below:
Developed Acreage (1) Undeveloped Acreage (2)
Location Gross (3) Net (4) Gross (3) Net (4)
California............. 0 0 14,270 1,123
Colorado............... 17,589 10,846 27,014 12,929
Nevada................. 0 0 3,840 360
Oklahoma............... 1,875 58 0 0
Texas.................. 482 325 27,577 25,616
Utah................... 320 66 1,857 598
Wyoming................ 657 145 65,318 40,716
Total................ 20,923 11,440 139,876 81,342
(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acreage are those lease acres on which wells have not been
drilled or completed to a point that would permit the production of
commercial quantities of oil or natural gas, regardless of whether such
acreage contains proved reserves.
(3) A gross acre is an acre in which a working interest is owned. The
number of gross acres is the total number of acres in which a working
interest is owned.
(4) A net acre is deemed to exist when the sum of the fractional ownership
working interests in gross acres equals one. The number of net acres
is the sum of the fractional working interests owned in gross acres
expressed as whole numbers and fractions thereof.
Many of the leases summarized in the table above as undeveloped acreage
will expire at the end of their respective primary terms unless production
has been obtained from the acreage subject to the lease prior to that date,
in which event the lease will remain in effect until the cessation of
production. The following table sets forth the expiration dates of the gross
and net acres subject to leases summarized in the table of undeveloped
acreage.
Acres Expiring
Twelve Months Ending: Gross Net
December 31, 1996................. 7,088 2,004
December 31, 1997................. 3,677 2,519
December 31, 1998................. 24,971 21,682
December 31, 1999................. 11,520 10,366
December 31, 2000................. 6,839 5,066
December 31, 2001 and later....... 49,786 29,304
DRILLING ACTIVITIES
Certain information with regard to the Company's drilling activities for
the years ended December 31, 1995, 1994 and 1993 is set forth below:
1995 1994 1993
Gross Net Gross Net Gross Net
Exploratory:
Productive.................. 0 0.00 0 0.00 0 0.00
Dry......................... 4 0.78 0 0.00 0 0.00
4 0.78 0 0.00 0 0.00
Development:
Productive.................. 45 15.38 46 34.36 34 33.45
Dry......................... 0 0.0 0 0.00 1 1.00
45 5.38 46 34.36 35 34.45
Total
Productive.................. 45 15.38 46 34.36 34 33.45
Dry......................... 4 0.78 0 0.00 1 1.00
49 16.16 46 34.36 35 34.45
OIL AND GAS MARKETING AND TRADING
The Company's marketing and trading activities consist of marketing the
Company's own production, marketing the production of others from wells
operated by the Company, and gas trading activities that consist of the
purchase and resale of natural gas.
The Company has entered into a number of gas sales agreements with
respect to the sale of gas from its producing wells. These contracts vary
with respect to their specific provisions, including price, quantity and
length of contract. The Company's oil production is sold under contracts at
prices which are based upon posted prices. For the year ended December 31,
1995, all of the Company's production from the Bonny Field, which accounted
for approximately 4% of the Company's natural gas production, was committed
to a gas sales contract that had a fixed price ($5.90 per MMBtu). At
December 31, 1995, none of the remaining production was sold under a fixed
price contract or under a contract that required the Company to deliver any
specified amount of production.
Total revenues from the sales of natural gas and oil produced by the
Company were $11,502,000, or 60.4% of consolidated revenues, for the year
ended December 31, 1995. During 1995, two purchasers of the Company's oil
and gas production accounted for 21% and 20% of the Company's total revenues.
Although the loss of either of these customers could have a material adverse
effect on the Company, the Company believes it would be able to locate
alternate customers in the event of the loss of either or both of these
purchasers.
As a result of its trading activities, the Company may from time to time
have purchase or sale commitments without corresponding contracts to offset
these commitments, which could result in losses to the Company. The Company
attempts to control and monitor its exposure to these risks by monitoring
and hedging its trading positions as it deems appropriate. All trades or
positions are reviewed by the Chief Executive Officer before they are
committed to and significant positions are reviewed by the Company's
Board of Directors. There were no open positions at December 31, 1995.
During the year ended December 31, 1995, revenues from trading
activities, which included the cost of gas purchased or sold for trading
purposes, were $4,604,000, representing 24.2% of the Company's consolidated
revenues. One customer accounted for 54% of the Company's trading revenues
and 13% of total consolidated revenues.
A participation agreement was executed May 24, 1989 between the Company
and an unrelated third party participant ("Participant"), to supply the
natural gas required for a 50 megawatt cogeneration facility in Brush,
Colorado. The Company has contracted to supply 70% of the committed
quantities. Also on May 24, 1989, the Company and the Participant signed a
Gas Sales Agreement with the owner/operator of the cogeneration facility.
The Gas Sales Agreement requires that approximately 1,750,000 MMBtu's per
year of natural gas for 15 years be supplied to the cogeneration facility.
Deliveries of natural gas began in the fall of 1990. Under the agreement,
the owner/operator is required to take or pay for 80% of the annual contract
quantity. The Company has dedicated a substantial portion of its proved
reserves in the Wattenberg Area to cover its share of the commitment. The
1996 price for the gas is $2.57 per MMBtu, which escalates annually at the
higher of 3% or a sharing of the indexed energy payment rate received by
the owner/operator. The agreement allows the Company to supply the natural
gas from other sources, substitute dedicated reserves or secure marketing
arrangements with third-party suppliers. During 1995, the Company supplied
all gas from marketing arrangements with third-party suppliers.
OILFIELD SERVICES
The Company's oilfield service business is conducted under the name of
Action Oilfield Services, Inc. ("Action"), a wholly owned subsidiary. Action
owns five completion rigs, a swab rig, and various trucking, earth moving,
water hauling and oilfield rental equipment including pumps, tanks,
workstrings and blow-out preventors. Action's activities are currently
concentrated in the Wattenberg Area. Action provides these services on wells
owned and operated by Prima and for third parties. During 1995, 24.5% of
Action's revenues were from wells owned by Prima. The Company's share of
fees paid to Action on Company owned properties and the costs associated with
providing these services are eliminated in the consolidated financial
statements. Over the past few years, the Wattenberg Area has been one of the
most active areas in the United States for drilling of new wells. Due at
least in part to the decline in natural gas prices, activity in the area
declined significantly during 1995. During 1995, Action elected to stack two
of its rigs and is monitoring activity and utilization rates to determine if
further actions are warranted. The Company anticipates activity levels in
the Wattenberg Area in 1996 will continue to be lower than levels experienced
prior to 1995. Revenues recorded by Action from third parties during the
year ended December 31, 1995 were $1,487,000 or 7.8% of consolidated
revenues.
MANAGEMENT AND OPERATOR SERVICES
The Company provides management and operator services for approximately
310 wells which the Company operates. The Company also serves as managing
venturer and operator of Bonny Gathering Company, a joint venture formed to
construct and operate a natural gas gathering and pipeline facility in
the Bonny Field in eastern Colorado. Revenues attributable to management and
operator services were $1,084,000 for the year ended December 31, 1995, which
was 5.7% of consolidated revenues.
CERTAIN RISKS
Historically, oil and natural gas prices have been volatile and are
likely to continue to be volatile. Prices are affected by, among other
things, market supply and demand factors, market uncertainty, and actions of
the United States and foreign governments and international cartels. These
factors are beyond the control of the Company. To the extent that oil and
gas prices decline, the Company's revenues, cash flows, earnings and
operations would be adversely impacted. The Company is unable to accurately
predict future oil and natural gas prices.
The oil and gas business involves a variety of operating risks,
including the risk of fire, explosions and blow-outs, as well as risks
associated with production, marketing and general economic conditions. The
Company maintains insurance against some, but not all, of these risks, any of
which could result in substantial losses to the Company. There can be no
assurance that any insurance would be adequate to cover any losses or
exposure to liability or whether insurance will continue to be available at
premium levels that justify its purchase or whether it will be available at
all.
COMPETITION
The Company competes with numerous other companies and individuals,
including many that have significantly greater resources, in virtually all
facets of its business. Such competitors may be able to pay more for
desirable leases and to evaluate, bid for and purchase a greater number of
properties than the financial or personnel resources of the Company permit.
The ability of the Company to increase reserves in the future will be
dependent on its ability to select and acquire suitable producing properties
and prospects for future exploration and development. The availability of a
market for oil and natural gas production depends upon numerous factors
beyond the control of producers, including but not limited to the
availability of other domestic or imported production, the locations and
capacity of pipelines, and the effect of federal and state regulation on such
production. Domestic oil and natural gas must compete with imported oil and
natural gas, coal, atomic energy, hydroelectric power and other forms of
energy.
GOVERNMENT REGULATION
All aspects of the oil and gas industry are extensively regulated by
federal, state and local governments in all areas in which the Company has
operations. Regulations govern such things as drilling permits,
environmental protection and pollution control, spacing of wells, the
unitization and pooling of properties, reports concerning operations, royalty
rates and various other matters including taxation. Oil and gas industry
legislation and administrative regulations are periodically changed for a
variety of political, economic and other reasons. These regulations may
substantially increase the cost of doing business and sometimes prevent or
delay the starting or continuing of any given exploration or development
project and may adversely affect the economics of capital projects. At the
present time it is impossible to predict what effect current and future
proposals or changes in existing laws or regulations will have on operations,
estimates of oil and natural gas reserves, or future revenues. The costs of
complying, monitoring compliance and dealing with the agencies that
administer these regulations can be significant.
PHYSICAL PROPERTIES
The Company owns 160 acres of land in Weld County, Colorado near LaSalle,
Colorado. A shop, office building and yard facilities located on the land
are used for the Company's field and oilfield service operations. Net book
value of the land and buildings at December 31, 1995 was $222,000. The
service company and field operations own related equipment, including
completion rigs, a swab rig, water trucks, a dozer, a grader, rental
equipment and various oil field vehicles with a net book value of $716,000 at
December 31, 1995.
The Company owns a 15.5% interest in Bonny Gathering Company, a joint
venture which owns a gas gathering and pipeline system located in Yuma
County, Colorado. The book value of this partnership interest was $72,000 at
December 31, 1995. The facility consists of 70 miles of gas gathering lines,
26 miles of main trunk line, an office and shop building, and related
compression and dehydration facilities. The Company also owns a 6% limited
partnership interest in 22 acres of land in Phoenix, Arizona with a book
value at December 31, 1995 of $257,000.
The Company leases its Denver office space at an annual rate of $130,000
per year. Such offices consist of 11,717 square feet and the lease continues
until November 30, 2000. The Company owns office furniture and equipment
with a net book value at December 31, 1995 of $136,000.
EMPLOYEES AND OFFICES
As of December 31, 1995, the Company had 55 full-time employees,
including 18 in its Denver office and 37 field employees. Action Oilfield
Services employed 22 of the field employees and 15 were employed in Prima's
field production, pumping and gas gathering activities. The Company's
principal executive offices are located at 1801 Broadway, Suite 500, Denver,
Colorado 80202.
ITEM 3. LEGAL PROCEEDINGS
On January 31, 1994, Prima and certain other producers at the Bonny
Field filed suit seeking declaratory judgment establishing Williams Natural
Gas Company's ("Williams") obligation to purchase natural gas under the terms
of the parties Gas Purchase Contracts following the conclusion of the primary
term of those contracts. Defendant Williams contends that it has an option
to continue purchasing natural gas rather than an obligation.
Prima and the other producers filed a Motion for Summary Judgment. On
January 16, 1995, the Court issued its opinion finding in favor of Prima and
the other producers, holding that Williams is obligated under the language of
the contracts to continue to purchase gas past the primary term of the
contracts in accordance with the terms and conditions of the contracts.
On January 31, 1995, Williams filed an appeal with the Tenth Circuit
Court of Appeals. On December 5, 1995, the Tenth Circuit Court of Appeals
affirmed the District Court's decision in favor of Prima and the other
producers.
On approximately March 5, 1996, Williams filed a Petition for Writ of
Certiorari with the United States Supreme Court. Prima and the other
producers will be filing a Response to the Petition shortly.
At December 31, 1995, the Company is not engaged in any other material
pending legal proceedings to which the Company is a party or which any of its
property is subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's security holders
during the fourth quarter of the fiscal year ended December 31, 1995.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
(a) Principal Market or Markets. Prima's common stock is traded on
the NASDAQ National Market under the symbol "PENG." The following table sets
forth the NASDAQ high and low bid quotations for Prima's common stock for
each quarterly period during the Company's years ended December 31, 1995
and 1994.
Year Ended December 31, 1995 HIGH LOW
Quarter Ended March 31, 1995................. $14 1/4 $10 3/4
Quarter Ended June 30, 1995.................. 15 1/2 13 3/8
Quarter Ended September 30,1995.............. 15 11 3/4
Quarter ended December 31,1995............... 14 3/4 13 1/4
Year Ended December 31, 1994
Quarter Ended March 31, 1994................. $16 1/2 $12 3/4
Quarter Ended June 30, 1994.................. 15 1/2 11
Quarter Ended September 30, 1994............. 15 1/4 13
Quarter Ended December 31, 1994.............. 14 10 1/4
On March 15, 1996 the closing sale price for the Company's common stock
was $11.75 per share.
The above quotations are from sources believed to be reliable. They do
not include any retail mark-ups, mark-downs or commissions and may not
represent actual transactions.
(b) Approximate Number of Holders of Common Stock. The number of
holders of record of Prima's common stock at March 15, 1996 was 1,298.
(c) Dividends. Holders of common stock are entitled to receive such
dividends as may be declared by Prima's Board of Directors. The Company has
not paid any cash dividends since its inception. The Company anticipates
that all earnings will be retained for the development of its business and
that no cash dividends will be declared in the foreseeable future.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected consolidated
financial data. This data should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations and
the Consolidated Financial Statements and notes thereto.
