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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1993
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER: 1-9743
ENRON OIL & GAS COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 47-0684736
(STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER
OF INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
1400 SMITH STREET, HOUSTON, TEXAS 77002-7337
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 713-853-6161
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
Common Stock, without par value New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes /X/ No / /.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/
Aggregate market value of the voting stock held by non-affiliates of the
registrant, based on the closing sale price in the daily composite list for
transactions on the New York Stock Exchange on March 1, 1994 was $665,277,983.
As of March 1, 1994, there were 79,920,000 shares of the registrant's Common
Stock, without par value, outstanding.
DOCUMENTS INCORPORATED BY REFERENCE. Certain portions of the registrant's
definitive Proxy Statement for the May 3, 1994 Annual Meeting of Shareholders
('Proxy Statement') are incorporated in Part III by reference.
TABLE OF CONTENTS
PART I
PAGE
Item 1. Business----------------------------- 1
General-------------------------- 1
Business Segments---------------- 1
Exploration and Production------- 1
Marketing------------------------ 3
Wellhead Volumes and Prices, and
Lease and Well Expenses-------- 5
Other Natural Gas Marketing
Volumes and Prices------------- 6
Competition---------------------- 6
Regulation----------------------- 6
Relationship Between the Company
and Enron Corp.---------------- 9
Other Matters-------------------- 11
Current Executive Officers of the
Registrant--------------------- 13
Item 2. Properties--------------------------- 14
Oil and Gas Exploration and
Production Properties and
Reserves----------------------- 14
Item 3. Legal Proceedings-------------------- 17
Item 4. Submission of Matters to a Vote of
Security Holders--------------------- 17
PART II
Item 5. Market for the Registrant's Common
Equity and Related Shareholder
Matters---------------------------- 18
Item 6. Selected Financial Data-------------- 19
Item 7. Management's Discussion and Analysis
of Financial Condition and Results
of Operations---------------------- 20
Item 8. Financial Statements and
Supplementary Data------------------- 27
Item 9. Disagreements on Accounting and
Financial Disclosure----------------- 27
PART III
Item 10. Directors and Executive Officers of
the Registrant----------------------- 27
Item 11. Executive Compensation--------------- 27
Item 12. Security Ownership of Certain
Beneficial Owners and
Management------------------------- 27
Item 13. Certain Relationships and Related
Transactions------------------------- 27
PART IV
Item 14. Exhibits, Financial Statement
Schedules, and Reports on Form
8-K-------------------------------- 28
i
PART I
ITEM 1. BUSINESS
GENERAL
Enron Oil & Gas Company (the 'Company'), a Delaware corporation, is engaged
in the exploration for, and the development and production of, natural gas and
crude oil primarily in major producing basins in the United States and, to a
lesser extent, in Canada, Trinidad and selected other international areas. At
December 31, 1993, the Company's estimated net proved natural gas reserves were
1,772 billion cubic feet ('Bcf') and estimated net proved crude oil, condensate
and natural gas liquids reserves were 20.9 million barrels ('MMBbl'). (See
'Supplemental Information to Consolidated Financial Statements'). At such date,
approximately 78% of the Company's reserves (on a natural gas equivalent basis)
was located in the United States, 16% in Canada and 6% in Trinidad. As of
December 31, 1993, the Company employed approximately 690 persons.
The Company's core areas are the Big Piney area in Wyoming, South Texas
primarily centered in the Lobo Trend area, the Matagorda Trend area located in
federal waters offshore Texas and the Canyon Trend located in West Texas. The
Company's other domestic natural gas and crude oil producing properties are
located primarily in other areas of Texas, Utah, New Mexico, Oklahoma and
California. The Company also has natural gas and crude oil producing properties
located in western Canada, primarily in the provinces of Alberta, Saskatchewan
and Manitoba, and in Trinidad. At December 31, 1993, 95% of the Company's proved
domestic reserves (on a natural gas equivalent basis) was natural gas and 5% was
crude oil, condensate and natural gas liquids. A substantial portion of the
Company's natural gas reserves is in long-lived fields with well established
production histories. The opportunity exists to increase production in many of
these fields through infill drilling.
Enron Corp. currently owns 80% of the outstanding common stock of the
Company. (See 'Relationship Between the Company and Enron Corp.').
Unless the context otherwise requires, all references herein to the Company
include Enron Oil & Gas Company, its predecessors and subsidiaries. Unless the
context otherwise requires, all references herein to Enron Corp. include Enron
Corp., its predecessors and affiliates, other than the Company and its
subsidiaries.
With respect to information on the Company's working interest in wells or
acreage, 'net' oil and gas wells or acreage are determined by multiplying
'gross' oil and gas wells or acreage by the Company's working interest in the
wells or acreage. Unless otherwise defined, all references to wells are gross.
BUSINESS SEGMENTS
The Company's operations are all natural gas and crude oil exploration and
production related. Accordingly, such operations are classified as one business
segment.
EXPLORATION AND PRODUCTION
The Company's six principal U.S. producing areas are the Big Piney area,
South Texas area, Matagorda Trend area, Canyon Trend area, Pitchfork Ranch field
and Vernal area. Properties in these areas comprised approximately 76% of the
Company's domestic reserves (on a natural gas equivalent basis) and 83% of the
Company's maximum domestic net natural gas deliverability as of December 31,
1993 and are substantially all operated by the Company. The Company also has
operations in Canada and in Trinidad and is conducting exploration in selected
other international areas.
BIG PINEY AREA. The Company's largest reserve accumulation is located in
the Big Piney area in Sublette and Lincoln counties in southwestern Wyoming. The
Company is the holder of the largest productive acreage base in this area, with
approximately 200,000 net acres under lease directly within field limits. A
portion of the natural gas production from new wells drilled during 1991 and
1992 on the Company's leases in the Big Piney area is classified as tight
formation natural gas. (See 'Other
1
Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption').
The Company operates approximately 461 natural gas wells in this area in which
it owns a 91% average working interest. Production from the area net to the
Company averaged 126 million cubic feet ('MMcf') per day of natural gas and 1.4
thousand barrels ('MBbl') per day of crude oil, condensate, and natural gas
liquids in 1993. At December 31, 1993, maximum natural gas deliverability net to
the Company was approximately 138 MMcf per day.
The current principal producing intervals are the Frontier and Mesaverde
formations. The Frontier formation, which occurs at 6,500-10,000 feet, contains
approximately 66% of the Company's current Big Piney reserves. The Company
drilled 48 wells in the Big Piney area in 1993 and anticipates an active
drilling program will continue for several years.
SOUTH TEXAS AREA. The Company's activities in South Texas are focused in
the Wilcox, Expanded Wilcox, Frio and Lobo producing horizons. The primary area
of activity is in the Lobo Trend which occurs primarily in Webb and Zapata
counties.
The Company operates approximately 625 wells in the South Texas area.
Production is primarily from the Lobo sand of the Wilcox formation at depths
ranging from 7,000 to 11,000 feet. The Company has approximately 260,000 acres
under lease in this area and a majority of the natural gas production from new
wells drilled during 1991 and 1992 on Company leases in the South Texas Lobo
area is classified as tight formation natural gas. (See 'Other Matters - Tight
Gas Sand Tax Credits (Section 29) and Severance Tax Exemption'). Natural gas
sales net to the Company averaged 225 MMcf per day in 1993. At December 31,
1993, maximum natural gas deliverability net to the Company was approximately
250 MMcf per day. The Company drilled 104 wells in the South Texas area in 1993
and anticipates an active drilling program will continue for several years.
MATAGORDA TREND AREA. The Company has an interest in several fields in the
Matagorda Trend area, located 20 miles south of Port O'Connor, Texas in federal
waters. The Company has a 78% working interest in Block 638 and a 92% working
interest in Block 620. In Matagorda Blocks 555, 556, 700 and 713, the Company
has an approximate 70%, 50%, 62% and 64% working interest, respectively. In
addition, the Company has an approximate 82% and 50% working interest in Mustang
Island Blocks 758 and 784, respectively. The Company operates all of the
offshore tracts mentioned above. Natural gas sales from these areas net to the
Company averaged 59 MMcf per day in 1993. At December 31, 1993, maximum natural
gas deliverability net to the Company from these blocks was approximately 76
MMcf per day. The Company expects to maintain an active drilling program in the
Gulf of Mexico during 1994.
CANYON TREND AREA. The Company has added approximately 90,000 acres in this
area during the last five years. Activities have been concentrated in Sutton,
Crockett and Terrell Counties, Texas where the Company drilled 324 natural gas
wells during the period 1991 through 1993. The Company operates approximately
500 natural gas wells in this area in which it owns a 95% average working
interest. Production is from the Canyon sands and Strawn limestone at depths
from 5,500 to 9,500 feet. At December 31, 1993, maximum natural gas
deliverability net to the Company was approximately 70 MMcf per day. The Company
expects to maintain an active drilling program in the Canyon Trend area during
1994. (See 'Other Matters - Tight Gas Sand Tax Credits (Section 29) and
Severance Tax Exemption').
PITCHFORK RANCH FIELD. The Pitchfork Ranch field located in Lea County, New
Mexico, produces primarily from the Bone Spring, Atoka and Morrow formations. In
1993, natural gas sales net to the Company averaged 44 MMcf per day. At December
31, 1993, maximum natural gas deliverability net to the Company was
approximately 46 MMcf per day. During 1993, the Company significantly increased
reserves and deliverability through drilling and workovers. The Company expects
to maintain an active drilling program in this field during 1994. (See 'Other
Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption').
VERNAL AREA. In the Vernal area, located primarily in Uintah County, Utah,
the Company operates approximately 187 producing wells and presently controls
approximately 75,000 net acres. A
2
majority of the natural gas production from new wells drilled during 1991 and
1992 on the Company's leases in the Vernal area is classified as tight formation
natural gas. (See 'Other Matters - Tight Gas Sand Tax Credits (Section 29) and
Severance Tax Exemption'). In 1993, natural gas sales from the Vernal area
averaged 24 MMcf per day compared with approximately 29 MMcf per day maximum
deliverability, both net to the Company. Production is from the Green River and
Wasatch formations located at depths between 4,500-8,000 feet. The Company has
an average working interest of approximately 60%. The Company drilled 14 wells
in the Vernal area in 1993 and expects to maintain a comparable drilling program
during 1994.
CANADA. The Company is engaged in the exploration for and the development
and production of natural gas and crude oil and the operation of natural gas
processing plants in western Canada, principally in the provinces of Alberta,
Saskatchewan, and Manitoba. The Company conducts operations from offices in
Calgary. Effective December 31, 1992, the Company consummated the acquisition of
a natural gas property located in the Sandhills field in Saskatchewan. The
property was further developed in 1993 through the drilling of 150 wells
resulting in deliverability net to the Company from the Sandhills property of
approximately 36 MMcf per day at December 31, 1993. Maximum Canadian natural gas
deliverability net to the Company at December 31, 1993 was approximately 76 MMcf
per day, and the Company held approximately 324,000 net undeveloped acres in
Canada. The Company expects to maintain an active drilling program in Canada
during 1994.
TRINIDAD. In November 1992, the Company was awarded a 95% working interest
concession in the South East Coast Consortium Block offshore Trinidad,
previously held by three government-owned energy companies. Three undeveloped
fields containing crude oil and natural gas rich with condensate are scheduled
for development over the next three to five years. Existing surplus processing
and transportation capacity at the Pelican Field facilities owned and operated
by Trinidadian companies is being used to process and transport the production.
Natural gas is being sold into the local market under a take-or-pay agreement
with the National Gas Company of Trinidad and Tobago. At December 31, 1993,
maximum natural gas deliverability net to the Company was approximately 40 MMcf
per day and the Company held approximately 74,000 net undeveloped acres in
Trinidad. As a result of continued development activities, natural gas
deliveries were averaging approximately 60 MMcf per day and condensate
deliveries were averaging approximately 3.3 MBbl per day net to the Company as
of mid-March 1994. The Company expects to maintain an active development
drilling program in this area in 1994.
OTHER INTERNATIONAL. The Company continues to pursue selected other
conventional natural gas and crude oil opportunities outside North America. In
1993, two unsuccessful wells were drilled in Malaysia and one in the United
Kingdom North Sea area. During 1994, the Company will pursue other exploitation
opportunities in countries where indigenous natural gas reserves have been
identified, particularly where synergies in natural gas transportation,
processing and power cogeneration can be optimized with other Enron Corp.
affiliated companies. The Company currently is actively involved in an effort to
obtain joint venture concessions involving two oil fields (Panna and Mukta) and
one natural gas field (Tapti) offshore India in the Bombay High area. Resolution
is anticipated by mid-1994.
In 1993, the Company continued expansion of its international opportunity
portfolio in the coalbed methane recovery arena. In September 1992, the Company
entered into an operating agreement under which it is serving as operator with
another partner in a venture in the Lorraine Basin in France and under which it
exercised, in March 1994, an option to acquire a 50% working interest in the
concession. In addition, a 100% working interest concession has been obtained in
the Galilee Basin in Queensland, Australia. Protocols have also been signed and
joint venture agreements are in the government approval process in both Russia
and Kazakhstan; joint feasibility studies are underway in China; and, several
other high potential countries are under active investigation.
3
MARKETING
WELLHEAD MARKETING. The Company's wellhead natural gas production is
currently being sold on the spot market and under long-term natural gas
contracts at market responsive prices. In many instances, the long-term contract
prices closely approximate the prices received for natural gas being sold on the
spot market. Approximately one-half of the Company's wellhead natural gas
production is currently being sold to pipeline and marketing subsidiaries of
Enron Corp.
Substantially all of the Company's wellhead crude oil and condensate is sold
under short-term contracts at market responsive prices.
OTHER MARKETING. Enron Oil & Gas Marketing, Inc. ('EOGM'), a wholly-owned
subsidiary of the Company, is a marketing company engaging in various marketing
activities. Both the Company and EOGM contract to provide, under long-term
agreements, natural gas to various purchasers and then aggregate the necessary
supplies for the sales with purchases from various sources including third-party
producers, marketing companies, pipelines or from the Company's own production.
In addition, EOGM has purchased and constructed several small gathering systems
in order to facilitate its entry into the gathering business on a limited basis.
EOGM anticipates providing gathering services when such activity will enhance
its capability as an aggregator and marketer. Both EOGM and the Company utilize
other short and long-term hedging mechanisms including sales and purchases in
the futures market and price swap agreements. These marketing activities have
provided an effective balance in managing the Company's exposure to commodity
price risks in the energy market.
In September 1992, the Company sold a volumetric production payment for
$326.8 million to a limited partnership of which an Enron Corp. affiliated
company is general partner with a 1% interest. Under the terms of the production
payment agreements, the Company conveyed a real property interest of
approximately 124 billion cubic feet equivalent ('Bcfe') (136 trillion British
thermal units) of natural gas and other hydrocarbons in the Big Piney area of
Wyoming. Effective October 1, 1993, the agreements were amended providing for
the extension of the original term of the volumetric production payment through
March 31, 1999 and including a revised schedule of daily quantities of
hydrocarbons to be delivered which is approximately one-half of the original
schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 trillion
British thermal units) versus approximately 87.9 Bcfe (96.4 trillion British
thermal units) remaining to be delivered under the original agreement. Daily
quantities of hydrocarbons no longer required to be delivered under the revised
schedule during the period from October 1, 1993 through June 30, 1996 are
available for sale by the Company. The Company retains responsibility for its
working interest share of the cost of operations. The Company also entered into
a separate agreement with the same limited partnership whereby it has agreed to
exchange volumes owned by the Company in the Midcontinent area and the Texas
Gulf Coast area for equivalent volumes produced and owned by the limited
partnership in the Big Piney area. The costs incurred, if any, to effect
redeliveries pursuant to such exchange are borne by the Company.
The Company also has contracted to supply natural gas to a Texas City, Texas
cogeneration facility which is owned by Cogenron Inc. Cogenron Inc. is 50% owned
by Enron Corp. The primary contract provides for the sale of natural gas under a
fixed schedule of prices substantially above current spot market prices. Current
deliveries of approximately 45 MMcf of natural gas per day are being supplied
primarily by purchases at market responsive prices under a long-term agreement
with an Enron Corp. subsidiary. The Company has also entered into a price swap
agreement with a third party that has the effect of converting the prices under
this contract to a fixed schedule of prices. The resulting prices under this
combination of purchase and price swap agreements are substantially below the
fixed schedule of prices in the primary sales contract. The arrangements are
designed, as to the volumes involved, to provide the Company a fixed margin of
profit under its agreement with Cogenron Inc. However, the Company's commitment
to deliver volumes of natural gas in excess of the current delivery levels at
the schedule of predetermined prices discussed above could be disadvantageous to
the Company during any time spot market prices exceed the applicable contract
prices for natural gas.