Six Months
Years Ended Ended Years Ended
December 31, December June 30,
1995 1994 1993 31,1992 1992 1991
(in thousands, except per share data)
Income Statement Data:
Revenues:
Oil and gas sales.. $11,502 $11,558 $11,107 $ 3,924 $ 5,552 $ 5,207
Trading revenues... 4,604 3,790 2,143 1,082 2,005 1,873
Oilfield services.. 1,487 2,102 1,744 901 1,453 1,388
Management and
operator fees..... 1,084 1,014 1,063 571 1,092 1,098
Interest and
dividend income... 154 143 196 131 326 411
Other.............. 217 1,477 211 219 1,227 (77)
19,048 20,084 16,464 6,828 11,655 9,900
Expenses:
General,
administrative
and cost of
oilfield services.. 3,033 3,259 3,070 1,550 2,705 2,714
Depreciation,
depletion
and amortization.. 4,372 4,313 3,869 1,315 2,071 1,952
Lease operating
expense........... 1,432 1,512 1,336 468 787 740
Production taxes... 736 863 999 351 462 470
Cost of trading.... 3,613 3,334 1,849 913 1,556 1,615
13,186 13,281 11,123 4,597 7,581 7,491
Income before
income taxes....... 5,862 6,803 5,341 2,231 4,074 2,409
Income taxes........ 1,370 1,572 1,090 445 815 500
Net Income.......... $ 4,492 $ 5,231 $ 4,251 $ 1,786 $ 3,259 $ 1,909
Net Income per Common
Share and Common
Share Equivalent.. $ 1.16 $ 1.35 $ 1.09 $ 0.46 $ 0.83 $ 0.47
Balance Sheet Data
(at end of period):
Total assets........ $38,565 $35,716 $ 29,477 $21,731 $18,380 $14,797
Net property and
equipment......... 29,118 28,177 21,428 13,624 8,693 5,999
Long-term debt...... 0 1,000 1,300 0 0 0
Stockholders'
equity............ 29,916 25,353 20,270 16,019 14,233 11,348
Working capital..... 4,292 848 2,003 2,970 6,032 5,421
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
The Company's principal sources of liquidity are internally generated
cash flows and existing cash and cash equivalents. Net cash provided by
operating activities before working capital changes totaled $9,719,000 for
the year ended December 31, 1995 compared to $10,873,000 for the year ended
December 31, 1994 and $8,653,000 for the year ended December 31, 1993. Net
working capital at December 31, 1995 was $4,292,000 as compared to $848,000
at December 31, 1994. Current assets were $8,792,000 at December 31, 1995
compared to $6,784,000 at December 31, 1994. Current liabilities were
$4,500,000 at December 31, 1995 compared to $5,936,000 at December 31, 1994.
Current assets increased from December 31, 1994 levels by $2,008,000 and
current liabilities decreased by $1,436,000 for the same period, resulting in
a working capital increase of $3,444,000 for the year ended December 31,
1995.
The Company has external borrowing capacity of $8,000,000 through an
unsecured line of credit with a commercial bank, all of which is available to
be drawn. The Company paid off the amount owing of $1,000,000 at December
31, 1994, during the first six months of 1995.
The Company invested $5,182,000 in additions to oil and gas properties
during the year ended December 31, 1995, compared to $10,620,000 during the
year ended December 31, 1994 and $11,057,000 during the year ended December
31, 1993. During 1995, $3,634,000 was paid for the Company's share of
development well costs and recompletions, $202,000 for exploratory costs,
$1,319,000 for acquisitions of unproved properties and $27,000 for purchases
of proved properties. Other uses of funds in 1995 included $249,000 for
purchases of office equipment and oilfield service equipment and facilities
and $181,000 for purchases of marketable securities.
The standardized measure of estimated discounted future net cash flows
of the Company's proved oil and natural gas reserves increased to $39,180,000
at December 31, 1995 as compared to $38,095,000 at December 31, 1994 and
$34,935,000 at December 31, 1993. Estimated future net cash flows
(undiscounted) before income taxes from proved oil and natural gas reserves
rose to $85,028,000 at December 31, 1995 compared to $83,316,000 at December
31, 1994 and $73,351,000 at December 31, 1993. Oil reserves at December 31,
1995 decreased 9% and natural gas reserves increased 3% compared to December
31, 1994. The weighted average natural gas price received at December 31,
1995 on Company production was $1.88 per Mcf, a decrease of $.04 per Mcf
compared to December 31, 1994. The year end weighted average oil price was
$18.73 per barrel, an increase of $2.73 per barrel compared to December 31,
1994.
In late 1990, the Company began deliveries of gas to the cogeneration
facility in Brush, Colorado, per its contract with the project owner. At
December 31, 1995, the contract price of $2.57 per MMBtu, escalated annually
at 3% pursuant to the pricing provisions of the contract, was used to value
gas reserves equivalent to one half of the minimum contract quantity or 8.14%
of the Company's estimated proved natural gas reserves, based on the
Company's estimate of the percentage of the minimum contract requirement
that will be fulfilled from its existing reserves.
At December 31, 1995, an estimated capital expenditure of $15,425,000
will be required to develop the Company's proved undeveloped and proved
developed non-producing reserves over the next several years. Approximately
$13,434,000, net of future development costs, of the estimated future net
cash flows of the Company's proved oil and gas reserves at December 31, 1995
were proved undeveloped reserves.
The Company regularly reviews opportunities for acquisition of assets or
companies related to the oil and gas industry which could expand or enhance
its existing business. The Company expects its operations, including
acquisitions and drilling prospects, will be financed by funds provided from
operations, working capital, various cost-sharing arrangements, borrowings
under its line of credit or from other financing alternatives.
Historically, oil and natural gas prices have been volatile and are
likely to continue to be volatile. Prices are affected by, among
other things, market supply and demand factors, market uncertainty, and
actions of the United States and foreign governments and international
cartels. These factors are beyond the control of the Company. To the extent
that oil and gas prices decline, the Company's revenues, cash flows, earnings
and operations would be adversely impacted. The Company is unable to
accurately predict future oil and natural gas prices.
RESULTS OF OPERATIONS
1995 vs 1994
For the year ended December 31, 1995, the Company earned net income of
$4,492,000, or $1.16 per share, on revenues of $19,048,000, compared to net
income of $5,231,000, or $1.35 per share, on revenues of $20,084,000 for the
year ended December 31, 1994. Operating expenses were $13,186,000 for the
1995 year compared to $13,281,000 for 1994. Revenues decreased $1,036,000 or
5%, expenses decreased $95,000 or 1% and net income decreased $739,000 or 14%
in 1995. The revenues, net income and earnings per share for 1994 include
$1,200,000, $750,000 and $.19, respectively, for proceeds received from a
non-recurring lawsuit settlement.
Oil and gas sales for the year ended December 31, 1995 were $11,502,000
compared to $11,558,000 for the year ended December 31, 1994, a decrease of
$56,000 or .5%. The Company's net production was 4.30 Bcf of natural gas and
266,000 barrels of oil in 1995 compared to 4.07 Bcf of natural gas and
296,000 barrels of oil in 1994. The Company's natural gas production
increased due to its participation in the drilling of new wells in the Cave
Gulch Unit and the Bonny Field. The average price received per Mcf of
natural gas sold was $1.61 for the year ended December 31, 1995 compared to
$1.76 per Mcf for the year ended December 31, 1994, a decrease of $.15 per
Mcf or 8.5%. Approximately 4% of the natural gas production for the year
ended December 31, 1995 was attributable to production sold under a fixed
contract price of $5.90 per MMBtu. The average price for the Company's
natural gas production exclusive of the fixed price contract gas was $1.43
per Mcf for the year ended December 31, 1995. The average price received per
barrel of oil sold was $17.19 for 1995 compared to $14.90 for 1994, an
increase of $2.29 per barrel or 15%.
Trading revenues and cost of trading represent the marketing of third
party gas by Prima Natural Gas Marketing, Inc., a wholly owned subsidiary.
Trading revenues were $4,604,000 for 1995 compared to $3,790,000 for 1994, an
increase of $814,000 or 21%. The Company marketed 2,295,000 MMBtu's of
third party gas in 1995 compared to 1,678,000 MMBtu's in 1994. Costs of
trading were $3,613,000 for 1995 compared to $3,334,000 for 1994, an increase
of $279,000 or 8%.
Oilfield service revenues of $1,487,000 and $2,102,000 for the years
ended December 31, 1995 and 1994, respectively, represent the revenues earned
by Action Oilfield Services, Inc., a wholly owned subsidiary. These revenues
include well servicing fees from five completion rigs, a swab rig, trucking,
water hauling, dozer and roustabout work, rental equipment and other related
activities. The decrease in revenues is attributable to decreased activity
in the Wattenberg Field Area where the service company is active. This
decline in activity is due at least in part to the decline in natural gas
prices incurred during the latter part of 1994 and continuing into 1995,
which resulted in a significant decline in drilling activity in the area.
For the years ended December 31, 1995 and 1994, 25% and 35% of the gross fees
billed by Action were for Company owned wells. The Company's share of fees
paid to Action on owned wells and the costs associated with providing the
services are eliminated in consolidation. The services performed for the
Company have declined because the Company reduced the size of its 1995
Wattenberg drilling program compared to previous years programs.
Management and operator fees for the years ended December 31, 1995 and
1994 were $1,084,000 and $1,014,000, respectively. Management and operator
fees are earned pursuant to the Company's roles as operator for approximately
310 oil and gas wells located primarily in the Wattenberg Area of Weld
County, Colorado and as managing venturer of a joint venture which owns gas
gathering and pipeline facilities in the Bonny Field in Yuma County,
Colorado. The Company is a working interest owner in each of the operated
wells. The Company is paid operating fees by the other working interest
owners in the properties. Fees fluctuate with the number of wells operated,
the percentage working interest in a property owned by third parties, and the
amount of drilling activity during the period. Fees increased in 1995 due to
increased management fees earned as managing venturer of the gas gathering
system.
General and administrative expense and cost of oilfield services ("G&A")
totaled $3,033,000 for the year ended December 31, 1995 compared to
$3,259,000 for the year ended December 31, 1994. These costs include the
direct and indirect expenses of the Company's service business as well as
costs of payroll, insurance, rent, office, maintenance, etc. G&A costs
decreased by $226,000 or 7%. The Company has sought to reduce its costs
consistent with the reduced activity levels in the service business by
stacking equipment and reducing the work force.
Depreciation, depletion and amortization ("DD&A") rates are affected by
production levels and changes in reserve estimates. Total DD&A expense was
$4,372,000 in 1995 compared to $4,313,000 for 1994, an increase of $59,000.
The Company's depletion of oil and gas properties was $4,058,000 or $4.13 per
equivalent barrel of production on 983,000 equivalent barrels produced in
1995, compared to $3,974,000 or $4.08 per equivalent barrel of production on
974,000 equivalent barrels produced in 1994. Included in DD&A expense for
1995 and 1994 is $314,000 and $339,000, respectively, attributable to
depreciation of service equipment, furniture and equipment and buildings.
Lease operating expenses ("LOE") were $1,432,000 for the year ended
December 31, 1995 compared to $1,512,000 for the year ended December 31,
1994. Production taxes were $736,000 and $863,000 for the same periods.
Total lifting costs (LOE plus production taxes) were 19% of oil and gas
revenues and $2.21 per equivalent barrel of production for 1995 compared to
21% and $2.44 for 1994.
The provision for income taxes was $1,370,000 for the year ended
December 31, 1995 compared to $1,572,000 for the year ended December 31,
1994. The effective tax rate was 23.4% in 1995 compared to 23.1% in 1994.
Effective tax rates are affected by amounts of temporary and permanent
differences in financial and taxable income and by statutory depletion
deductions and Section 29 tax credits.
1994 vs 1993
For the year ended December 31, 1994, the Company earned net income of
$5,231,000, or $1.35 per share, on revenues of $20,084,000, compared to net
income of $4,251,000, or $1.09 per share, on revenues of $16,464,000 for the
year ended December 31, 1993. Operating expenses were $13,281,000 for the
1994 year compared to $11,123,000 for 1993. Revenues increased $3,620,000 or
22%, expenses increased $2,158,000 or 19% and net income increased $980,000
or 23% in 1994.
Oil and gas sales for the year ended December 31, 1994 were $11,558,000
compared to $11,107,000 for the year ended December 31, 1993, an increase of
$451,000 or 4%. The Company's net production was 4.07 Bcf of natural gas and
296,000 barrels of oil in 1994 compared to 3.74 Bcf of natural gas and
246,000 barrels of oil in 1993. The Company's production increased due to
its participation in the drilling of new wells and the recompletion of older
wells. The average price received per Mcf of natural gas sold was $1.76 for
the year ended December 31, 1994 compared to $1.88 per Mcf for the year ended
December 31, 1993. The average price received per barrel of oil sold was
$14.90 compared to $16.50 for the same periods.
Trading revenues were $3,790,000 for 1994 compared to $2,143,000 for
1993, an increase of $1,647,000 or 77%. The Company marketed 1,678,000
MMBtu's of third party gas in 1994 compared to 902,000 MMBtu's in 1993.
Costs of trading were $3,334,000 for 1994 compared to $1,849,000 for 1993, an
increase of $1,485,000 or 80%.
Oilfield service revenues were $2,102,000 for the year ended December
31, 1994 compared to $1,744,000 for the year ended December 31, 1993. Fees
increased by $358,000, or 21% for 1994 as utilization rates increased and the
Company expanded its oilfield service operating base through acquisitions of
additional service equipment. For the years ended December 31, 1994 and
1993, 35% and 39% of the gross fees billed by Action were for Company owned
wells.
Management and operator fees for the years ended December 31, 1994 and
1993, were $1,014,000 and $1,063,000, respectively. The Company's operated
approximately 300 oil and gas wells during 1994 compared to 260 for 1993, as
well as the joint venture which owns gas gathering and pipeline facilities
in the Bonny Field in Yuma County, Colorado.