4
WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES
The following table sets forth certain information regarding the Company's
wellhead volumes of and average prices for natural gas per thousand cubic feet
('Mcf'), crude oil and condensate, and natural gas liquids per barrel ('Bbl'),
and average lease and well expenses per thousand cubic feet equivalent ('Mcfe' -
natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas
to 1.0 barrel of crude oil and condensate or natural gas liquids) delivered
during each of the three years in the period ended December 31, 1993:
YEAR ENDED DECEMBER 31,
1993 1992 1991
VOLUMES (PER DAY)
Natural Gas (MMcf)
United States---------------- 648.6(1) 533.6(1) 465.8
Canada----------------------- 58.4 30.0 24.8
Trinidad--------------------- 2.3 - -
Total---------------------- 709.3(1) 563.6(1) 490.6
Crude Oil and Condensate (MBbl)
United States---------------- 6.6 6.3 5.9
Canada----------------------- 2.2 2.2 2.3
Trinidad--------------------- .1 - -
Total---------------------- 8.9 8.5 8.2
Natural Gas Liquids (MBbl)
United States---------------- .2 .3 .3
Canada----------------------- .4 .4 .3
Trinidad--------------------- - - -
Total---------------------- .6 .7 .6
AVERAGE PRICES
Natural Gas ($/Mcf)
United States---------------- $ 1.97(2) $ 1.61(2) $ 1.38
Canada----------------------- 1.34 1.18 1.32
Trinidad--------------------- .89 - -
Composite------------------ 1.92(2) 1.58(2) 1.37
Crude Oil and Condensate ($/Bbl)
United States---------------- $ 16.96 $ 18.29 $ 19.24
Canada----------------------- 14.63 16.80 17.58
Trinidad--------------------- 14.36 - -
Composite------------------ 16.37 17.90 18.78
Natural Gas Liquids ($/Bbl)
United States---------------- $ 13.85 $ 11.56 $ 10.79
Canada----------------------- 9.46 10.05 12.48
Trinidad--------------------- - - -
Composite------------------ 11.12 10.69 11.64
LEASE AND WELL EXPENSES ($/MCFE)
United States---------------- $ .18 $ .20 $ .23
Canada----------------------- .48 .50 .57
Trinidad--------------------- 1.46 - -
Composite------------------ .21 .22 .25
(1) Includes 81.0 MMcf per day in 1993 and 27.6 MMcf per day in 1992 delivered
under the terms of a volumetric production payment agreement effective
October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of $1.57 per Mcf in 1993 and
$1.70 per Mcf in 1992 for the volumes described in note (1), net of
transportation costs.
5
OTHER NATURAL GAS MARKETING VOLUMES AND PRICES
The following table sets forth certain information regarding the Company's
volumes of natural gas delivered under other marketing and volumetric production
payment arrangements, and resulting average of sales prices and per unit
amortization of deferred revenues along with associated costs during each of the
three years in the period ended December 31, 1993. (See 'Marketing' for a
discussion of other natural gas marketing arrangements and agreements).
YEAR ENDED DECEMBER 31,
1993 1992 1991
Volumes (MMcf per day)--------------- 293.4(1) 254.9(1) 237.2
Average Gross Revenue ($/Mcf)-------- $ 2.57(2) $ 2.62(2) $ 2.63
Associated Costs ($/Mcf)(4)---------- 2.32(3) 1.99(3) 1.75
Margin ($/Mcf)----------------------- $ 0.25 $ 0.63 $ 0.88
(1) Includes 81.0 MMcf per day in 1993 and 27.6 MMcf per day in 1992 delivered
under the terms of volumetric production payment and exchange agreements
effective October 1, 1992, as amended.
(2) Includes per unit deferred revenue amortization for the volumes detailed
in note (1) at an equivalent of $2.50 per Mcf ($2.40 per million British
thermal units) in 1993 and $2.51 per Mcf ($2.40 per million British
thermal units) in 1992.
(3) Includes an average value of $2.20 per Mcf in 1993 and $2.37 per Mcf in
1992, including average equivalent wellhead value, any applicable
transportation costs and exchange differentials, for the volumes detailed
in note (1).
(4) Including transportation and exchange differentials.
COMPETITION
The Company actively competes for reserve acquisitions and exploration
leases, licenses and concessions, frequently against companies with
substantially larger financial and other resources. To the extent the Company's
exploration budget is lower than that of certain of its competitors, the Company
may be disadvantaged in effectively competing for certain reserves, leases,
licenses and concessions. Competitive factors include price, contract terms, and
quality of service, including pipeline connection times and distribution
efficiencies. In addition, the Company faces competition from other producers
and suppliers, including competition from Canadian natural gas.
REGULATION
DOMESTIC REGULATION OF NATURAL GAS AND CRUDE OIL PRODUCTION. Natural gas
and crude oil production operations are subject to various types of regulation,
including regulation in the United States by state and federal agencies.
Domestic legislation affecting the oil and gas industry is under constant
review for amendment or expansion. Also, numerous departments and agencies, both
federal and state, are authorized by statute to issue and have issued rules and
regulations which, among other things, require permits for the drilling of
wells, regulate the spacing of wells, prevent the waste of natural gas and crude
oil resources through proration, require drilling bonds and regulate
environmental and safety matters. The regulatory burden on the oil and gas
industry increases its cost of doing business and, consequently, affects its
profitability.
A substantial portion of the Company's oil and gas leases in the Big Piney
area and in the Gulf of Mexico, as well as some in other areas, are granted by
the federal government and administered by the Bureau of Land Management (the
'BLM') and the Minerals Management Service (the 'MMS') federal agencies.
Operations conducted by the Company on federal oil and gas leases must comply
with numerous statutory and regulatory restrictions. Certain operations must be
conducted pursuant to appropriate permits issued by the BLM and the MMS.
6
Sales of crude oil, condensate and natural gas liquids by the Company are
made at unregulated market prices.
The transportation and sale for resale of natural gas in interstate commerce
are regulated pursuant to the Natural Gas Act of 1938 (the 'NGA') and the
Natural Gas Policy Act of 1978 (the 'NGPA'). These statutes are administered by
the Federal Energy Regulatory Commission (the 'FERC'). Effective January 1,
1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas
prices for all 'first sales' of natural gas, which includes all sales by the
Company of its own production. Consequently, sales of the Company's natural gas
currently may be made at market prices, subject to applicable contract
provisions.
Regulation of natural gas importation is administered primarily by the
Department of Energy's Office of Fossil Energy (the 'DOE/FE'), pursuant to the
NGA. The NGA provides that any party seeking to import natural gas must first
seek DOE/FE authorization, which authorization may be granted, modified or
denied in accordance with the public interest. The Energy Policy Act of 1992
amended the NGA's public interest standard with respect to imports from and
exports to certain countries, such as Canada, to deem imports from and exports
to such countries to be in the public interest, and require such import/export
applications to be granted without delay. In addition, the Energy Policy Act
amended the NGPA to treat natural gas imported from Canada as 'first sales' of
natural gas under Section 3 of the NGPA, thus allowing such imported natural gas
to be sold for resale without certificate authorization from the FERC.
Additionally, the National Energy Board of Canada has dramatically revised its
natural gas export policies to permit large volumes of Canadian natural gas to
compete with natural gas produced in the U.S. for the U.S. spot market.
Additional natural gas pipeline capacity from Canada to the U.S. has been built
and other such construction proposals are pending approval. While the impact on
the Company of this change is uncertain, it is possible that it will increase
competition in the markets in which the Company sells natural gas. For example,
Canadian natural gas competes directly with natural gas produced from the
Company's Big Piney area for customers located in the Pacific Northwest region
of the United States.
Since 1985, the FERC has endeavored to make natural gas transportation more
accessible to gas buyers and sellers on an open and non-discriminatory basis.
These efforts have significantly altered the marketing and pricing of natural
gas. The FERC's latest action in this area is Order No. 636, issued in April
1992, which mandates a fundamental restructuring of interstate pipeline sales
and transportation services. Order No. 636 requires interstate natural gas
pipelines to 'unbundle' or segregate the sales, transportation, storage, and
other components of their existing city-gate sales service, and to separately
state the rates for each unbundled service. Under Order No. 636, unbundled
pipeline sales can be made only in the production areas. Order No. 636 also
requires interstate pipelines to assign capacity rights they have on upstream
pipelines to such pipelines' former sales customers and provides for the
recovery by interstate pipelines of costs associated with the transition from
providing bundled sales services to providing unbundled transportation and
storage services. The purpose of Order No. 636 is to further enhance competition
in the natural gas industry by assuring the comparability of pipeline sales
service and services offered by a pipelines' competitors. Various aspects of
Order No. 636 were challenged, including alleged shifts of costs between
pipeline customer groups and the continuing reliability of unbundled services.
In two subsequent orders on rehearing of Order No. 636, namely Order Nos. 636-A
and 636-B, the FERC modified the original order in response to these and other
concerns. As of early February 1994, the FERC had issued final orders accepting
most pipelines' Order No. 636 compliance filings. Numerous parties have filed
petitions for court review of Order Nos. 636, 636-A and 636-B, as well as orders
in individual pipeline restructuring proceedings. Upon such judicial review,
these orders may be reversed in whole or in part. Order No. 636 does not
directly regulate the Company's activities, but has had and will have an
indirect effect because of its broad scope. With Order No. 636 only partially
implemented and subject to court review, it is difficult to predict with
precision its effects. In many instances,
7
however, Order No. 636 has substantially reduced or brought to an end interstate
pipelines' traditional role as wholesalers of natural gas in favor of providing
only storage and transportation services. Order No. 636 has also created
substantial uncertainty with respect to the marketing and transportation of
natural gas. In spite of this uncertainty, Order No. 636 may enhance the
Company's ability to market and transport its natural gas production.
In December 1992, the FERC issued Order No. 547, governing the issuance of
blanket marketer sales certificates to all natural gas sellers other than
interstate pipelines. The order eliminates the need for natural gas producers
and marketers to seek specific authorization under Section 7 of the NGA from the
FERC to make sales of natural gas, such as imported natural gas and natural gas
purchased from interstate pipelines. Instead, effective January 7, 1993, these
natural gas sellers, by operation of the order, will be issued blanket
certificates of public convenience and necessity allowing them to make
jurisdictional natural gas sales for resale at negotiated rates without seeking
specific FERC authorization. For marketers affiliated with interstate pipelines,
Order No. 547 becomes effective for sales involving each affiliated pipeline as
that pipeline complies with Order No. 636. The FERC intends Order No. 547, in
tandem with Order No. 636, to foster a competitive market for natural gas by
giving natural gas purchasers access to multiple supply sources at market-driven
prices. The Company, as a natural gas producer, is covered by Order No. 547 and
stands to benefit from the opportunity to market natural gas more freely under
the blanket certificate as well as from the potential improvement in access to
multiple natural gas purchasers.
In December 1993, the FERC issued Order No. 497-E, which modified in some
respects the standards of conduct, record keeping and reporting requirements and
other measures that govern relationships between interstate pipelines and their
marketing affiliates. Order No. 497-E narrowed the contemporaneous disclosure
standard of conduct and the reporting requirements, while at the same time
possibly expanding the class of pipeline and marketing affiliate employees to
whom the standards of conduct apply. Order No. 497-E also extended until June
1994 the sunset date of the reporting requirements. The FERC simultaneously
issued a notice of proposed rulemaking to revise these reporting requirements,
which would establish new rules to go into effect before the June 1994 sunset
date. Order No. 497 does not directly regulate the Company's activities,
although a substantial portion of the Company's natural gas production is sold
to or transported by interstate pipeline affiliates which are subject to the
Order. The Company's activities may therefore be indirectly affected by these
regulations.
The Company owns, directly or indirectly, certain natural gas pipelines that
it believes meet the traditional tests the FERC has used to establish a
pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA.
State regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, non-discriminatory take requirements,
but does not generally entail rate regulation. Natural gas gathering may receive
greater regulatory scrutiny at both the state and federal levels as the pipeline
restructuring under Order No. 636 is implemented. For example, the State of
Oklahoma recently enacted a prohibition against discriminatory gathering rates.
In certain recent cases, the FERC has asserted ancillary NGA jurisdiction over
gathering activities of interstate pipelines and their affiliates. In addition,
the FERC recently convened a conference to consider issues relating to gathering
services performed by interstate pipelines or their affiliates. The FERC intends
to use information obtained to reevaluate the appropriateness of its traditional
gathering criteria in light of Order No. 636 and to establish consistent
policies for gathering rates and services for both interstate pipelines and
their affiliates. It is not possible at this time to predict the outcome of this
proceeding although it could ultimately affect access to and gathering rates for
interstate gathering services. The Company's gathering operations could be
adversely affected should they be subject in the future to the application of
state or federal regulation of rates and services.
The Company cannot predict the effect that any of the aforementioned orders
or the challenges to such orders will ultimately have on the Company's
operations. Additional proposals and proceedings that might affect the natural
gas industry are pending before Congress, the FERC and the courts.
8
The Company cannot predict when or whether any such proposals or proceedings may
become effective. It should also be noted that the natural gas industry
historically has been very heavily regulated; therefore, there is no assurance
that the less regulated approach currently being pursued by the FERC will
continue indefinitely. Thus, the Company cannot predict the ultimate outcome or
durability of the unbundled regulatory regime mandated by Order No. 636.
ENVIRONMENTAL REGULATION. Various federal, state and local laws and
regulations covering the discharge of materials into the environment, or
otherwise relating to the protection of the environment, may affect the
Company's operations and costs as a result of their effect on natural gas and
crude oil exploration, development and production operations. It is not
anticipated that the Company will be required in the near future to expend
amounts that are material in relation to its total exploration and development
expenditure program by reason of environmental laws and regulations, but
inasmuch as such laws and regulations are frequently changed, the Company is
unable to predict the ultimate cost of compliance.
The Company has been named as a potentially responsible party in one
Comprehensive Environmental Response Compensation and Liability Act proceeding.
However, management does not believe that any potential assessment resulting
from such proceeding will have a materially adverse effect on the financial
condition or results of operations of the Company.
CANADIAN REGULATION. In Canada, the petroleum industry operates under
Federal, provincial and municipal legislation and regulations governing land
tenure, royalties, production rates, pricing, environmental protection, exports
and other matters. The price of natural gas and crude oil in Canada has been
deregulated and is now determined by market conditions and negotiations between
buyers and sellers.
Various matters relating to the transportation and export of natural gas
continue to be subject to regulation by both provincial and Federal agencies;
however, the North American Free Trade Agreement has reduced the risk of
altering cross-border commercial transactions.
Canadian governmental regulations may have a material effect on the economic
parameters for engaging in oil and gas activities in Canada and may have a
material effect on the advisability of investments in Canadian oil and gas
drilling activities. The Company is monitoring political, regulatory and
economic developments in Canada.
RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP.
OWNERSHIP OF COMMON STOCK. Enron Corp. owns 80% of the outstanding shares
of common stock of the Company and, through its ability to elect all directors
of the Company, has the ability to control all matters relating to the
management of the Company, including any determination with respect to
acquisition or disposition of Company assets, future issuance of common stock or
other securities of the Company and any dividends payable on the common stock.
Enron Corp. also has the ability to control the Company's exploration,
development, acquisition and operating expenditure plans. If Enron Corp. should
sell a substantial amount of the common stock of the Company that it owns, such
action could adversely affect the prevailing market price for the common stock
and could impair the Company's ability to raise capital through the sale of its
equity securities. In addition, a sale by Enron Corp. of any common stock owned
by Enron Corp. would cause Enron Corp.'s ownership interest in the Company to
fall below 80% with the result that (i) the Company would cease to be included
in the consolidated federal income tax return filed by Enron Corp. and (ii) the
tax allocation agreement between the Company and Enron Corp. described below
would terminate. The Company has granted certain registration rights to Enron
Corp. with respect to the common stock owned by Enron Corp. (See 'Contractual
Arrangements' below). There is no agreement between Enron Corp. and any other
party, including the Company, that would prevent Enron Corp. from acquiring
additional shares of common stock of the Company.
9
CONTRACTUAL ARRANGEMENTS. The Company entered into a Services Agreement
(the 'Services Agreement') with Enron Corp. effective January 1989, pursuant to
which Enron Corp. provided various services, such as maintenance of certain
employee benefit plans, provision of telecommunications and computer services,
lease of office space and the provision of purchasing and operating services and
certain other corporate staff and support services. Such services historically
have been supplied to the Company by Enron Corp., and the Services Agreement
provided for the further delivery of such services substantially identical in
nature and quality to those services previously provided. The Company agreed to
a fixed rate for the rental of office space and to reimburse Enron Corp. for all
other direct costs incurred in rendering services to the Company under the
contract and to pay Enron Corp. for allocated indirect costs incurred in
rendering such services up to an annual maximum of $8 million, such cap to be
increased for inflation and certain changes in the Company's allocation bases
with the increase limited to a maximum of 10% per year. The Services Agreement
was for an initial term of five years through December 1993. Effective January
1, 1994, the Company and Enron Corp. entered into a new services agreement (the
'New Services Agreement') pursuant to which Enron Corp. will, among other
things, provide for the Company similar services substantially identical in
nature and quality to those provided under terms of the previous agreement. The
Company has agreed to pay and to reimburse Enron Corp. on bases essentially
consistent with those included in the previous agreement, except that allocated
indirect costs are subject to an annual maximum of $6.7 million for the year
1994 with any increase in such maximum for subsequent years not to exceed 7.5%
per year. The New Services Agreement is for an initial term of five years
through December 1998 and will continue thereafter until terminated by either
party.
The Company is included in the consolidated federal income tax return filed
by Enron Corp. as the common parent for itself and its subsidiaries and
affiliated companies, excluding any foreign subsidiaries. Consistent therewith
and pursuant to a Tax Allocation Agreement (the 'Tax Agreement') between the
Company, the Company's subsidiaries and Enron Corp., either Enron Corp. will pay
to the Company and each subsidiary an amount equal to the tax benefit realized
in the Enron Corp. consolidated federal income tax return resulting from the
utilization of the Company's or the subsidiary's net operating losses and/or tax
credits, or the Company and each subsidiary will pay to Enron Corp. an amount
equal to the federal income tax computed on its separate taxable income less the
tax benefits associated with any net operating losses and/or tax credits
generated by the Company or the subsidiary which are utilized in the Enron Corp.
consolidated return. Enron Corp. will pay the Company and each subsidiary for
the tax benefits associated with their net operating losses and tax credits
utilized in the Enron Corp. consolidated return, provided that a tax benefit was
realized except as discussed in the following paragraph, even if such benefits
could not have been used by the Company or the subsidiary on a separately filed
tax return.