Other revenues includes $1,200,000 in net proceeds from the settlement
of prior litigation. The settlement proceeds were received and the income
recognized in the fourth quarter of 1994. The proceeds increased the
Company's net income by approximately $750,000 or $.19 per share.
General and administrative expense and cost of oilfield services ("G&A")
totaled $3,259,000 for the year ended December 31, 1994 compared to
$3,070,000 for the year ended December 31, 1993. G&A costs increased by
$189,000 or 6%. The cost of oilfield services has increased due to increased
activity. However, the Company's share of costs associated with providing
services for owned wells is eliminated in consolidation.
Total DD&A expense was $4,313,000 in 1994 compared to $3,869,000 for
1993, an increase of $444,000 or 11%. The Company's depletion of oil and gas
properties was $3,974,000 or $4.08 per equivalent barrel of production in
1994, compared to $3,520,000 or $4.05 per equivalent barrel of production
for 1993. Included in DD&A expense for 1994 and 1993 is $339,000 and
$349,000, respectively, attributable to depreciation of service equipment,
furniture and equipment and buildings.
LOE was $1,512,000 for the year ended December 31, 1994 compared to
$1,336,000 for the year ended December 31, 1993. Production taxes were
$863,000 and $999,000 for the same periods. Total production expenses were
21% of oil and gas revenues and $2.44 per equivalent barrel of production for
1994 compared to 21% and $2.68 for 1993.
The provision for income taxes was $1,572,000 for the year ended
December 31, 1994 compared to $1,090,000 for the year ended December 31,
1993. The effective tax rate was 23.1% in 1994 compared to 20.4% in 1993.
NEW ACCOUNTING PRONOUNCEMENTS
During 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
("SFAS 121"). SFAS 121 provides standards for accounting for the impairment
of various long-lived assets. The Company is required to adopt SFAS 121 no
later than 1996. The Company uses the full cost method of accounting for its
oil and gas properties, which requires an impairment to be recorded when
total capitalized costs exceed the present value, discounted at 10%, of
estimated future net cash flows from proved oil and gas reserves. Therefore,
the adoption of SFAS 121 is not expected to have a material effect on the
financial position or results of operations of the Company.
During 1995, the FASB issued Statement of Financial Accounting Standards
No. 123, "Accounting for Stock Based Compensation" ("SFAS 123"). SFAS 123
requires entities to either account for, or disclose, stock based
compensation in their financial statements. The Company is required to adopt
SFAS 123 no later than 1996. Because the Company intends to elect only the
disclosure provisions of SFAS 123, the adoption of SFAS 123 is not expected
to have a material effect on the financial position or results of operations
of Prima.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements and schedules that constitute Item
8 are attached at the end of this Annual Report on Form 10-K. An index to
these Consolidated Financial Statements and Schedules is also included in
Item 14(a) of this Annual Report on Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURES
Since the Company's inception, there has not been any Form 8-K filed
under the Securities Exchange Act of 1934 reporting a change in accountants
in which there was a reported disagreement on any matter of accounting
principles or practices or financial statement disclosure.
PART III
The information required by Part III is omitted from this report in that
the Registrant will file a definitive Proxy Statement pursuant to Regulation
14A (the Proxy Statement) not later than 120 days after the end of the fiscal
year covered by this report, and certain information included therein is
incorporated herein by reference.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item is incorporated by reference from
the Company's Proxy Statement.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference from
the Company's Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is incorporated by reference from
the Company's Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference from
the Company's Proxy Statement.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
(a) (1) FINANCIAL STATEMENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Independent Auditors' Report ........................................ 23
Consolidated Balance Sheets at December 31, 1995 and 1994............ 24
Consolidated Statements of Income for the years ended
December 31, 1995, 1994 and 1993................................... 26
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1995, 1994 and 1993................................... 27
Consolidated Statements of Cash Flows for the years ended
December 31, 1995, 1994 and 1993................................... 28
Notes to Consolidated Financial Statements for the years ended
December 31, 1995, 1994 and 1993................................... 29
(a) (2) FINANCIAL STATEMENT SCHEDULES
There are no required financial statement schedules.
(a) (3) EXHIBITS
The following Exhibits are filed herewith pursuant to Rule 601 of the
Regulation S-K or are incorporated by reference to previous filings.
Exhibit No. Document
10.1 First Amendment to Trinity Place Office Lease
(Incorporated by reference as Exhibit 10-95.1 to
Form 10-Q filed August 14, 1995)
10.2 Line of Credit Letter Agreement (Incorporated by
reference as Exhibit 10-95.2 to Form 10-Q filed
August 14, 1995)
21 Subsidiaries of the Registrant
27 Financial Data Schedules
99 Petition for Writ of Certiorari - Williams Natural Gas
Company, Petitioner v. Talus Properties Limited
Partnership, Prima Oil & Gas Company, John P.
Lockridge, Yuma County Oil Company, and JER
Partnership, Respondents
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the Registrant's fiscal quarter
ended December 31, 1995.
<PAGE>
INDEPENDENT AUDITORS' REPORT
Prima Energy Corporation:
We have audited the accompanying consolidated balance sheets of Prima
Energy Corporation ("Company") and subsidiaries as of December 31, 1995 and
1994 and the related consolidated statements of income, stockholders' equity
and cash flows for the years ended December 31, 1995, 1994 and 1993.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of the Company and
subsidiaries at December 31, 1995 and 1994 and the results of their
operations and their cash flows for the above stated periods, in conformity
with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
March 22, 1996
Denver, Colorado
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1995 and 1994
ASSETS
1995 1994
CURRENT ASSETS
Cash and cash equivalents...................... $ 3,977,000 $ 1,558,000
Available for sale securities, at market....... 1,180,000 895,000
Receivables (net of allowance for doubtful
accounts: 1995, $43,000; 1994, $49,000)..... 3,087,000 3,425,000
Tubular goods inventory........................ 217,000 478,000
Deferred tax asset............................. 101,000 174,000
Other current assets........................... 230,000 254,000
Total current assets..................... 8,792,000 6,784,000
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method.............. 45,774,000 40,686,000
Less accumulated depreciation,
depletion and amortization.................. (17,730,000) (13,672,000)
Oil and gas properties - net............. 28,044,000 27,014,000
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment..................... 1,888,000 1,800,000
Furniture and equipment........................ 518,000 500,000
Field office, shop and land.................... 334,000 300,000
2,740,000 2,600,000
Less accumulated depreciation.................. ( 1,666,000) ( 1,437,000)
Property and equipment - net............. 1,074,000 1,163,000
OTHER ASSETS
Cash, designated............................... 326,000 457,000
Other.......................................... 329,000 298,000
Total other assets....................... 655,000 755,000
$38,565,000 $35,716,000
See accompanying notes to consolidated financial statements.
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (cont'd.)
DECEMBER 31, 1995 and 1994
LIABILITIES AND STOCKHOLDERS' EQUITY
1995 1994
CURRENT LIABILITIES
Accounts payable............................... $ 1,746,000 $ 3,110,000
Amounts payable to oil and gas property owners. 1,086,000 1,364,000
Production taxes payable....................... 1,239,000 1,109,000
Accrued and other liabilities.................. 429,000 353,000
Total current liabilities................ 4,500,000 5,936,000
NOTE PAYABLE - BANK............................ 0 1,000,000
PRODUCTION TAXES, non-current.................. 1,012,000 1,139,000
DEFERRED TAX LIABILITY......................... 3,137,000 2,288,000
Total liabilities........................ 8,649,000 10,363,000
STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value,
2,000,000 shares authorized;
no shares issued or outstanding............. 0 0
Common stock, $0.015 par value, 8,000,000
shares authorized; 3,880,396 shares
issued and outstanding...................... 58,000 58,000
Additional paid-in capital..................... 4,251,000 4,251,000
Retained earnings.............................. 25,684,000 21,192,000
Unrealized loss on available for sale
securities................................... (77,000) (148,000)
Stockholders' equity..................... 29,916,000 25,353,000
$38,565,000 $35,716,000
See accompanying notes to consolidated financial statements.
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 and 1993
1995 1994 1993
REVENUES
Oil and gas sales............... $11,502,000 $11,558,000 $11,107,000
Trading revenues................ 4,604,000 3,790,000 2,143,000
Oilfield services............... 1,487,000 2,102,000 1,744,000
Management and operator fees.... 1,084,000 1,014,000 1,063,000
Interest and dividend income.... 154,000 143,000 196,000
Other........................... 217,000 1,477,000 211,000
19,048,000 20,084,000 16,464,000
EXPENSES
General, administrative and cost
of oilfield services........... 3,033,000 3,259,000 3,070,000
Depreciation, depletion and
amortization................... 4,372,000 4,313,000 3,869,000
Lease operating expense......... 1,432,000 1,512,000 1,336,000
Production taxes................ 736,000 863,000 999,000
Cost of trading................. 3,613,000 3,334,000 1,849,000
13,186,000 13,281,000 11,123,000
INCOME BEFORE INCOME TAXES...... 5,862,000 6,803,000 5,341,000
PROVISION FOR INCOME TAXES...... 1,370,000 1,572,000 1,090,000
NET INCOME...................... $ 4,492,000 $ 5,231,000 $ 4,251,000
NET INCOME PER COMMON SHARE
AND COMMON SHARE EQUIVALENT.... $ 1.16 $ 1.35 $ 1.09
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING AND COMMON SHARE
EQUIVALENTS................... 3,883,536 3,885,411 3,883,941
See accompanying notes to consolidated financial statements.
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 and 1993
ADDITIONAL UNREALIZED
COMMON PAID-IN RETAINED LOSS ON
STOCK CAPITAL EARNINGS SECURITIES TOTAL
BALANCES,
January 1,
1993......... $58,000 $4,251,000 $11,710,000 $ 0 $16,019,000
Net income.... 4,251,000 4,251,000
BALANCES,
December 31,
1993......... 58,000 4,251,000 15,961,000 0 20,270,000
Net income.... 5,231,000 5,231,000
Unrealized loss
on available
for sale
securities... (148,000) (148,000)
BALANCES,
December 31,
1994......... 58,000 4,251,000 21,192,000 (148,000) 25,353,000
Net income.... 4,492,000 4,492,000
Unrealized gain
on available
for sale
securities... 71,000 71,000
BALANCES,
December 31,
1995......... $58,000 $4,251,000 $25,684,000 $ (77,000) $29,916,000
See accompanying notes to consolidated financial statements.
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 and 1993
1995 1994 1993
OPERATING ACTIVITIES
Net income ..................... $ 4,492,000 $ 5,231,000 $ 4,251,000
Adjustments to reconcile net
income to net cash provided
by operating activities:
Depreciation, depletion and
amortization.................. 4,372,000 4,313,000 3,869,000
Deferred income taxes......... 889,000 1,277,000 606,000
Other......................... (34,000) 52,000 (73,000)
9,719,000 10,873,000 8,653,000
Changes in operating assets
and liabilities:
Receivables.................. 338,000 (1,426,000) 360,000
Inventory.................... 261,000 286,000 (260,000)
Other assets................. 24,000 (159,000) (44,000)
Payables..................... (1,512,000) 467,000 1,771,000
Accrued and other liabilities 76,000 49,000 (614,000)
Net cash provided by
operating activities....... 8,906,000 10,090,000 9,866,000
INVESTING ACTIVITIES
Additions to oil and gas
properties.................... (5,182,000) (10,620,000) (11,057,000)
Purchases of other property..... (249,000) (481,000) (664,000)
Purchases of securities......... (181,000) (70,000) (211,000)
Proceeds from sales of
securities.................... 0 488,000 890,000
Proceeds from sales of
property...................... 125,000 42,000 54,000
Net cash used by
investing activities....... (5,487,000) (10,641,000) (10,988,000)
FINANCING ACTIVITIES
Borrowings under line of credit. 0 2,000,000 1,300,000
Payments on line of credit...... (1,000,000) (2,300,000) 0
Net cash provided by (used
in) financing activities... (1,000,000) (300,000) 1,300,000
Increase (Decrease) in Cash
and Cash Equivalents.......... 2,419,000 (851,000) 178,000
Cash and Cash Equivalents,
beginning of year............. 1,558,000 2,409,000 2,231,000
Cash and Cash Equivalents,
end of year................... $ 3,977,000 $ 1,558,000 $ 2,409,000
See accompanying notes to consolidated financial statements.
<PAGE>
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 and 1993
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Prima Energy Corporation ("Prima") is an independent oil and gas
company primarily engaged in the exploration for, acquisition, development and
production of, crude oil and natural gas. Through its wholly owned
subsidiaries, Prima is also engaged in oil and gas property operations,
oilfield services and natural gas gathering and marketing. Prima's current
activities are principally conducted in the Rocky Mountain region.
Basis of Presentation
The accompanying consolidated financial statements include the
accounts of Prima and its subsidiaries, herein collectively referred to
as the "Company." All significant intercompany transactions have been
eliminated. Certain amounts in prior years have been reclassified to
conform with the classifications at December 31, 1995.
Use of Estimates
The preparation of the financial statements for the Company 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.
Consolidated Statements of Cash Flows
The Company considers all highly liquid debt instruments purchased
with a maturity of three months or less to be cash equivalents.
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Years Ended December 31,
1995 1994 1993
Income taxes........... $ 0 $584,000 $700,000
Interest............... 29,000 59,000 54,000
Available for Sale Securities
The Company classifies all securities as "available for sale,"
states them at market value and reports unrealized gains and losses, net
of income tax effect, as an adjustment to stockholders' equity.
Available for sale securities are readily marketable and used routinely
in operations, therefore the Company has classified its portfolio as a
current asset. Realized gains and losses are determined on the specific
identification method.
INVENTORY
Inventory consists of tubular goods stated at the lower of cost or
market value using the specific identification method.