In 1991, the Company and Enron Corp. modified the Tax Agreement to provide
that, through 1992, the Company will realize the benefit of certain tight gas
sand federal income tax credits available to the Company on a stand alone basis.
The Company has also entered into an agreement with Enron Corp. providing for
the Company to be paid for all realizable benefits associated with tight gas
sand federal income tax credits concurrent with tax reporting and settlement for
the periods in which they are generated. (See 'Other Matters Tight Gas Sand Tax
Credits (Section 29) and Severance Tax Exemption').
The Tax Agreement applies to the Company and each of its subsidiaries for
all years in which the Company or any of its subsidiaries are or were included
in the Enron Corp. consolidated return.
To the extent a state or other taxing jurisdiction requires or permits a
consolidated, combined, or unitary tax return to be filed and such return
includes the Company or any of its subsidiaries, the principles expressed with
respect to consolidated federal income tax allocation shall apply.
Pursuant to the terms of a Stock Restriction and Registration Agreement with
Enron Corp., the Company has agreed that upon the request of Enron Corp. (or
certain assignees), the Company will register under the Securities Act of 1933
and applicable state securities laws the sale of the Company
10
common stock owned by Enron Corp. which Enron Corp. has requested to be
registered. The Company's obligation is subject to certain limitations relating
to a minimum amount of common stock required for registration, the timing of
registration and other similar matters. The Company is obligated to pay all
expenses incidental to such registration, excluding underwriters' discounts and
commissions and certain legal fees and expenses.
CONFLICTS OF INTEREST. The nature of the respective businesses of the
Company and Enron Corp. and its affiliates is such as to potentially give rise
to conflicts of interest between the two companies. Conflicts could arise, for
example, with respect to transactions involving purchases, sales and
transportation of natural gas and other business dealings between the Company
and Enron Corp. and its affiliates, potential acquisitions of businesses or oil
and gas properties, the issuance of additional shares of voting securities, the
election of directors or the payment of dividends by the Company.
Enron Corp. has advised the Company that it does not currently intend to
engage in the exploration for and/or development and production of natural gas
and crude oil except through its ownership of common stock of the Company.
However, circumstances may arise that would cause Enron Corp. to engage in the
exploration for and/or development and production of natural gas and crude oil
in competition with the Company. For example, opportunities might arise which
would require financial resources greater than those available to the Company or
which are located in areas or countries in which the Company does not intend to
operate. Also, Enron Corp. might acquire a competing oil and gas business as
part of a larger acquisition. In addition, as part of Enron Corp.'s strategy of
securing supplies of natural gas, Enron Corp. may from time to time acquire
producing properties, and thereafter engage in exploration, development and
production activities with respect to such properties. Such acquisition,
exploration, development and production activities may directly or indirectly
compete with the Company's business. Thus, there can be no assurances that Enron
Corp. will not engage in the natural gas and crude oil exploration, development
and production business in competition with the Company.
The Company and Enron Corp. and its affiliates have in the past entered into
significant intercompany transactions and agreements incident to their
respective businesses, and the Company and Enron Corp. and its affiliates may be
expected to enter into material transactions and agreements from time to time in
the future. Such transactions and agreements have related to, among other
things, the purchase and sale of natural gas, the financing of exploration and
development efforts by the Company, and the provision of certain corporate
services. (See 'Marketing' and the Consolidated Financial Statements and notes
thereto). The Company believes that its existing transactions and agreements
with Enron Corp. and its affiliates have been at least as favorable to the
Company as could be obtained from third parties, and the Company intends that
the terms of any future transactions and agreements between the Company and
Enron Corp. and its affiliates will be at least as favorable to the Company as
could be obtained from third parties.
OTHER MATTERS
ENERGY PRICES. Since the Company is primarily a natural gas company, it is
more significantly impacted by changes in natural gas prices than in the prices
for crude oil, condensate and natural gas liquids. During recent periods,
natural gas has been priced significantly below parity with crude oil,
condensate and natural gas liquids based on the energy equivalency of, and
differences in transportation and processing costs associated with, the
respective products. This imbalance in parity has been primarily driven by,
among other things, a supply of domestic natural gas volumes in excess of demand
requirements. The Company is unable to predict when this supply imbalance may
resolve due to the significant impacts of factors such as general economic
conditions, weather and other international energy supplies over which the
Company has no control. However, during the latter part of 1993, certain shifts
in the pricing structure for natural gas and crude oil and condensate suggest
that the significance of the lack of parity between natural gas and crude oil
and condensate pricing may be beginning to lessen.
11
Natural gas prices have fluctuated, at times rather dramatically, during the
last three years. These fluctuations have resulted in an overall increase in
average wellhead natural gas prices realized by the Company of 15% from 1991 to
1992 and 22% from 1992 to 1993. Due to the many uncertainties associated with
the world political environment, the availabilities of other world wide energy
supplies and the relative competitive relationships of the various energy
sources in the view of the consumers, the Company is unable to predict what
changes may occur in natural gas prices in the future.
Crude oil and condensate prices also have fluctuated, at times rather
dramatically, during the last three years. These fluctuations have resulted in
an overall decline in average wellhead crude and condensate prices realized by
the Company of 5% from 1991 to 1992 and 9% from 1992 to 1993. Due to the many
uncertainties associated with the world political environment, the
availabilities of other world wide energy supplies and the relative competitive
relationships of the various energy sources in the view of the consumers, the
Company is unable to predict what changes may occur in crude oil and condensate
prices in the future.
TIGHT GAS SAND TAX CREDITS (SECTION 29) AND SEVERANCE TAX
EXEMPTION. Federal tax law provides a tax credit for production of certain
fuels produced from nonconventional sources (including natural gas produced from
tight formations), subject to a number of limitations. Fuels qualifying for the
credit must be produced from a well drilled or a facility placed in service
before January 1, 1993, and must be sold before January 1, 2003.
The credit, which is currently approximately $.52 per MMBtu of natural gas,
is computed by reference to the price of crude oil, and is phased out as the
price of crude oil exceeds $23.50 in 1980 dollars (adjusted for inflation) with
complete phaseout if such price exceeds $29.50 in 1980 dollars (similarly
adjusted). Under this formula, the commencement of phaseout would be triggered
if the average price for crude oil rose above approximately $43 per barrel in
current dollars. Significant benefits from the tax credit are accruing to the
Company since a portion (and in some cases a substantial portion) of the
Company's natural gas production from new wells drilled after November 5, 1990,
and before January 1, 1993, on the Company's leases in several of the Company's
significant producing areas qualify for this tax credit.
Certain natural gas production from wells spudded or completed after May 24,
1989 and before September 1, 1996 in tight formations in Texas qualifies for a
ten-year exemption, ending August 31, 2001, from Texas severance taxes, subject
to certain limitations.
OTHER. All of the Company's oil and gas activities are subject to the risks
normally incident to the exploration for and development and production of
natural gas and crude oil, including blowouts, cratering and fires, each of
which could result in damage to life and property. Offshore operations are
subject to usual marine perils, including hurricanes and other adverse weather
conditions, and governmental regulations as well as interruption or termination
by governmental authorities based on environmental and other considerations. In
accordance with customary industry practices, insurance is maintained by the
Company against some, but not all, of the risks. Losses and liabilities arising
from such events could reduce revenues and increase costs to the Company to the
extent not covered by insurance.
The Company's overseas operations are subject to certain risks, including
expropriation of assets, risks of increases in taxes and government royalties,
renegotiation of contracts with foreign governments, political instability,
payment delays, limits on allowable levels of production and current exchange
and repatriation losses, as well as changes in laws and policies governing
operations of overseas-based companies generally.
12
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
The current executive officers of the Company and their names and ages are
as follows:
NAME AGE POSITION
Forrest E. Hoglund----------------- 60 Chairman of the Board, President and
Chief Executive Officer; Director
Joe Michael McKinney--------------- 54 President-International Operations
Mark G. Papa----------------------- 47 President-North American Operations
George E. Uthlaut------------------ 60 Senior Vice President-Operations
Walter C. Wilson------------------- 51 Senior Vice President and Chief
Financial Officer
Ben B. Boyd------------------------ 52 Vice President and Controller
Dennis M. Ulak--------------------- 40 Vice President and General Counsel
Forrest E. Hoglund joined the Company as Chairman of the Board, Chief
Executive Officer and Director in September 1987. Since May 1990, he has also
served as President of the Company. Mr. Hoglund was a director of USX
Corporation from February 1986 until September 1987. He joined Texas Oil & Gas
Corp. ('TXO') in 1977 as president, was named Chief Operating Officer in 1979,
Chief Executive Officer in 1982, and served TXO in those capacities until
September 1987. Mr. Hoglund is also a director of Texas Commerce Bancshares,
Inc.
Joe Michael McKinney has been President-International Operations since
February 1994 with responsibilities for all exploration, drilling, production
and engineering activities for the Company's international ventures outside
North America. Mr. McKinney joined Enron Exploration Company, a wholly-owned
subsidiary of the Company, in December 1991 as Senior Vice President of
Operations and was elected President and Chief Operating Officer of Enron
Exploration Company in April 1993, a capacity in which he continues to serve.
Prior to joining the Company, Mr. McKinney held operations management positions
with Union Texas Petroleum Company, The Superior Oil Company and Exxon Company,
USA.
Mark G. Papa has been President-North American Operations since February
1994. From May 1986 through January 1994, Mr. Papa served as Senior Vice
President-Operations. Mr. Papa joined Belco Petroleum Corporation, a predecessor
of the Company, in 1981 as Division Production Coordinator and served as Senior
Vice President-Drilling and Production, BelNorth Petroleum Corporation from May
1984 until May 1986.
George E. Uthlaut has been Senior Vice President-Operations of the Company
since November 1987. Mr. Uthlaut was previously employed by Exxon Corporation
(and affiliates) for 29 years in a number of managerial and technical positions.
His last position was Headquarters Operations Manager, Production Department,
Exxon Company, USA.
Walter C. Wilson has been Senior Vice President and Chief Financial Officer
since May 1991. Mr. Wilson joined the Company in November 1987 as Vice President
and Controller and was named Senior Vice President-Finance in October 1988.
Prior to joining the Company Mr. Wilson held financial management positions with
Exxon Company, USA for 16 years and The Superior Oil Company for 4 years.
Ben B. Boyd has been Vice President and Controller since March 1991. Mr.
Boyd joined the Company in March 1989 as Director of Accounting and was named
Controller in May 1990. Prior to joining the Company, Mr. Boyd held financial
management positions with DeNovo Oil & Gas, Inc., Scurlock Oil Company and
Coopers & Lybrand.
Dennis M. Ulak has been Vice President and General Counsel since March 1992.
Mr. Ulak joined the Company in March 1987 as Senior Counsel and was named
Assistant General Counsel in
13
August 1990. Prior to joining the Company, Mr. Ulak held various legal positions
with Enron Corp. and Northern Natural Gas Company.
ITEM 2. PROPERTIES
OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES
RESERVE INFORMATION. For estimates of the Company's net proved and proved
developed reserves of natural gas and liquids, including crude oil, condensate
and natural gas liquids, see 'Supplemental Information to Consolidated Financial
Statements.'
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures, including many factors beyond the control of the producer. The
reserve data set forth in Supplemental Information to Consolidated Financial
Statements represent only estimates. Reserve engineering is a subjective process
of estimating underground accumulations of natural gas and liquids, including
crude oil, condensate and natural gas liquids, that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the amount
and quality of available data and of engineering and geological interpretation
and judgment. As a result, estimates of different engineers normally vary. In
addition, results of drilling, testing and production subsequent to the date of
an estimate may justify revision of such estimate. Accordingly, reserve
estimates are often different from the quantities ultimately recovered. The
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they were based.
In general, the volume of production from oil and gas properties owned by
the Company declines as reserves are depleted. Except to the extent the Company
acquires additional properties containing proved reserves or conducts successful
exploration and development activities, or both, the proved reserves of the
Company will decline as reserves are produced. Volumes generated from future
activities of the Company are therefore highly dependent upon the level of
success in acquiring or finding additional reserves and the costs incurred in
doing so.
The Company's estimates of reserves filed with other federal agencies agree
with the information set forth in Supplemental Information to Consolidated
Financial Statements.
14
ACREAGE. The following table summarizes the Company's developed and
undeveloped acreage at December 31, 1993. Excluded is acreage in which the
Company's interest is limited to owned royalty, overriding royalty and other
similar interests.
DEVELOPED UNDEVELOPED TOTAL
GROSS NET GROSS NET GROSS NET
United States
Texas---------------------------- 411,223 306,705 252,543 229,348 663,766 536,053
Federal Offshore----------------- 199,053 96,719 280,701 253,233 479,754 349,952
Wyoming-------------------------- 164,836 109,528 211,414 159,676 376,250 269,204
Oklahoma------------------------- 102,495 58,724 45,640 39,136 148,135 97,860
Utah----------------------------- 58,540 47,032 32,772 27,435 91,312 74,467
New Mexico----------------------- 85,294 38,227 58,846 32,713 144,140 70,940
Kansas--------------------------- 4,148 4,048 27,402 26,029 31,550 30,077
California----------------------- 13,235 11,680 12,897 12,182 26,132 23,862
Colorado------------------------- 10,111 1,490 29,715 14,318 39,826 15,808
Mississippi---------------------- 1,940 1,852 7,876 7,178 9,816 9,030
Montana-------------------------- 1,301 1,169 8,250 6,437 9,551 7,606
North Dakota--------------------- 2,395 961 1,509 1,228 3,904 2,189
Louisiana------------------------ 946 797 1,445 712 2,391 1,509
Other---------------------------- 163 132 861 841 1,024 973
Total------------------------ 1,055,680 679,064 971,871 810,466 2,027,551 1,489,530
Canada
Alberta-------------------------- 329,677 145,804 227,872 141,602 557,549 287,406
Saskatchewan--------------------- 140,929 121,791 179,818 179,818 320,747 301,609
Manitoba------------------------- 11,611 9,661 3,260 2,900 14,871 12,561
British Columbia----------------- 656 164 - - 656 164
Total Canada----------------- 482,873 277,420 410,950 324,320 893,823 601,740
Other International
Australia------------------------ - - 9,600,000 9,600,000 9,600,000 9,600,000
Trinidad------------------------- 975 926 78,076 74,172 79,051 75,098
United Kingdom------------------- - - 199,855 49,964 199,855 49,964
Total Other International---- 975 926 9,877,931 9,724,136 9,878,906 9,725,062
Total-------------------- 1,539,528 957,410 11,260,752 10,858,922 12,800,280 11,816,332
PRODUCING WELL SUMMARY. The following table reflects the Company's
ownership in gas wells in 316 fields and oil wells in 75 fields located in
Texas, offshore Texas and Louisiana in the Gulf of Mexico, Oklahoma, New Mexico,
Utah, Wyoming, California and various other states, Canada and Trinidad at
December 31, 1993. Gross oil and gas wells include 229 with multiple
completions.
PRODUCTIVE WELLS
GROSS NET
Gas---------------------------------- 4,674 3,170
Oil---------------------------------- 884 527
Total---------------------------- 5,558 3,697
15
DRILLING AND ACQUISITION ACTIVITIES. During the years ended December 31,
1993, 1992 and 1991 the Company spent approximately $430.1, $395.7 and $254.8
million, respectively, for exploratory and development drilling and acquisition
of leases and producing properties. The Company drilled, participated in the
drilling of or acquired wells as set out in the table below for the periods
indicated:
YEAR ENDED DECEMBER 31,
1993 1992 1991
GROSS NET GROSS NET GROSS NET
Development Wells Completed
Domestic
Gas-------------------------- 352 279.00 484 399.06 193 165.25
Oil-------------------------- 45 19.01 19 10.80 6 3.89
Dry-------------------------- 59 46.83 64 56.12 29 21.43
Total---------------------- 456 344.84 567 465.98 228 190.57
International
Gas-------------------------- 227 190.10 2 2.00 8 5.33
Oil-------------------------- 4 3.50 13 11.70 9 8.50
Dry-------------------------- 11 7.60 5 4.05 4 2.86
Total---------------------- 242 201.20 20 17.75 21 16.69
Total Development---------------- 698 546.04 587 483.73 249 207.26
Exploratory Wells Completed
Domestic
Gas-------------------------- 14 10.03 11 8.72 14 10.54
Oil-------------------------- 3 2.50 1 .40 1 1.00
Dry-------------------------- 32 22.08 16 13.42 13 10.38
Total---------------------- 49 34.61 28 22.54 28 21.92
International
Gas-------------------------- 14 11.40 7 5.75 3 1.83
Oil-------------------------- 2 .90 4 3.69 1 .39
Dry-------------------------- 10 7.35 4 2.85 9 5.48
Total---------------------- 26 19.65 15 12.29 13 7.70
Total Exploratory---------------- 75 54.26 43 34.83 41 29.62
Total---------------------- 773 600.30 630 518.56 290 236.88
Wells in Progress at end of
period----------------------------- 82 61.09 82 60.75 32 21.60
Total---------------------- 855 661.39 712 579.31 322 258.48
Wells Acquired
Gas------------------------------ 44 26.44* 641 597.29* 100 70.10*
Oil------------------------------ - 12.80* 28 25.80* 5 4.10*
Total---------------------- 44 39.24 669 623.09 105 74.20
* Includes the acquisition of additional interests in certain wells in which
the Company previously held an interest.
All of the Company's drilling activities are conducted on a contract basis
with independent drilling contractors. The Company owns no drilling equipment.