OIL AND GAS PROPERTIES
The Company utilizes the full cost method of accounting for oil and
gas activities. Under this method, subject to a limitation based on
estimated value, all costs associated with property acquisition,
exploration and development, including costs of unsuccessful exploration, are
capitalized within a cost center. The Company's oil and gas properties are
located within the United States, which constitutes one cost center. No gain
or loss is recognized upon normal sale or abandonment of undeveloped or
producing oil and gas properties unless the gain significantly alters the
relationship between capitalized costs and proved oil and gas reserves of the
cost center. Depreciation, depletion and amortization of oil and gas
properties is computed on the units of production method based on proved
reserves. Amortizable costs include estimates of future development costs of
proved undeveloped reserves.
Capitalized costs of oil and gas properties may not exceed an
amount equal to the present value discounted at 10% of the estimated
future net cash flows from proved oil and gas reserves plus the cost,
or estimated fair market value, if lower, of unproved properties.
Should capitalized costs exceed this ceiling, an impairment is recognized.
The present value of estimated future net cash flows is computed by applying
year end prices of oil and natural gas to estimated future production of
proved oil and gas reserves as of year end, less estimated future
expenditures to be incurred in developing and producing the proved reserves
and assuming continuation of existing economic conditions.
The Company does not accrue costs for future site restoration,
dismantlement and abandonment costs related to proved oil and gas
properties because the Company estimates that such costs will be offset
by the salvage value of the equipment sold upon abandonment of such
properties. The Company's estimates are based upon its historical
experience and upon review of current properties and restoration
obligations.
During 1995, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of" ("SFAS 121"). SFAS 121 provides standards for accounting
for the impairment of various long-lived assets. The Company is
required to adopt SFAS 121 no later than 1996. The Company uses the
full cost method of accounting for its oil and gas properties, which
requires an impairment to be recorded when total capitalized costs
exceed the present value, discounted at 10%, of estimated future net
cash flows from proved oil and gas reserves. Therefore, the adoption of
SFAS 121 is not expected to have a material effect on the financial
position or results of operations of the Company.
PROPERTY AND EQUIPMENT
Property and equipment is recorded at cost. Renewals and betterments
which substantially extend the useful life of the assets are capitalized.
Maintenance and repairs are expensed when incurred. Depreciation is provided
using the straight-line method over the estimated useful lives, 3 to 10
years, of the assets.
TRADING
The Company recognizes revenues and costs on natural gas trading
transactions at the point in time when gas is delivered to the purchaser. At
December 31, 1995 and 1994, the Company had delivered 48,000 MMBtu's and
41,000 MMBtu's respectively, into the pipeline which had not been delivered
to the purchaser. This gas is valued at the lower of cost or market value.
Market value for this purpose is deemed to be the sales price specified in
the contract under which the Company intends to sell the gas. Included in
other current assets at December 31, 1995 and 1994, is $60,000 and $53,000
respectively, representing the cost of gas which had been delivered into the
pipeline but not delivered to the purchaser.
HEDGING TRANSACTIONS
The Company periodically uses both commodity futures contracts and
price swaps to hedge the impact of natural gas and oil price fluctuations on
a portion of its production and gas marketing activities. Gains and losses
on hedging transactions are deferred until the physical transaction occurs
for financial reporting purposes. Deferred gains and losses are evaluated in
connection with the physical transaction underlying the hedge position.
Gains or losses on hedging activities are recorded in the income statement as
adjustments of the revenue or cost of the underlying physical transaction.
Hedging activities are reported as operating activities in the statements of
cash flows. There were no open positions at December 31, 1995.
If the Company enters into price swaps or commodities transactions
that do not correspond to scheduled physical transactions (scheduled
physical transactions include committed gas marketing activities or
production from producing wells), the transactions would not qualify for
hedge accounting. In that event, the Company records the instruments at
fair value and gains or losses are recorded as fair values fluctuate
compared to cost.
GOVERNMENT REGULATION
All aspects of the oil and gas industry are extensively regulated
by federal, state and local governments in all areas in which the
Company has operations. Regulations govern such things as drilling
permits, environmental protection and pollution control, spacing of
wells, the unitization and pooling of properties, reports concerning
operations, royalty rates and various other matters including taxation.
Oil and gas industry legislation and administrative regulations are
periodically changed for a variety of political, economic and other
reasons. As of December 31, 1995, the Company had not been fined or
cited for any violations of government regulations which would have a
material adverse effect upon capital expenditures, earnings or the
competitive position of the Company in the oil and gas industry.
MANAGEMENT, OPERATOR AND OILFIELD SERVICE FEES
The Company receives management fees for services performed as the
managing venturer and operator for a gas gathering and pipeline joint
venture. Such fees are included in income. Income from operating wells
for third parties is recognized pursuant to the applicable operating
agreements when the services are performed. Oilfield services fees are
recognized as income when the services are performed for third parties.
INCOME TAXES
Income taxes are provided for the tax effects of transactions
reported in the financial statements and consist of taxes currently due
plus deferred taxes related to certain income and expenses recognized in
different periods for financial and income tax reporting purposes. The
deferred tax assets and liabilities represent the future tax consequences of
those differences, which will either be taxable or deductible when the assets
and liabilities are recovered or settled.
EARNINGS PER SHARE
Net income per common share and common share equivalents is
computed using the weighted average number of shares of common stock and
common stock equivalents outstanding during each year. Options to
purchase stock are included as common stock equivalents, when dilutive,
using the treasury stock method.
2. AVAILABLE FOR SALE SECURITIES
The Company's investments are comprised of marketable equity securities.
For the year ended December 31, 1994, the Company sold securities with a
market value of $488,000 which resulted in realized gains and losses of
$4,000 and $85,000, respectively. No securities were sold in 1995. The net
unrealized loss on securities at December 31, 1995 and 1994 is included as a
separate component of stockholders' equity net of deferred income taxes of
$46,000 and $78,000, respectively. The change in net unrealized gain or loss
on securities for the years ended December 31, 1995 and 1994 was determined
as follows:
1995 1994
Net unrealized loss, beginning of year....... $ 226,000 $ 0
Net unrealized loss, end of year............. 122,000 226,000
Net unrealized gain or (loss)................ $ 104,000 $(226,000)
The components of fair value as of December 31, 1995 and 1994 are as
follows:
1995 1994
Cost (including reinvested distributions).... $1,302,000 $1,121,000
Gross unrealized gains....................... 1,000 0
Gross unrealized losses...................... (123,000) (226,000)
Fair value................................... $1,180,000 $ 895,000
3. LONG-TERM DEBT
Long-term debt at December 31, 1994 consisted of borrowings under
an $8,000,000 unsecured line of credit with a commercial bank. The note
bears interest at the bank's prime rate, with interest payable monthly.
Funds are available on a revolving basis until April 30, 1997. The
balance of principal plus accrued interest is payable at maturity, May
1, 1997. There was no balance outstanding on the line of credit
at December 31, 1995 or March 15, 1996.
December 31,
1995 1994
Total borrowings...................... $ 0 $1,000,000
Current payable....................... 0 0
Long-term debt........................ $ 0 $1,000,000
Interest rate......................... 8.5% 8.5%
4. CONTRACT SETTLEMENTS
During the quarter ended December 31, 1994, the Company received
proceeds resulting from a Federal District Court decision regarding the
pricing and take-or-pay provisions of a gas contract which had been in
litigation for approximately eight years. The Company recorded the
$1,200,000 of net proceeds received as other revenues.
5. INCOME TAXES
The components of the provision for income taxes are as follows:
Years Ended December 31,
1995 1994 1993
Current provision..................... $ 481,000 $ 295,000 $ 484,000
Deferred provision.................... 1,243,000 1,492,000 982,000
Minimum tax credit carryforwards...... (354,000) (215,000) (376,000)
Provision for income taxes............ $1,370,000 $1,572,000 $1,090,000
The provision for income taxes differs from the amount of income
taxes determined by applying the federal statutory income tax rate to
pretax earnings. The reasons for these differences, shown as a percent
of pre-tax earnings, are as follows:
Years Ended December 31,
1995 1994 1993
Statutory income tax rate............. 34.0% 34.0% 34.0%
Percentage depletion.................. (3.4) (2.2) (2.7)
Section 29 credits.................... (13.7) (8.6) (16.8)
State taxes........................... 2.9 3.1 2.9
Other................................. 3.6 (3.2) 3.0
23.4% 23.1% 20.4%
Deferred income taxes result from temporary differences in
the timing of income and expense for financial and income tax reporting
purposes. The Company's temporary differences are attributable to (1)
intangible drilling costs deducted for income tax purposes but depleted
for financial statement purposes, (2) different depreciation methods,
(3) state income taxes expensed in the financial statements prior to
actual payment to state taxing authorities and (4) excess income tax
versus financial reporting basis in partnerships. The tax effects of
these temporary differences are partially offset by minimum tax credit
carryforwards.
At December 31, 1995, the Company had minimum tax credit carryforwards
of approximately $2,478,000, which may be carried forward indefinitely.
The net deferred tax liability in the accompanying December 31, 1995 and
1994 balance sheets includes the following components:
1995 1994
Deferred Tax Assets:
Minimum tax credit carryforwards...... $2,478,000 $2,128,000
Depreciation.......................... (42,000) (41,000)
State deferred income taxes........... 226,000 181,000
Investment in partnerships............ 58,000 78,000
Other................................. 114,000 185,000
2,834,000 2,531,000
Deferred Tax Liabilities:
Intangible drilling costs............ 5,340,000 4,402,000
Other................................ 530,000 243,000
5,870,000 4,645,000
Net Deferred Tax Liability............. $3,036,000 $2,114,000
6. MAJOR CUSTOMERS
For the past three years, three customers have each provided over
10% of the Company's revenues from the oil and gas industry segment.
Following is a table summarizing the percentage provided by each
customer. Although the Company sells the majority of its oil and gas
production to a few purchasers, there are numerous other purchasers in
the area, therefore, the loss of its significant customers would not
adversely affect the Company's operations.
A B C
Year ended December 31, 1995............... 21% 20% 13%
Year ended December 31, 1994............... 26 20 14
Year ended December 31, 1993............... 32 22 14
7. INDUSTRY SEGMENT INFORMATION
The following table sets forth revenues, operating earnings before
income taxes, identifiable assets, depreciation, depletion and amortization
expense and capital expenditures for the years ended December 31, 1995, 1994
and 1993 for the Company's two identifiable industry segments.
1995 1994 1993
Revenues
Oil and gas................... $17,399,000 $17,916,000 $14,472,000
Oilfield services............. 1,968,000 3,214,000 2,875,000
Other......................... 162,000 66,000 248,000
Total....................... $19,529,000 $21,196,000 $17,595,000
Operating Earnings
Oil and gas................... $ 5,617,000 $ 6,307,000 $ 4,778,000
Oilfield services............. 104,000 489,000 369,000
Other......................... 141,000 7,000 194,000
Total....................... $ 5,862,000 $ 6,803,000 $ 5,341,000
Identifiable Assets
Oil and gas.................... $28,116,000 $27,055,000 $20,399,000
Oilfield services.............. 939,000 976,000 857,000
Other.......................... 9,510,000 7,685,000 8,221,000
Total........................ $38,565,000 $35,716,000 $29,477,000
Depreciation, Depletion and
Amortization Expense
Oil and gas.................... $ 4,058,000 $ 3,974,000 $ 3,520,000
Oilfield services.............. 247,000 280,000 267,000
Other.......................... 67,000 59,000 82,000
Total........................ $ 4,372,000 $ 4,313,000 $ 3,869,000
Capital Expenditures
Oil and gas................... $ 5,182,000 $10,620,000 $11,057,000
Oilfield services............. 230,000 425,000 575,000
Other......................... 19,000 56,000 89,000
Total....................... $ 5,431,000 $11,101,000 $11,721,000
Oilfield services revenue includes $481,000, $1,112,000 and $1,131,000
for the years ended December 31, 1995, 1994 and 1993, respectively, for
intersegment sales.
8. COMMITMENTS AND CONTINGENCIES
OFFICE LEASE
During 1995, the Company entered into an agreement to extend its
current operating lease for office space for an additional five years,
with a term through November 30, 2000. Rental expense, net of sublease
rental income, totaled $127,000, $124,000 and $74,000 for the years
ended December 31, 1995, 1994 and 1993, respectively. Future minimum
annual rentals are as follows:
Year ending December 31, 1996................. $123,000
Year ending December 31, 1997................. 126,000
Year ending December 31, 1998................. 129,000
Year ending December 31, 1999................. 132,000
Year ending December 31, 2000................. 124,000
$634,000
DELIVERY COMMITMENT
A participation agreement was executed May 24, 1989 between the
Company and an unrelated third party to supply the natural gas required
for a 50 megawatt cogeneration facility in Brush, Colorado. The
Company has contracted to supply 70% of the committed quantities. Also
on May 24, 1989, the Company and the other party signed a Gas Sales
Agreement with the owner/operator of the cogeneration facility. The
Gas Sales Agreement requires that approximately 1,750,000 MMBtu's per
year of natural gas for 15 years be supplied to the cogeneration
facility. Under the agreement, the owner/operator is required to take
or pay for 80% of the annual contract quantity. The Company has
dedicated a substantial portion of its proved reserves in Weld County,
Colorado to cover its share of the commitment. The 1996 price for the
gas is $2.57 per MMBtu, which escalates annually at the higher of 3% or
a sharing of the indexed energy payment rate received by the
owner/operator.
9. EMPLOYEE BENEFIT PLANS
STOCK OPTION PLAN
The Board of Directors adopted the Prima Energy Corporation 1993
Stock Incentive Plan effective September 14, 1993. The Plan was
approved by Prima's stockholders at the 1994 Annual Meeting. The
plan reserves 400,000 shares of Prima's common stock for issuance to key
employees at fair market value on the date of grant of a stock option.