16
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries and related companies are named defendants
in numerous lawsuits and named parties in numerous governmental proceedings
arising in the ordinary course of business. While the outcome of lawsuits or
other proceedings against the Company cannot be predicted with certainty,
management does not expect these matters to have a material adverse effect on
the financial condition or results of operations of the Company. TransAmerican
Natural Gas Corporation ('TransAmerican') has filed a petition against the
Company and Enron Corp. alleging breach of contract, tortious interference with
contract, misappropriation of trade secrets and violation of state antitrust
laws. The petition, as amended, seeks actual damages of $100 million plus
exemplary damages of $300 million. The Company has answered the petition and is
actively defending the matter; in addition, the Company has filed counterclaims
against TransAmerican and a third-party claim against its sole shareholder, John
R. Stanley, alleging fraud, negligent misrepresentation and breach of state
antitrust laws. Trial, originally set for February 7, 1994, is now set for
September 12, 1994. Although no assurances can be given, the Company believes
that the claims made by TransAmerican are totally without merit, that the
ultimate resolution of the matter will not have a materially adverse effect on
its financial condition or results of operations, and that such ultimate
resolution could result in a recovery to the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
fourth quarter of 1993.
17
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS
The following table sets forth, for the periods indicated, the high and low
sale prices per share for the common stock, as reported on the New York Stock
Exchange Composite Tape, and the amount of cash dividends paid per share.
PRICE RANGE CASH
HIGH LOW DIVIDENDS
1991
First Quarter-------------------- 22.25 16.25 .05
Second Quarter------------------- 21.50 18.00 .05
Third Quarter-------------------- 24.63 17.63 .05
Fourth Quarter------------------- 25.13 19.25 .05
1992
First Quarter-------------------- 21.88 16.63 .05
Second Quarter------------------- 27.25 20.50 .05
Third Quarter-------------------- 35.88 25.38 .05
Fourth Quarter------------------- 34.38 27.50 .05
1993
First Quarter-------------------- 40.63 26.75 .06
Second Quarter------------------- 45.00 35.75 .06
Third Quarter-------------------- 53.63 39.75 .06
Fourth Quarter------------------- 54.00 34.13 .06
As of March 1, 1994, there were approximately 500 record holders of the
Company's common stock, including individual participants in security position
listings. There are an estimated 5,600 beneficial owners of the Company's common
stock, including shares held in street name.
Following the initial public offering and sale of its common stock in
October 1989, the Company paid quarterly dividends of $0.05 per share beginning
with an initial dividend paid in January 1990 with respect to the fourth quarter
of 1989. Beginning in January 1993 with respect to the fourth quarter of 1992,
the Company has paid quarterly dividends of $0.06 per share. The Company
currently intends to continue to pay quarterly cash dividends on its outstanding
shares of common stock. However, the determination of the amount of future cash
dividends, if any, to be declared and paid will depend upon, among other things,
the financial condition, funds from operations, level of exploration and
development expenditure opportunities and future business prospects of the
Company.
18
ITEM 6. SELECTED FINANCIAL DATA
YEAR ENDED DECEMBER 31,
1993 1992 1991 1990 1989
(RESTATED)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
STATEMENT OF INCOME (LOSS) DATA:
Net operating revenues--------------- $ 567,702 $ 452,989 $ 387,605 $ 371,335 $ 289,416
Operating expenses
Lease and well------------------- 59,344 49,406 49,922 43,806 39,889
Exploration---------------------- 36,921 33,278 31,470 35,031 23,988
Dry hole------------------------- 18,355 10,764 14,698 12,986 10,212
Impairment of unproved oil and
gas properties----------------- 20,467 15,136 12,791 20,571 10,832
Depreciation, depletion and
amortization------------------- 249,704 179,839 160,885 155,877 134,313
General and administrative------- 45,274 36,648 36,216 38,254 40,240
Taxes other than income---------- 35,396 28,346 18,222 22,966 23,760
Other---------------------------- - - - - (117)
Total------------------------ 465,461 353,417 324,204 329,491 283,117
Operating income--------------------- 102,241 99,572 63,401 41,844 6,299
Other income------------------------- 19,953 2,561 11,768 29,649 18,065
Interest expense (net of interest
capitalized)----------------------- 9,921 22,289 29,500 36,879 33,849
Income (loss) before income taxes---- 112,273 79,844 45,669 34,614 (9,485)
Income tax benefit (1)--------------- (25,752)(2) (17,736) (2,247)(3) (10,854) (3,384)
Net income (loss)-------------------- $ 138,025 $ 97,580 $ 47,916(3) $ 45,468 $ (6,101)
Earnings (loss) per share of common
stock------------------------------ $ 1.73 $ 1.26 $ .63(3) $ .60 $ (.09)
Average number of common shares------ 79,983 77,267 75,900 75,900 66,838
AT DECEMBER 31,
1993 1992 1991 1990 1989
(RESTATED) (RESTATED)
BALANCE SHEET DATA (IN
THOUSANDS):
Oil and gas properties - net--------- $ 1,546,045 $ 1,468,011 $ 1,339,666 $ 1,305,136 $ 1,249,657
Total assets------------------------- 1,811,162 1,731,012 1,455,608 1,417,939 1,365,819
Long-term debt
Affiliate-------------------------- - - (4) 132,836 277,918 401,092(5)
Other------------------------------ 153,000 150,000(4) 289,556 140,442 -
Shareholders' equity----------------- 933,073 826,986(3)(4) 643,185(3) 610,042 582,321(5)
(1) Includes benefits of approximately $65 million, $43 million and $17
million in 1993, 1992 and 1991, respectively, relating to tight gas sand
federal income tax credits and $7 million and $25 million associated with
the utilization of a net operating loss carryforward in 1991 and 1990,
respectively.
(2) Includes a benefit of $12 million from the reduction of the Company's
accumulated deferred federal income tax liability partially offset by an
approximate $7 million predominantly non-cash charge primarily to adjust
the Company's accumulated deferred federal income tax liability for the
increase in the corporate federal income tax rate from 34% to 35%.
(3) The Company adopted Statement of Financial Accounting Standards (SFAS) No.
109 - 'Accounting for Income Taxes' effective January 1, 1993 and applied
the provisions of the statement retroactively. As a result, the previously
reported Income tax benefit and Net income (loss) for 1991 were restated
to $2.2 million and $47.9 million ($.63 per share), respectively, from
$9.2 million and $54.9 million ($.72 per share), respectively, a reduction
to both of $7.0
19
million. The Net income (loss) for 1992 and 1993 were not affected by the
restatement. The Company's consolidated balance sheets at December 31,
1992 and 1991 were also restated to reflect the increase to deferred
income taxes payable of $7.0 million and the corresponding decrease to
retained earnings of an equal amount.
(4) In August 1992, the Company completed the sale of an additional 4,100,000
shares of common stock resulting in aggregate net proceeds to the Company
of approximately $112 million used primarily to repay long-term debt. In
September 1992, the Company completed the sale of a volumetric production
payment, resulting in net proceeds of approximately $327 million used to
repay long-term debt and for other general corporate purposes.
(5) The Company completed an initial public offering of 11,500,000 shares of
common stock in October 1989, resulting in aggregate net proceeds to the
Company of approximately $202 million which were used to repay advances
from affiliates.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following review of operations for each of the three years in the period
ended December 31, 1993 should be read in conjunction with the consolidated
financial statements of the Company and notes thereto beginning with page F-1.
RESULTS OF OPERATIONS
NET OPERATING REVENUES. Volume and price statistics for the specified years
were as follows:
YEAR ENDED DECEMBER 31,
1993 1992 1991
Wellhead Volumes
Natural Gas (MMcf per day)------- 709.3(1) 563.6(1) 490.6
Crude Oil and Condensate (MBbl
per day)----------------------- 8.9 8.5 8.2
Natural Gas Liquids (MBbl per
day)--------------------------- 0.6 0.7 0.6
Wellhead Average Prices
Natural Gas ($/Mcf)-------------- $ 1.92(2) $ 1.58(2) $ 1.37
Crude Oil and Condensate
($/Bbl)------------------------ 16.37 17.90 18.78
Natural Gas Liquids ($/Bbl)------ 11.12 10.69 11.64
Other Natural Gas Marketing
Volumes (MMcf per day)----------- 293.4(1) 254.9(1) 237.2
Average Gross Revenue ($/Mcf)---- $ 2.57(3) $ 2.62(3) $ 2.63
Associated Costs ($/Mcf) (5)----- 2.32(4) 1.99(4) 1.75
Margin ($/Mcf)------------------- $ 0.25 $ 0.63 $ 0.88
(1) Includes 81.0 MMcf per day in 1993 and 27.6 MMcf per day in 1992 delivered
under the terms of volumetric production payment and exchange agreements
effective October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of $1.57 per Mcf in 1993 and
$1.70 per Mcf in 1992 for the volumes detailed in note (1), net of
transportation costs.
(3) Includes per unit deferred revenue amortization for the volumes detailed
in note (1) at an equivalent of $2.50 per Mcf ($2.40 per million British
thermal units) in 1993 and $2.51 per Mcf ($2.40 per million British
thermal units) in 1992.
(4) Includes an average value of $2.20 per Mcf in 1993 and $2.37 per Mcf in
1992, including average equivalent wellhead value, any applicable
transportation costs and exchange differentials, for the volumes detailed
in note (1).