Options granted under the plan vest at 20% per year for five years,
with a term of 10 years from the date of grant. As of December 31,
1995, options to purchase 155,000 shares at $13.25 per common share, of
which 62,000 shares were vested, options to purchase 15,000 shares at
$14.00 per common share, of which 3,000 were vested, and options to purchase
75,000 shares at $14.875, none of which were vested, had been granted under
the plan. None of the options had been exercised as of December 31, 1995 or
March 15, 1996.
During 1995, the FASB issued Statement of Financial Accounting
Standards No. 123, "Accounting for Stock Based Compensation" ("SFAS
123"). SFAS 123 requires entities to either account for, or disclose,
stock based compensation in their financial statements. The Company is
required to adopt SFAS 123 no later than 1996. Because the Company
intends to elect only the disclosure provisions of SFAS 123, the
adoption of SFAS 123 is not expected to have a material effect on the
financial position or results of operations of Prima.
Employee Stock Ownership Plan
The Company has an Employee Stock Ownership Plan ("Plan") and a
Trust to administer the Plan. The Plan is qualified under Section
401(a) of the Internal Revenue Code of 1986, as amended, and is for
the benefit of all eligible employees of the Company. Allocations to
participants are made annually as of the last day of the Plan year,
September 30, and are allocated among the participants in proportion to
their eligible compensation for the Plan year. Contributions to the
plan are payable at a minimum rate of 5% of eligible salaries. Through
the Plan year ended September 30, 1993, the Plan provided for contributions
to be made quarterly and to be used to purchase Prima common stock on the
open market. Effective October 1, 1993, the Plan was amended to allow fully
vested employees the option to direct the Plan Trustees to diversify a
portion of their Plan investments by selling a limited percent of Prima
common stock and investing the proceeds in various investment options. The
Plan benefits all full-time employees and includes six year, 100% vesting
provisions. For the years ended December 31, 1995, 1994 and 1993, the
Company expensed $93,000, $119,000 and $103,000, respectively, of
contributions payable to the Plan.
10. DESIGNATED CASH AND RELATED PRODUCTION TAXES PAYABLE
The Company has designated a portion of its cash balance for
payment of production taxes withheld from third party revenue interest
owners. The non-current portion of production taxes payable relates to
ad valorem taxes collected and accrued for production through December
1995 which is not payable until fiscal 1997 or later. The related cash
collected from third party revenue interest owners designated for
payment of non-current ad valorem taxes is reflected as a non-current
asset.
11. TRANSACTIONS WITH RELATED PARTIES
The Company is a 6% limited partner in a real estate limited
partnership which currently owns approximately 22 acres of undeveloped
land in Phoenix, Arizona for investment and capital appreciation. The
partnership owns the 22 acres free and clear. One of the general partners of
the partnership is a company controlled by the brother of the Company's
president. The Company participated on the same basis as the other limited
partners. This transaction was approved by the disinterested members of the
Company's Board of Directors.
Certain of the Company's directors and officers have participated,
either individually or through entities which they control, in oil and
gas prospects or properties in which the Company has an interest.
These participations, which have been on a working interest basis, have
been in prospects or properties originated or acquired by the Company.
In substantially every instance, there has also been one or more
non-affiliated participants who participated on the same basis as the
officers and directors. In some cases, the interests sold to affiliated
and non-affiliated participants were sold on a promoted basis requiring
these participants to pay a portion of the Company's costs. Each of the
participations by directors and officers has been on terms no less
favorable to the Company than it could have obtained from non-affiliated
participants. It is expected that joint participations with the Company
will occur from time to time in the future. All participations by the
officers and directors have and will continue to be approved by the
disinterested members of the Company's Board of Directors.
At any point in time, there are receivables and payables with
officers and directors that arise in the ordinary course of business.
These amounts are not significant.
12. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Costs incurred in oil and gas property acquisition, exploration and
development activities are as follows:
Years Ended December 31,
1995 1994 1993
Acquisition costs:
Unproved properties........... $ 1,319,000 $ 688,000 $ 341,000
Proved properties............. 27,000 402,000 472,000
Exploration costs............... 202,000 0 0
Development costs............... 3,634,000 9,530,000 10,244,000
Total........................ $ 5,182,000 $10,620,000 $11,057,000
Amortization per equivalent
barrel of production......... $ 4.13 $ 4.08 $ 4.05
Results of operations for oil and gas producing activities are as
follows:
Years Ended December 31,
1995 1994 1993
Revenues
Oil and gas sales............. $11,502,000 $11,588,000 $11,107,000
Expenses
Lease operating expense....... 1,432,000 1,512,000 1,336,000
Production taxes.............. 736,000 863,000 999,000
Depreciation, depletion and
amortization................. 4,058,000 3,974,000 3,520,000
6,226,000 6,349,000 5,855,000
Income before income taxes...... 5,276,000 5,239,000 5,252,000
Income tax expense.............. 1,233,000 1,048,000 1,050,000
Income from oil and gas
producing properties.......... $ 4,043,000 $ 4,191,000 $ 4,202,000
The reserve information presented below has been prepared by the
Company's personnel. There are numerous uncertainties inherent in
estimating quantities of proved reserves and in projecting future rates of
production and timing of development expenditures. Oil and gas reserve
engineering must be recognized as a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in
an exact way. The accuracy of any reserve estimates is a function of the
quality of available data and engineering and geological interpretation and
judgment. Results of drilling, testing and production after the date of the
estimate may justify revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and natural gas that are
ultimately produced.
Proved oil and gas reserves are the estimated quantities of crude
oil, natural gas, and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions.
Proved developed oil and gas reserves are those proved reserves expected to
be recovered through existing wells with existing equipment and operating
methods.
Proved oil and gas reserves of the Company, all of which are located in
the United States, are as follows:
Years Ended December 31,
1995 1994 1993
Oil Gas Oil Gas Oil Gas
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
Proved reserves:
Beginning of year....... 3,009 46,202 2,702 42,638 1,998 32,341
Purchases of oil and
gas reserves in place.. 14 123 4 345 80 1,100
Revisions of previous
estimates.............. (39) (218) (90) (2,624) (118) 1,340
Extensions, discoveries
and other additions.... 17 5,924 689 9,915 989 11,611
Production.............. (266) (4,298) (296) (4,072) (246) (3,742)
Sales of oil and gas
reserves in place...... (1) (22) (0) (0) (1) (12)
End of Year............. 2,734 47,711 3,009 46,202 2,702 42,638
Proved developed reserves:
Beginning of year...... 2,080 35,664 1,724 30,422 1,265 21,388
End of year............ 1,853 38,076 2,080 35,664 1,724 30,422
Standardized measures of discounted future net cash flows relating to
proved oil and gas reserves are as follows:
Years Ended December 31,
1995 1994 1993
Future cash inflows............ $148,101,000 $144,215,000 $129,969,000
Future production costs........ (47,648,000) (47,347,000) (41,553,000)
Future development costs....... (15,425,000) (13,552,000) (15,065,000)
Future net cash flows.......... 85,028,000 83,316,000 73,351,000
10% discount factor............ (37,243,000) (35,645,000) (31,241,000)
Discounted future net cash
flows before income taxes.... 47,785,000 47,671,000 42,110,000
Discounted future income taxes. (8,605,000) (9,576,000) (7,175,000)
Standardized measure of
discounted future net
cash flows.................... $ 39,180,000 $ 38,095,000 $ 34,935,000
The principal sources of change in the standardized measure of
discounted future net cash flows are as follows:
Years Ended December 31,
1995 1994 1993
Sales of oil and gas produced,
net of production costs....... $ (9,334,000) $ (9,183,000) $ (8,772,000)
Net changes in prices and
production costs.............. (1,763,000) (3,980,000) (3,837,000)
Extensions, discoveries, and
improved recovery, less
related costs................. 8,505,000 13,899,000 12,598,000
Development costs incurred
during the year............... 2,729,000 3,609,000 4,307,000
Changes in estimated future
development costs............. (2,629,000) (103,000) (444,000)
Revisions of previous quantity
estimates and other........... (1,291,000) (2,383,000) 88,000
Purchases of reserves in place. 101,000 208,000 844,000
Sales of reserves in place..... (13,000) 0 (14,000)
Accretion of discount.......... 3,809,000 3,494,000 2,980,000
Net change in income taxes..... 971,000 (2,401,000) (2,613,000)
Net change..................... $ 1,085,000 $ 3,160,000 $ 5,137,000
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each
quarter for the years ended December 31, 1995, 1994 and 1993.
Three Months Ended
3/31/95 6/30/95 9/30/95 12/31/95
Year Ended
December 31, 1995
Revenues............... $5,702,000 $3,954,000 $4,003,000 $5,389,000
Income before income
taxes................ 1,632,000 1,291,000 1,343,000 1,596,000
Net income............. 1,257,000 1,001,000 1,008,000 1,226,000
Net income per share... 0.32 0.26 0.26 0.32
Three Months Ended
3/31/94 6/30/94 9/30/94 12/31/94
Year Ended
December 31, 1994 (1)
Revenues.............. $4,794,000 $4,691,000 $4,139,000 $6,460,000
Income before income
taxes............... 1,510,000 1,483,000 1,295,000 2,515,000
Net income............ 1,215,000 1,193,000 1,035,000 1,788,000
Net income per share.. 0.31 0.31 0.27 0.46
Three Months Ended
3/31/93 6/30/93 9/30/93 12/31/93
Year Ended
December 31, 1993
Revenues.............. $4,042,000 $4,121,000 $3,482,000 $4,819,000
Income before income
taxes............... 1,257,000 1,351,000 1,147,000 1,586,000
Net income............ 1,007,000 1,101,000 927,000 1,216,000
Net income per share.. 0.26 0.28 0.24 0.31
(1) Includes $1,200,000 of revenue, $750,000 of net income and $.19 per
share from non-recurring contract settlements.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Prima Energy Corporation has duly caused this Annual
Report on Form 10-K to be signed on its behalf by the undersigned, thereunto
duly authorized, in Denver, Colorado on the 22nd day of March, 1996.
PRIMA ENERGY CORPORATION
By: /s/ Richard H. Lewis
Richard H. Lewis, President
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Annual Report on Form 10-K has been signed below by the following
persons in the capacities indicated and on the dates indicated.
Signature Title Date
/s/Richard H. Lewis March 22, 1996
Richard H. Lewis Chairman, President, Treasurer,
(Principal Executive and
Financial Officer)
/s/Robert E. Childress March 22, 1996
Robert E. Childress Director
/s/Douglas J. Guion March 22, 1996
Douglas J. Guion Director
/s/John P. Lockridge March 22, 1996
John P. Lockridge Director
/s/George L. Seward March 22, 1996
George L. Seward Director
/s/Sandra J. Irlando March 22, 1996
Sandra J. Irlando Vice President of Accounting
and Controller
<PAGE>
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
Prima Energy Corporation has one direct wholly owned subsidiary, Prima
Oil & Gas Company, a Colorado corporation.
Prima Oil & Gas Company has two significant wholly owned subsidiaries.
These are as follows:
1. Action Oil Field Services, Inc., a Colorado corporation.
2. Prima Natural Gas Marketing, Inc., a Colorado corporation.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PRIMA
ENERGY CORPORATION'S FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31,
1995 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 3,977,000
<SECURITIES> 1,180,000
<RECEIVABLES> 3,130,000
<ALLOWANCES> (43,000)
<INVENTORY> 217,000
<CURRENT-ASSETS> 8,792,000
<PP&E> 48,514,000
<DEPRECIATION> (19,396,000)
<TOTAL-ASSETS> 38,565,000
<CURRENT-LIABILITIES> 4,500,000
<BONDS> 0
<COMMON> 58,000
0
0
<OTHER-SE> 29,858,000
<TOTAL-LIABILITY-AND-EQUITY> 38,565,000
<SALES> 16,106,000
<TOTAL-REVENUES> 19,048,000
<CGS> 10,153,000
<TOTAL-COSTS> 10,153,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 5,862,000
<INCOME-TAX> 1,370,000
<INCOME-CONTINUING> 4,492,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 4,492,000
<EPS-PRIMARY> 1.16
<EPS-DILUTED> 1.16
</TABLE>
EXHIBIT 99
No.
IN THE
SUPREME COURT OF THE UNITED STATES
OCTOBER TERM, 1995
WILLIAMS NATURAL GAS COMPANY,
Petitioner,
V.
TALUS PROPERTIES LIMITED PARTNERSHIP,
PRIMA OIL AND GAS COMPANY, JOHN P.
LOCKRIDGE, YUMA COUNTY OIL COMPANY,
AND JER PARTNERSHIP,
Respondents.
ON PETITION FOR WRIT OF CERTIORARI
TO THE UNITED STATES COURT OF APPEALS
FOR THE TENTH CIRCUIT
PETITION FOR WRIT OF CERTIORARI
Gary W. Boyle Jay V. Allen
Counsel of Record Williams Natural Gas
Williams Natural Gas Company
Company 4100 One Williams Center
4100 One Williams Center Tulsa, Oklahoma 74172
Tulsa, Oklahoma 74172
(918) 588-235
<PAGE>
QUESTIONS PRESENTED FOR REVIEW
1. Did the Tenth Circuit Court of Appeals err when it failed to consider
the extrinsic evidence presented to it by the Petitioner?
2. Did the Tenth Circuit Court of Appeals err when it refused to direct
the District Court to consider the Petitioner's contract reformation claim?
<PAGE>
TABLE OF CONTENTS
QUESTIONS PRESENTED FOR REVIEW....................(i)
LIST OF PARTIES AND RULE 29.1 LISTING.............(ii)
TABLE OF AUTHORITIES..............................(v)
OPINIONS..........................................2
JURISDICTION......................................2
RELEVANT STATUTE..................................2
STATEMENT OF THE CASE.............................2
REASONS FOR GRANTING THE WRIT.....................6
Summary of Argument...............................6
I. THE COURT OF APPEALS' DECISION
INVOLVES FEDERAL ISSUES THAT HAVE
A SIGNIFICANT IMPACT ON THE
INTERSTATE NATURAL GAS GRID...................6
A. The Decision Below Directly Conflicts
With FERC's Policy Determinations in
Its Order No. 636, Which Introduced
Competition to the Interstate Gas
Supply and Transportation Markets.........6
B. The Tenth Circuit's Interpretation of
the Contracts Creates an Unconscionable
Burden on Interstate Commerce.............9
II. IN A MATTER OF GREAT PUBLIC IMPORTANCE,
THE TENTH CIRCUIT MISAPPLIED THE
APPLICABLE LAW AND HELD THAT WNG MUST
PERPETUALLY PURCHASE GAS FROM THE
RESPONDENTS AT AMOUNTS IN EXCESS
OF 400% OF THE MARKET PRICE...................10
A. Standard of Review........................10
B. The Tenth Circuit Erroneously
Determined That the Contracts are
Unambiguous...............................11
(iii)
<PAGE>
1. The Contracts Contain Internally
Inconsistent Language.................13
2. Circumstances External to the
Contracts Also Raise
Ambiguities...........................15
3. The Absurdity of the Contracts'
Operation Evidences Their
Ambiguity.............................16
C. The Tenth Circuit Erroneously Refused
to Consider WNG's Extrinsic Evidence
........................................18
D. The Tenth Circuit Erroneously Failed
to Direct the District Court to
Consider WNG's Reformation Claim..........24
CONCLUSION........................................27
(iv)
<PAGE>
TABLE OF AUTHORITIES
Court Cases
American Casualty Co. v. Glaskin, 805 F. Supp. 866 (D. Colo.
1992)...................................................24
Amoco Prod. Co. v. Kansas Power & Light Co., 505 F. Supp.
628 (D. Kan. 1980).................................15, 22
Amoco Prod. Co. v. Western Slope Gas Co., 754 F.2d 303
(10th CIRC. 1985)............................................13
Amoco Rocmount Co. v. Anschutz Corp., 7 F.3d 909 (10th Cir.
1993)............................................11, 12,19
Anderson v. Liberty Lobby, Inc., 477 U.S. 242 (1986).........11
Boyles Bros. Drilling Co. v. Orion Indus.,Ltd., 761 P.2d 278
(Colo. Ct. App.1988)................................24, 25
Chilson v. Reed, 389 P.2d 87 (Colo. 1964)....................25
City of Wichita v. Southwestern Bell Tel.Co., 24 F.3d 1282
(10th Cir. 1994)........................................15
Colorado Interstate Gas Co. v. Chemco, Inc., 833 P.2d 786
(Colo. Ct. App.1991), affd, 854 P.2d 1232 (Colo.
1993)...............................................11, 19
Eastman Kodak Co. v. Image Technical Serv., Inc., 504 U.S.
451 (1992)..........................................10, 11
(v)
<PAGE>
Evensen v. Pubco Petroleum Corp., 274 F.2d 866 (10th Cir.
1960)................................................12,16
Jensen v. Redevelopment Agency, 998 F.2d 1550 (10th Cir.
1993)...................................................10
In re Manzo, 659 P.2d 669 (Colo. 198').......................24
Northwest Cent. Pipeline Corp, v. JER Partnership, 943 F.2d
1219 (10th Cir. 1991).............3, 15, 17,18, 19, 20, 21
Oklahoma Radio Ass'n v. F.D.I.C., 987 F.2d 685 (l0th Cir.
1993)...................................................11
Otteson v. United States, 622 F.2d 516 (10th Cir. 1980)......11
Pennzoil v. F.E.R.C., 645 F.2d 360 (5th Cir. 1991), cert,
denied, 454 U.S.1142 (1982).............................13
Prenalta Corp. v. Colorado Interstate Gas Co., 944 F.2d 677
(10th Cir. 1991)........................................12
Segelke v. Kilmer, 360 P.2d 423 (Colo. 1961).................24
In re Thomason, 802 P.2d 1189 (Colo. Ct. App. 1990)..........12
United States v. Diebold, Inc., 369 U.S. 654 (1962)..........10
United States Fidelity & Guar. Co. v. Budget Rent-A-
Car Sys., Inc., 842 P.2d 208 (Colo. 1992)...............12
(vi)
<PAGE>
Western Gas Processors, Ltd. v. Woods Petroleum Corp.,.......15
F.3d 981 (10th Cir. 1994)...............................16
Wota v. Blue Cross & Blue Shield, 831 P.2d 1307 (Colo. 1992)
........................................................12
Statutes
28 U.S.C. 1254(l) (1994)....................................2
28 U.S.C. 1332(a)(1), 2201(a) (1994).......................2
Colo. Rev. Stat. Section 4-2-202 (1992)...............2, 21, 22
Fed. R. Civ. P. 56(c)........................................11
UCC Section 2-202.............................................5
Administrative Materials
Pipeline Serv. Obligations and Revisions to Regulations Governing
Self-Implementing Transportation; and Regulation of Natural Gas Pipelines
After Wellhead Decontrol (hereinafter Order No. 636), 57 Fed. Reg. 13,267,
III FERC Stats. & Regs. Preambles 30,939, order on reh'g. 57 Fed. Reg.
36,128, III FERC Stats. & Regs. Preambles 30,950, order on reh'g, 57 Fed.
Reg. 57,911, 61 FERC 61,272
(1992).....................................................7, 8
Presentations of INGAA Panel at Pub. Conference on Pricing
Differential Mechanisms, Interstate Natural Gas Ass'n of
America, May 26, 1994.........................................8
(vii)
<PAGE>
No.
IN THE
SUPREME COURT OF THE UNITED STATES
OCTOBER TERM, 1995
WILLIAMS NATURAL GAS COMPANY,
Petitioner,
V.
TALUS PROPERTIES LIMITED PARTNERSHIP,
PRIMA OIL AND GAS COMPANY, JOHN P.
LOCKRIDGE, YUMA COUNTY OIL COMPANY,
AND JER PARTNERSHIP,
Respondents.
ON PETITION FOR WRIT OF CERTIORARI
TO THE UNITED STATES COURT OF APPEALS
FOR THE TENTH CIRCUIT
PETITION FOR WRIT OF CERTIORARI
Petitioner, Williams Natural Gas Company ("WNG"), seeks a writ of
certiorari to review an opinion and order of the United States Court of
Appeals for the Tenth Circuit, which affirmed an order granted by the
district court in favor of Respondents.
<PAGE>
OPINIONS BELOW
The December 5, 1995, unpublished opinion of the Tenth Circuit is
reprinted at Appendix A 1 and may be found at 1995 U.S. App. LEXIS 33,734.
The unpublished decision of the United States District Court for the
District of Colorado (Nottingham, D.J.), is reprinted at App. B.
JURISDICTION
The United States Court of Appeals for the Tenth Circuit issued its
opinion on December 5, 1995. App. A. This petition for a writ of
certiorari is being docketed in this Court within ninety days from the
entry of judgment by the Court of Appeals. The Jurisdiction of this Court
is invoked under 28 U.S.C. 1254(l) (1994).
RELEVANT STATUTE
Pursuant to Rule 14.1(f), WNG has attached a copy of Colo. Rev. Stat.
Section 4-2-202 (1992) as App, C.
STATEMENT OF THE CASE
This case arises from the respondents' action seeking declaratory
judgment in a contract dispute and WNG's counterclaim seeking reformation
of the contracts involved. The district court's jurisdiction was based on
diversity of citizenship grounds under 28 U.S.C. 1332(a)(1), 2201(a)
(1994). WNG is a Delaware corporation with its principal place of business
in Oklahoma. Talus Properties Limited Partnership is a Texas partnership,
1 References to documents reprinted in an Appendix will hereinafter
appear in the petition as "App."
2
<PAGE>
with a General Partner that is a South Carolina corporation with a
principal place of business in South Carolina and with Limited Partners of
a New Jersey corporation with a principal place of business in Florida and
an individual who is a resident of Switzerland and a citizen of the United
States. Prima Oil and Gas Company is a Colorado corporation with its
principal place of business in Colorado. John P. Lockridge is a Colorado
citizen. Yuma County Oil Company is a Colorado corporation with its
principal place of business in Colorado. JER Partnership is a Colorado
partnership whose partners are all Colorado citizens.
Respondents are the sellers, and WNG is the buyer, under three Gas
Purchase Contracts (the "Contracts"). Various aspects of the Contracts had
been before the district court in four prior proceedings and before the
Tenth Circuit in Northwest Central Pipeline Corp. v. JER Partnership, 943
F.2d 1219 (1Oth Cir. 1991). The Contracts are identical with respect to
their provisions concerning the term of WNG's obligation to purchase gas.
The Contracts provide, in part, as follows:
Term
This Contract shall remain in full force and effect from the date
hereof and shall extend for a period of twenty (20) years from the date of
initial delivery of gas hereunder.
3
<PAGE>
Preferential Right to Purchase and Right of First Refusal
Upon the expiration of the primary term of this Contract, Seller
hereby grants to Buyer the preferential right and the right of first
refusal to purchase gas produced from the wells, leases and lands described
on Exhibit "A" attached hereto. At least thirty (30) days, but not more
than ninety (90) days, before the expiration of this contract, Seller may
make a bona fade offer to Buyer to sell that natural gas which may
thereafter be produced from such wells, leases and lands. If no offer is
made by Seller to Buyer within the time above described, then that natural
gas thereafter produced from the wells, leases and lands described on
Exhibit "A" will continue to be sold to Buyer under the terms and
conditions of this Contract. Thereafter, Seller shall have the right to
make a bona fide offer at least thirty (30) days, but not more than ninety
(90) days, before the next anniversary date of this Contract and each and
every anniversary date thereafter until Seller shall make a bona fide offer
to Buyer within the above described time period prior to any succeeding
anniversary date.
The parties discovered that they interpreted the quoted language
differently in the course of settling claims raised in other litigation,
which has since been settled. Respondents filed a declaratory judgment
action asking the district court to hold that the Contracts provide
Respondents with the power to unilaterally extend WNG's obligation beyond
the twenty-year term. WNG opposed that claim and sought a declaration that
the Contracts could not be extended beyond the twenty-year term without
the consent of WNG or, in the alternative, an equitable reformation of the
Contracts to reflect the agreement of the parties that the Contracts could
not be extended beyond the twenty-year term without WNG's consent.
4
<PAGE>
Respondents filed a motion for summary judgment contending that the
Contracts are unambiguous and that they provide Respondents with the option
to unilaterally extend the term. WNG opposed the motion on the same grounds
presented here. The district court granted Respondents' motion for summary
judgment, holding that the Contracts are unambiguous and that they provide
Respondents with a unilateral option to extend. The district court entered
a judgment declaring that interpretation of the Contracts and specifically
declining to reach WNG's reformation action. App. B at 9. WNG appealed
that decision to the Tenth Circuit.
On appeal, the Tenth Circuit found that the Contracts' terms are
"plain and unambiguous." App. A at 5. From this finding, the court
concluded that "defendant cannot introduce extrinsic evidence to vary or
contradict" the Contracts' terms. App. A at 5.
Despite the fact that the Contracts are not fully integrated, the
court held that WNG's evidence of consistent additional terms was
inadmissible. The court recognized that UCC Section 2-202 (as adopted in
Colorado) allows a party to introduce, evidence of consistent, additional
contract terms. However, the evidence was not allowed because the court
erroneously believed that the additional terms would conflict with the
Contracts.
Finally, the court disallowed WNG's reformation counterclaim. WNG
presented several examples of evidence that supported its request for
reformation of the Contracts. However, the court's opinion incorrectly
recognized only the evidence that supported the court's ultimate conclusion.
5
<PAGE>
REASONS FOR GRANTING THE WRIT
SUMMARY OF AGREEMENT
In a matter of great public importance, this Court should grant
certiorari in order to limit the negative impact of the Court of Appeals'
decision on the clearly established policy goals of the Federal Energy
Regulatory Commission ("FERC"). If this decision is allowed to stand,
FERC's attempts to introduce competition to the interstate natural gas
market will be threatened, and the economic basis on which FERC reorganized
the natural gas industry will be thrown into serious question. FERC's
inability to meet its competition goals, and the resulting chaos in the
interstate natural gas transportation markets, would ultimately cause
citizens nationwide to pay higher gas rates without receiving corresponding
value in return.
1. THE COURT OF APPEALS' DECISION INVOLVES FEDERAL ISSUES THAT HAVE A
SIGNIFICANT IMPACT ON THE INTERSTATE NATURAL GAS GRID.
A. The Decision Below Directly Conflicts With FERC's Policy
Determinations in Its Order No. 636, Which Introduced Competition to
the Interstate Gas Supply and Transportation Markets.
In its Order No. 63 6, FERC made a sweeping regulatory reorganization
of the interstate natural gas industry that was designed to promote
6
<PAGE>
competition among suppliers for both gas and natural gas transportation
services.2 The FERC intended such competition to benefit individual gas
consumers and the nation as a whole by ensuring reliable gas supplies at
reasonable prices.
When FERC was developing its regulations, it made economic assessments
of the impact of reorganization based on the assumption that gas supply
contracts entered into by pipelines would terminate after a known time
period. The termination of gas supply contracts was required because FERC
believed that it would be in the consumers' best interests to take
pipelines out of the business of buying and selling gas and limit them to
transportation only. "Unbundling" of pipelines' merchant function was
necessary to realize FERC's goal of a competitive interstate natural gas
grid. To assist a fair and orderly transition to the reorganized industry,
FERC permitted pipelines to recover from ratepayers the cost of terminating
their gas purchase contracts that were no longer necessary due to the
reorganization. FERC assumed that the transition costs associated with
terminating the contracts would be limited to reasonable amounts by the
terms of the contracts.
FERC's economic assumptions played a key role in the formulation of
its policies. The decision of the Tenth Circuit in this case, if followed
in other Circuits, would invalidate FERC's careful analysis. With the
underlying analysis undermined, the complete restructuring of the massive
interstate natural gas system would be thrown into question. This Court
has the opportunity to stop the potential destruction of FERC's well
planned efforts to restructure the natural gas transportation industry for
the benefit of consumers across the nation.
2 Pipeline Serv. Obligations and Revisions to Regulations Governing
Self-Implementing Transportation; and Regulation of Natural Gas
Pipelines after Wellhead Decontrol (hereinafter Order No. 636), 57 Fed.
Reg. 13,267, III FERC Stats. & Regs. Preambles 30,939, order on reh'g,
57 Fed. Reg. 36,128, III FERC Stats. & Regs. Preambles 30,950, order on
reh'g, 57 Fed. Reg.57,911, 61 FERC 61,272 (1992).
7
<PAGE>
Actions that steer reality away from FERC's projections pose a
serious threat to FERC's competitive efforts. The Tenth Circuit's
interpretation of the Contracts, when combined with the potential for
similar decisions in other Circuits, has just such an effect. In WNG's
case, it was assumed that the Contracts would expire in 2002 (a twenty-year
term) based on the written terms of the Contracts. The Tenth Circuit's
decision causes the Contracts to continue perpetually. There are many
contracts that FERC assumed had various remaining terms with some extending
as long as 2004.3 If the Tenth Circuit's decision is allowed to stand, some
of these contracts could be interpreted in a manner similar to WNG's
Contracts. Such an interpretation would clearly render FERC's initial
assumptions about the industry's contracts unreliable and would pose a
severe threat to FERC's competitive goals.
Pipeline companies will pass the extra gas costs they pay under such
extended contracts to their customers.4 The resulting threat to
competition would be two-fold. First, this would attach to the effected
pipelines a stigma as a potential source of future, hidden costs. This
would have a negative impact on interstate pipelines' competitive standing
in the marketplace. Second, the amounts charged to the pipelines' former
and current customers lessen the amount of money that the customers have
available to spend on future services. This has the same impact as if a
portion of the customers were simply removed from the marketplace because
the customers will not be able to purchase their anticipated amount of
services.
3 Presentations of INGAA Panel at Pub. Conference on Pricing
Differential Mechanisms, Interstate Natural Gas Ass'n of America,
May 26, 1994.
4 FERC determined that the costs of the pipelines' transition to a
competitive market, including the Respondents' excess recovery under
the Contracts, should be completely borne by the customers, as long as
the pipelines prudently incurred the costs. Order No. 636, III FERC
Stats. & Regs. Preambles 30,939, at 30,457-59 (1992).
8
<PAGE>
Overall, the net result of the Tenth Circuit's ruling in this case is to
make interstate pipeline companies less competitive with intrastate
pipelines and to destroy the basis on which FERC restructured the industry.
This result directly contradicts the commendable, stated policy goals of
FERC. Such a conflict is clearly a matter of public and federal importance
that this Court should review.
B. The Tenth Circuit's Interpretation of the Contracts Creates an
Unconscionable Burden on Interstate Commerce.
The pipeline's customers will ultimately bear the costs of the
Contracts. In this instance, WNG's local distribution company customers in
Kansas and Missouri will pay for the difference between the contract price
of the gas and the actual market price for the gas - approximately a 400%
markup. WNG will be little more than a conduit through which the gross
overrecovery windfall will pass from the hands of individual consumers and
businesses in Kansas and Missouri into the pockets of gas producers in
Colorado. Although it may be reasonable to force consumers to pay these
costs for a fixed term, it is unreasonable and contrary to public policy
to force them to pay these costs in perpetuity as the Tenth Circuit has
ruled. The payment required by the Tenth Circuit is especially egregious
when one recalls that the FERC determined that consumers would be best
served by an industry restructuring for which those consumers would pay.
Allowing the Tenth Circuit's decision to stand will unfairly increase the
cost of transition for consumers and will do so for an unlimited term.
9
<PAGE>
Because other interstate pipelines have similar contracts, consumers
in other states are potential targets of a comparable, burdensome
interstate wealth transfer from consumers in gas-consuming states to
producers in gas-producing states. The total impact of such a transfer
presents a serious burden on interstate commerce, which this Court should
not countenance. By saddling consumers with an unexpected perpetual
surcharge, the Tenth Circuit's opinion regarding the Contracts creates a
situation that compels this Court's review.
II. IN A MATTER OF GREAT PUBLIC IMPORTANCE, THE TENTH CIRCUIT MISAPPLIED
THE APPLICABLE LAW AND HELD THAT WNG MUST PERPETUALLY PURCHASE GAS FROM THE
RESPONDENTS AT AMOUNTS IN EXCESS OF 400% OF THE MARKET PRICE.
A. Standard of Review.
Courts must review summary judgment decisions de novo.5 Thus, the
Court should utilize the same legal standards as the district court in
evaluating the motion. This Court may affirm the Tenth Circuit's decision
only if it finds that there is no genuine issue
5 Eastman Kodak Co. v. Image Technical Serv., Inc., 504 U.S. 451, 466
n. 10 (1992) (citing United States v. Diebold, Inc., 369 U.S. 654
(1962)); Jenson v. Redevelopment Agency, 998 F.2d 1550, 1555 (10th Cir.
1993).
10
<PAGE>
as to any material fact and that Respondents were entitled to judgment as a
matter of law.6 This Court must view this case in the light most favorable
to WNG, the party that opposed the motion.7 WNG's evidence is to be
believed and all justifiable inferences are to be drawn in WNG's favor.8
B. The Tenth Circuit Erroneously Determined That the Contracts are
Unambiguous.
The Tenth Circuit reviewed the Contracts and concluded that the term
provisions are unambiguous. The Tenth Circuit incorrectly concluded that
such a finding was necessary if the court was to ignore the disputed issues
raised by WNG's extrinsic evidence. The Tenth Circuit's conclusion that
the Contracts are unambiguous is an incorrect determination of a question
of law and should be reversed.
The existence of an ambiguity in a written contract is a question of
law.9 The meaning of a written contract, however, is
6 Fed. R. Civ. P. 56(c).
7 Eastman Kodak, 504 U.S. at 456; Oklahoma Radio Ass'n v. F.D.I.C,.,987
F.2d 685, 690 (10th Cir. 1993); Otteson v. United States, 622 F.2d 516,
519 (1Oth Cir. 1980).
8 Anderson v. Liberty Lobbv, Inc., 477 U.S. 242 (1986).
9 Amoco Rocmount Co. v. Anschutz Com., 7 F.3d 909, 917 (10th Cir. 1993)
(interpreting Colorado law); Colorado Interstate Gas Co. v. Chemco. Inc.
833 P.2d 786, 788 (Colo. Ct. App. 1991), aff'd. 854 P.2d 1232 (Colo.
1993).
11
<PAGE>
a question of fact to be resolved in the same manner as other factual
disputes.10
In determining whether the Contracts are ambiguous, this Court must
examine the entire contract and not isolate particular phrases or
clauses.11 This Court should construe the provisions of the Contracts in
harmony with their ordinary meaning with reference to all other provisions
of the Contracts.12
This Court should also consider certain extrinsic evidence in
determining whether the Contracts are ambiguous. The Court should consider
the nature of the transaction,13 the commercial context of the Contracts,
the purpose of the Contracts, and the circumstances surrounding the
execution and performance of the Contracts.14
Ambiguity often arises from the application of the contract to the
subject matter of the agreement, and extrinsic evidence is admissible
to remove and explain any ambiguity in the contract as applied.
Ambiguity easily arises when the contract is applied to its subject
matter in changed circumstances. . . . A contract
10 Amoco Rocmount 7 F.3d at 917.
11 Amoco Rocmount, 7 F.3d at 917; United States Fidelitv & Guar. Co.
v. Budget Rent-A-Car Sys., Inc., 842 P.2d 208, 213 (Colo. 1992).
12 Wota v. Blue Cross & Blue Shield, 831 P.2d 1307, 1309 (Colo. 1992).
13 Amoco Rocmount, 7 F.3d at 917; In re Thomason, 802 P.2d 1189, 1190
(Colo. Ct. App. 1990).
14 Prenalta Corp. v. Colorado Interstate Gas Co., 944 F.2d 677, 688
(10th Cir. 1991); Evensen v. Pubco Petroleum Corp)., 274 F.2d 866, 871
(10th Cir. 1960).
12
<PAGE>
should be interpreted in light of the changed circumstances to accomplish
what the parties intended.15
The ambiguity in the Contracts arises in part as a result of dramatically
changed circumstances. First, at the time the parties negotiated the
Contracts they believed that the then-regulated price of natural gas would
continue to rise. Next, unlike the time period during which the Contracts
were negotiated, the price of natural gas is no longer subject to federal
regulation. Finally, FERC's new regulatory scheme has dramatically changed
the nature of WNG's business. WNG is now purely a gas transporter and no
longer performs a merchant (purchasing and selling gas) function. A
reasonable consideration of those circumstances compels the conclusion that
the Contracts' provisions concerning the term of WNG's purchase obligation are
ambiguous.
1. The Contracts Contain Internally Inconsistent Language.
The parties clearly and uniformly expressed WNG's obligation to
perform elsewhere in the Contracts. The lack of any language which can
fairly be interpreted as imposing an obligation on WNG in the preferential
right section strongly suggests that the parties intended to impose no such
obligation. At a minimum, the lack of any such definitive language raises
an ambiguity contrary to the Tenth Circuit's decision.
15 Amoco Prod. Co. v. Western Slope Gas Co. 754 F.2d 303, 309 (10th Cir.
1985) (quoting Pennzoil v. F.E.R.C.. 645 F.2d 360, 388 (5th Cir. 1981),
cert. denied, 454 U.S. 1142 (1982)).
13
<PAGE>
The Tenth Circuit's reading of the Contracts also ignores the directly
conflicting language of the remainder of the Contracts. The term provision
of the Contracts provides that they "shall extend for a period of twenty
(20), years from the date of initial delivery of gas." That language is not
qualified by the possibility of a unilateral extension. The clear and
unambiguous meaning of that provision directly contradicts the Tenth
Circuit's conclusion that the respondents can unilaterally extend the term
of the Contracts beyond twenty years.
Other aspects of the preferential right section raise ambiguities.
The title of the provision itself suggests that the parties included it in
the Contracts to grant WNG a rather than an obligation, to purchase gas
beyond the twenty-year term of the Contracts. A right of WNG to extend the
term is directly contrary to the Tenth Circuit's conclusion that the
respondents obtained a unilateral right to control any extension to the
exclusion of WNG. The first sentence of the clause confirms the intent
expressed in the title: "Upon the expiration of the primary term of this
Contract, [Talus] hereby grants to WNG] the preferential right and the
right of first refusal to purchase gas." (emphasis added). These
provisions directly contradict the Tenth Circuit's conclusion and raise
fundamental ambiguity inherent in the language of the Contracts.
14
<PAGE>
2. Circumstances External to the Contracts Also Raise Ambiguities.
Even if the language of the Contracts does not raise an ambiguity, a
proper consideration of the circumstances surrounding the Contracts, their
purpose, and their commercial context demonstrates the ambiguity. The
parties executed the Contracts at a time when FERC strictly regulated the
price of gas. It was widely believed (including by these parties) that
the price of gas would continue upward following deregulation.16 In this
context, the parties apparently did not anticipate what would happen at the
end of the twenty-year term if, as turned out to be the case, the price of
gas decreased following deregulation. Even more obvious is the fact that
the parties could not and did not anticipate that the price under the
Contracts would eventually reach more than 400% of the actual market value
of the gas. In fact, the language employed by the parties carefully
provides for the period after 2002 based on what the parties thought would
happen. The same language is ambiguous, however, when viewed in the
context of changes in federal regulation and pricing of the underlying
product.17
16 Northwest Cent Pipeline Corp.v.JER Partnership, 943 F.2d 1219, 1222-23
(1Oth Cir. 1991).
17 See City of Wichita v. Southwesten Bell Tel.Co., 24 F.3d 1282,
1287 (10th Cir. 1994) (finding ambiguity based on regulatory changes);
Amoco Prod. Co. v. Kansas Power & Light Co., 505 F. Supp. 628,630
(D. Kan. 1980) (finding ambiguity as the result of regulatory changes in
the natural gas industry).
15
<PAGE>
3. The Absurdity of the Contracts' Operation Evidences Their Ambiguity.
Ambiguity can also be based on the fact that a literal reading of the
contract will lead to an unreasonable or absurd result.18 In Western Gas
Processors, Ltd. v. Woods Petroleum Corp. the court found that the
"unambiguous" definition of a term proffered by the plaintiff was so broad
that adoption of that interpretation would lead to an unreasonable
result.19 The court concluded that the term in question was therefore
ambiguous.20 Here the "unambiguous" interpretation urged by the
respondents and adopted by the Tenth Circuit would similarly lead to an
absurd result. If the Tenth Circuit's decision is affirmed, WGN, its
customers, and their residential users will be forced to purchase gas for
an indefinite term at a price that currently exceeds the market value of
the gas by more than 400%. This grossly overpriced transaction will
continue in perpetuity even though the parties clearly and unequivocally
provided for a fixed term of twenty years and none of the parties
contemplated the possibility of a unilateral, perpetual extension.21 Such
a result is anything but reasonable and demonstrates the ambiguity inherent
in the Contracts as well as the significant public importance of this
decision.
18 See Evensen v. Pubco Petroleum Corp., 274 F.2d 866, 871 (1Oth Cir.
1960).
19 15 F.3d 981, 987 (1Oth Cir. 1994).
20 Id.
21 See discussion of WNG's evidence, infra. at 18-22.
16
<PAGE>
The most appropriate guidance in this matter comes from the Tenth
Circuit's prior interpretation of the very Contracts that are the subject
of this Petition.22 The court considered the interpretation of the pricing
provisions of the Contracts following a trial on the merits. Both the
district court and the Tenth Circuit found that the Contracts are "poorly
written" and ambiguous.23 Now that the contentions of the parties on this
question are reversed, the Tenth Circuit has somehow miraculously found
clarity where only confusion and uncertainty existed before. That decision
is contrary to the law of this case and the clear ruling of the court in
Northwest Central.
The Tenth Circuit's prior decision in Northwest Central found
ambiguity in a different part of the Contracts. Nonetheless, the
courts reasoning should apply with equal force to the preferential right
section. The court found that the lengthy provisions concerning the
price of gas, while dealing extensively with what would appear to be
every possible future contingency, were nonetheless confusing because
they were susceptible of two different and mutually exclusive
inferences.24 The court held:
In short, we refuse to legally preclude the sort of ambiguity created by
conflicting inferences that can be drawn from incomplete contract
language.
22 Northwest Cent. Pipeline Corp v. JER Partnership, 943 F.2d 1219 (1Oth
Cir. 1991).
23 Id. at 1227, 1229.
24 Id. at 1227.
17
<PAGE>
Since the pricing provision's language is susceptible of more than one
reasonable interpretation, we agree with the district court that it is
ambiguous.25
The court also found ambiguity in the fact that the language of the Contracts
is not internally consistent.26
The preferential right section of the Contracts compels exactly the
same conclusion. The parties failed to anticipate what would happen in the
future and therefore failed to provide explicitly for the term of the
Contracts where lower prices, deregulation, and industry restructuring
intervened. This is exactly the sort of ambiguity the Tenth Circuit found
in other provisions of the Contracts. The Tenth Circuit erred in failing
to find the same ambiguity here. That ruling is incorrect as a matter of
law and should be reversed.
C. The Tenth Circuit Erroneously Refused to Consider WNG's Extrinsic
Evidence.
Having incorrectly ruled that the Contracts are unambiguous, the Tenth
Circuit refused to consider evidence of substantial disputes regarding
material extrinsic evidence concerning the intent of the parties. The
court also raffled to correctly apply the Colorado version of the UCC. The
Tenth Circuit's refusal to consider the factual disputes presented by WNG's
extrinsic evidence is reversible error because, if that evidence had been
considered, summary judgment would have been precluded.
25 Id. (citation omitted).
26 Id. at 1228-29.
18
<PAGE>
The ambiguity in the Contracts discussed above required that the Tenth
Circuit consider extrinsic evidence of the parties' intent.27 WNG offered
a significant amount of extrinsic evidence that raised substantial disputes
concerning material facts. The most important evidence of the Respondents'
true intent is their assertion of a delayed drilling claim in related
litigation. The respondents argued, in writing, that they were entitled to
recover for gas that they would have been able to produce during the fixed
twenty-year term of the Contracts but for WNG's litigation. That claim is
wholly dependent on the fixed termination of the Contracts after twenty
years because a perpetual contract would render the claim worthless by
permitting the respondents to recover all of the gas on their property.
In addition to the compelling evidence of the delayed drilling claim,
WNG presented the district court with reserve estimates that reflected
anticipated prices for the gas subject to the Contracts. The estimates
were prepared at the respondents' direction. Portions of those estimates
projected prices through 2002 at a constant level reflective of the price
established by the Contracts. After 2002, prices fluctuate. That
fluctuation is consistent only with sales of gas after 2002 under some
arrangement other than the Contracts, because the Contracts establish a
single price for future production. Also, in November 1981, several months
before the execution of the Contracts, WNG and Respondents entered into a
Letter Agreement. App. D. That agreement sets forth the key elements of
the arrangement that eventually became the Contracts. Among other terms,
it includes the term of the Contracts as twenty years. The parties had the
opportunity in the Letter Agreement to provide for a longer term or for
unilateral extensions but did not.
27 E.g., Amoco Rocmount Co. v. Anschutz Corp., 7 F.3d 909, 918-19 (10th
Cir.1993); Northwest Cent Pipeline Corp. v. JER Partnership, 943 F.2d
1219, 1226 (10th Cir. 1991); Colorado Interstate Gas Co. v. Chemco, Inc.,
833 P.2d 786,789 (Colo. Ct. App. 1991), aff'd, 854 P.2d 1232 (Colo.
1993).
19
<PAGE>
Finally, review of the lengthy litigation history concerning the
Contracts reveals the fact that everyone involved has always acted as
though the Contracts had a fixed term of twenty years:
1) John Lockridge, one of the principals of Respondents, testified
previously that the Contracts covered a term of twenty years.
2) Respondents have argued in briefs that the Contracts provide for a
twenty-year term.
3) Respondents' Complaint in one of the prior lawsuits states that the
Contracts are "in full force and effect through May 2002" and that they
have a "term of 20 years."
4) The district court twice expressly found that the Contracts were
effective for a twenty-year term.
5) The Tenth Circuit recited and approved that finding.28
That conclusion is inconsistent with the respondents' interpretation and
supports WNG's reading of the Contracts.
28 Northwest Cent. Pipeline Corp., 943 F.2d at 1221.
20
<PAGE>
While these statements of the parties and the courts' understanding
of the Contracts do not specifically address the issue raised in this case,
they are circumstantially supportive of WNG's interpretation of the
Contracts and inconsistent with Respondents' interpretation. These
expressions raise sharp factual disputes when viewed in light of
Respondents' allegation that they always interpreted the Contracts as
including the unilateral right to extend them beyond twenty years. Those
factual disputes preclude summary judgment against WNG.
Even if the Tenth Circuit correctly determined that the Contracts are
unambiguous, it failed to consider WNG's evidence regarding additional
terms to the Contracts.29 The extrinsic evidence WNG presented to the
Tenth Circuit shows that the parties intended, consistent with the
provisions of the Contracts, that the preferential right section would
grant the parties the right to mutually extend the Contracts, but would not
grant the respondents the unilateral right to extend them. As discussed
above, the parties failed to define the key terms used in the preferential
right section. Because the district court had previously held that the
Contracts are not complete integrations,30 it should have considered
evidence of consistent additional terms - the definition of key phrases.
That evidence was disputed and therefore summary judgment was precluded.
The Tenth Circuit's refusal to consider the factual disputes raised
by the extrinsic evidence violates Colo. Rev. Stat. Section 4-2-202.
That provision changes the common law
29 Colo. Rev. Stat 4-2-202(b)(1994).
30 Northwest Cent Pipeline Corp., 943 F.2d at 1226. The Tenth Circuit
recited its earlier finding on integration in this proceeding. App. A
at 6.
21
<PAGE>
regarding the admission of parole evidence. Under Section 2-202, "the lack
of facial ambiguity in the contract language is basically irrelevant to
whether extrinsic evidence ought to be considered by the court . . . ."31
Regardless of whether the Contracts are ambiguous, the Tenth Circuit should
have considered WNG's evidence concerning the circumstances surrounding the
Contracts and the parties' conduct during performance.
Because the Contracts are ambiguous and are not complete
integrations, the Tenth Circuit had the obligation to consider extrinsic
evidence of the parties' intent. If the Tenth Circuit had considered the
extrinsic evidence, it would have been compelled to reverse the district
court's summary judgment in favor of Respondents. In failing to do so, the
court committed reversible error.
The Tenth Circuit also erroneously refused to consider WNG's evidence
of additional terms because the court ruled that the terms were not
consistent with the rest of the Contracts. A review of the Contracts and
WNG's proffered interpretation, however, makes it clear that WNG's
interpretation is consistent with the language of the Contracts.
WNG's interpretation of the Contracts gives effect to every provision
of the Contracts, and the Tenth Circuit, therefore, should have adopted
this interpretation. WNG contends that the Contracts give the parties the
power to continue the purchasing relationship after the conclusion of the
twenty-year term only if WNG agrees. WNG's interpretation gives meaning to
the grant to WNG of a preferential right to purchase gas. It also gives
full effect to the parties' agreement to a term of twenty years. Further,
it gives effect to the second and third sentences of the preferential
rights section:
31 Amoco Prod.Co.v.Westen Slope Gas Co.. 754 F.2d 303, 308
(1Oth Cir. 1985) (interpreting Colorado law).
22
<PAGE>
At least thirty (30) days, but not more than ninety (90) days, before the
expiration of this contract [Talus] may make a bona fide offer to [WNG]
to sell that natural gas which may thereafter be produced from such
wells, leases and lands. If no offer is made by [Talus] to [WNG] within
the time above described, then that natural gas thereafter produced from
the Wells, leases and lands described on Exhibit "A" will continue to be
sold to [WNG] under the terms and conditions of this Contract.
Under WNG's interpretation of the Contracts, the respondents are
empowered to make an offer to WNG during the sixty-day period ending thirty
days before the expiration of the Contracts. If they choose not to make an
offer, the Contracts will continue during the remaining thirty days,
subject to all of the terms and conditions of the Contracts. Those terms
and conditions include the immediately preceding paragraph stating that the
Contracts extend only until twenty years after first production. At the
end of the twenty-year term, the Contracts would terminate. Not only the
evidence of the parties' intent but also the language of the Contracts read
in light of the well-established rules of construction compels this
conclusion. The Tenth Circuit should have considered WNG's evidence
concerning consistent additional terms.
23
<PAGE>
D. The Tenth Circuit Erroneously Failed to Direct the District Court to
Consider WNG's Reformation Claim.
WNG's counterclaim stated a cause of action for reformation. Despite
the parties' arguments on the issue and the proper framing of the issue in
the pleadings, the district court concluded that the respondents are
empowered to unilaterally obligate WNG to purchase gas after the end of the
twenty-year term and stated, "[b]ased on that conclusion, I need not reach
the parties' arguments concerning reformation of the contracts." App. B at
9. That conclusion is incorrect as a matter of law, and the Tenth Circuit's
failure to direct the district court to consider WNG's claim for
reformation is reversible error.32
Reformation is an equitable remedy available to correct a mistake in
drafting when the final expression of the parties' agreement does not
express their true intent.33 The mistake may be unilateral if the other
party knows of it.34
The record before the Tenth Circuit established factual disputes with
respect to the elements of WNG's reformation action. The 1981 Letter
Agreement is one expression of the parties' agreement that predates the
Contracts. App. D. The Letter Agreement clearly sets forth a term of twenty
years for WNG's purchase obligation. The parties did not agree that the
respondents would retain a unilateral right to extend the obligation beyond
twenty years. The testimony of Robert Berney, the person who executed the
Letter Agreement and the Contracts for WNG, confirms the expression set
forth in the Letter Agreement. App. E. Mr. Berney testified that the
parties agreed to a straight twenty-year term. App.E.
32 The Tenth Circuit even admitted that it was confused by the reformation
claim. App. A at 7. That confusion is apparent from the substance of the
court's conclusion.
33 See Segelke v. Kilmer, 360 P.2d 423, 426 (Colo. 1961); Boyles
Bros. Drilling Co. v. Orion Indus., Ltd., 761 P.2d 278, 281 (Colo. Ct.
App. 1998).
34 American Casualty Co. v. Glaskin, 805 F. Supp. 866, 873 (D. Colo.
1992); In re Manzo, 659 P.2d 669, 672 (Colo. 1983).
24
<PAGE>
Thereafter, the parties all acted as though the Contracts would last for
only twenty years. The parties and the courts made statements that support
that conclusion. Respondents employed a party to create reserve studies
that are predicated on a twenty year term. Counsel for the respondents
calculated damages on a basis consistent solely with a twenty-year term,
and the principals of the respondents adopted the claim. Respondents
asserted their claims up to the time that the parties settled their prior
disputes. Parole evidence is admissible to establish a claim for
reformation.35 All of this admissible evidence raised factual disputes
concerning the elements of 'WNGs reformation action and therefore precluded
summary judgment.
Contrary to the Tenth Circuit's assertions, WNG's reformation claim
does not negate the other language in the Contracts. The reformation of
the Contracts would merely cause them to operate in the manner originally
intended by the parties. As reformed, the Contracts would simply last for
the agreed-upon twenty-year term and would provide the parties with the
option to extend the Contracts for a longer period. As reformed, the
Contracts would retain their original character rather than have their
original terms negated.
35 Chilson v. Reed, 389 P.2d 87, 89 (Colo. 1964), Boyles Bros., 761 P.2d
at 282.
25
<PAGE>
The district court erred when it concluded that it need not reach the
reformation action.36 The action was appealed to the Tenth Circuit and the
record established substantial disputes concerning material facts. The
conclusion that the Contracts unambiguously provide as the district court
held did not relieve the district court or the Tenth Circuit of the burden
of resolving the claim. Instead, resolution of the reformation claim
is required because the courts interpreted the Contracts adversely to WNG.
Logically, the courts could have avoided WNG's reformation claim only if
they had interpreted the Contracts in the manner urged by WNG. The Tenth
Circuit's failure to direct the district court to consider the reformation
action is reversible error.
36 The Tenth Circuit conceded as much when it relied on dicta from a
prior decision that permits the appellate court to affirm a decision on
grounds not considered by the lower court. Ap. A at 6.
26
<PAGE>
CONCLUSION
The impact of the Tenth Circuit's decision is a matter of great
importance to the interstate natural gas industry in the United States, and
this Court should issue the requested writ. On review, this Court will be
compelled to conclude that the Tenth Circuit's actions were erroneous as a
matter of law.
Respectfully submitted,
Gary W. Boyle
(Counsel of Record)
Jay V. Allen
Williams Natural Gas Company
4100 One Williams Center
Tulsa, Oklahoma 74172
(918) 588-2359
Attorneys for Petitioner
Williams Natural Gas Company
March 4, 1996
27