(5) Including transportation and exchange differentials.
20
During 1993, net operating revenues increased to $568 million, up $115
million as compared to 1992.
Average wellhead natural gas volumes increased approximately 26% compared to
1992 primarily reflecting the effects of exploration and development activities
relating to tight gas sand formations. Wellhead natural gas delivered volumes
were curtailed less during portions of 1993 than for the comparable periods in
1992 due to the significant increases realized in wellhead natural gas prices in
1993. Average wellhead natural gas prices were up approximately 22% in 1993 over
those received in 1992, adding approximately $87 million to net operating
revenues. Increases in wellhead natural gas volumes in 1993 added $83 million to
net operating revenues compared to 1992. Average wellhead crude oil and
condensate prices in 1993 were down 9% compared to 1992, reducing net operating
revenues by $5 million. Increases in wellhead crude oil and condensate volumes
in 1993 added approximately $2 million to net operating revenues compared to
1992.
Other marketing activities associated with sales and purchases of natural
gas, natural gas price swap transactions, other commodity price hedging of
natural gas and crude oil and condensate prices utilizing futures market
transactions, and margins relating to the volumetric production payment added $8
million to net operating revenues during 1993. This decrease of $54 million from
1992 primarily results from shrinking margins associated with sales under
long-term fixed price contracts and amortization of volumetric production
payment deferred revenue due to increases in market responsive natural gas
prices associated with volumes supplying these dispositions and losses on
natural gas commodity price hedging activities utilizing NYMEX commodity market
transactions. The average associated costs of natural gas marketing, price swap
and volumetric production payment transactions, including, where appropriate,
average wellhead value, transportation costs and exchange differentials,
increased $.33 per Mcf. Related other natural gas marketing volumes increased
15%.
The net reduction in benefits from these other marketing activities, a
substantial portion of which serve as hedges of commodity price risks for a
portion of wellhead deliveries, are more than offset by an increase in revenues
associated with market responsive price increases for wellhead deliveries, as
noted above. The $18 million hedging loss in 1993 associated with forward sales
of natural gas using the NYMEX futures market reflects the effects of
transactions sold over a period of time that turned out to be a continually
increasing natural gas pricing period. If the stronger market responsive pricing
environment continues, the incremental benefits realized by the Company in prior
years from these other marketing activities will continue to be reduced.
However, in such circumstances the Company will continue to realize more
significant benefits from the improved pricing related to wellhead deliveries.
(See Note 2 to Consolidated Financial Statements).
During 1992, net operating revenues increased to $453 million, up $65
million as compared to 1991.
Average wellhead natural gas volumes increased approximately 15% compared to
1991 primarily reflecting the effects of exploration and development activities
relating to tight gas sand formations. Although exploration and development
efforts resulted in deliverability increases in certain core areas, the
potential earnings and cash flow benefits were mitigated by voluntary
curtailments during 1992. Wellhead natural gas delivered volumes were
voluntarily curtailed by as much as 25% of deliverability during portions of the
year due to lower than acceptable prices. Average wellhead natural gas prices
were up approximately 15% and average wellhead crude oil and condensate prices
were down 5% compared to 1991. The increase in average wellhead natural gas
price received by the Company increased net operating revenues by approximately
$38 million. The increase in wellhead natural gas volumes added approximately
$43 million to net operating revenues. Increases in wellhead crude oil and
condensate delivered volumes added $2 million to net operating revenues. A
decrease in the average wellhead crude oil and condensate price decreased net
operating revenues by $3 million.
21
Other marketing activities associated with sales and purchases of natural
gas, natural gas price swap transactions, natural gas and crude oil commodity
price hedging utilizing futures market transactions and margins relating to the
volumetric production payment added $63 million to net operating revenues during
1992, a decrease of $17 million from 1991. Other natural gas marketing volumes
increased 7%. The average associated costs of supplying these commitments,
including average equivalent wellhead value, transportation costs and exchange
differentials, increased $.24 per Mcf.
OPERATING EXPENSES. During 1993, total operating expenses of $465 million
were $112 million higher than the $353 million incurred in 1992. Lease and well
expenses increased approximately $10 million primarily due to expanded domestic
and international operations. Exploration expenses increased approximately $4
million primarily due to increased exploration activities in North America. Dry
hole expenses increased by almost $8 million and lease impairments were $5
million higher than in 1992. An unsuccessful domestic deep well added nearly $4
million to dry hole expenses and a related $3 million to lease impairments in
1993. Dry hole expenses also reflect the impact of increased drilling activity
outside North America. Depreciation, depletion and amortization ('DD&A') expense
increased $70 million to $250 million reflecting an increase in production
volumes and an average DD&A rate increase from $.79 per Mcfe in 1992 to $.89 per
Mcfe for 1993. The DD&A rate increase is primarily due, as expected, to factors
associated with the tight gas sands drilling program which costs are being more
than offset by benefits realized in the form of tight gas sand federal income
tax credits and certain state severance tax exemptions. General and
administrative expenses increased almost $9 million to $45 million primarily
reflecting cost reductions included in 1992 related to changes associated with
certain employee compensation plans and overall higher costs in 1993 due to an
expansion of domestic and international operations. Taxes other than income
increased $7 million primarily due to increased production volumes and revenues
in 1993, partially offset by continuing benefits associated with certain state
severance tax exemptions allowed on high cost natural gas sales and a $3 million
reduction of state franchise taxes resulting from refunds of prior year payments
received in 1993.
Total per unit operating costs for lease and well expense, DD&A, general and
administrative expense, interest expense, and taxes other than income increased
$.03 per Mcfe, averaging $1.43 per Mcfe during 1993 compared to $1.40 per Mcfe
for 1992. The total increase was associated with DD&A expense which was up $.10
per Mcfe as noted above being partially offset by a reduction of $.07 Mcfe in
all other costs.
During 1992, operating expenses increased $29 million to $353 million as
compared to 1991. However, cost per Mcfe, including those associated with
exploration expenditures, declined $.08 to $1.56 per Mcfe in 1992. Lease and
well expenses remained essentially flat compared to 1991. However, lease and
well expense per Mcfe declined $.03 per Mcfe to $.22 per Mcfe in 1992. Per unit
operating cost reductions reflect the effects of a continuing focus on
controlling operating costs in all areas of Company operations and benefits
realized from the sale of properties which required higher maintenance costs
along with increasing volumes which tend to reduce per unit impacts of costs
that are more fixed in nature. Exploration expenses of $33 million increased $2
million over 1991 due to certain exploration activities in new international
areas of interest. Dry hole expenses of $11 million decreased $4 million from
1991 due to decreased drilling activity in areas outside of North America
partially mitigated by increased domestic drilling activities. Impairment of
unproved oil and gas properties increased approximately $2 million to $15
million primarily reflecting certain costs associated with the decision to
discontinue exploration activities in certain areas outside of North America,
including Egypt, Indonesia and Syria in addition to reflecting the effects of
accelerated relinquishments of certain domestic acreage holdings. DD&A expense
increased $19 million to $180 million primarily reflecting increased production
mitigated by a decline in the average DD&A rate from $.81 per Mcfe in 1991 to
$.79 per Mcfe in 1992. The reduction in DD&A rates per Mcfe reflects the effects
of a continuing focus on adding reserves with low finding costs along with the
benefits of selling certain properties with higher than average cost bases.
General and administrative
22
expenses increased $1 million to $37 million primarily reflecting the effects of
expanded operations. Taxes other than income increased $10 million to $28
million due to increased production volumes and revenues in 1992, increases in
certain ad valorem and state franchise taxes and earnings benefits associated
with the refund of certain state natural gas severance taxes in 1991 resulting
from overpayments in prior years. This increase was mitigated by Texas severance
tax exemptions for certain high cost gas production during 1992.
OTHER INCOME. Other income for 1993 of $20 million reflects an increase of
$17 million from the $3 million recorded for 1992. Other income for 1993
includes $13 million in gains on sales of oil and gas properties, an increase of
$7 million over 1992, $4 million in interest income associated with the
investment of funds temporarily surplus to the Company (See Note 3 to
Consolidated Financial Statements) and $4 million associated with settlements
related to the termination of certain long-term natural gas contracts.
Other income in 1992 was $3 million compared to $12 million in 1991. Other
income in 1992 included $6 million in gains on sales of oil and gas properties
compared to $15 million in 1991.
INTEREST EXPENSE. Net interest expense decreased $12 million, or 55%, to
$10 million in 1993 as compared to 1992 reflecting the repayment of a
substantial portion of the Company's long-term debt in 1992 with proceeds from
the sale of common stock in August 1992 and the sale of a volumetric production
payment in September 1992. The estimated fair value of outstanding interest rate
swap agreements at December 31, 1993 was a negative $3.3 million based upon
termination values obtained from third parties. (See Note 12 to Consolidated
Financial Statements).
Net interest expense decreased $7 million, or 24%, to $22 million in 1992 as
compared to 1991, reflecting a restructuring of debt in early 1991 and lower
interest rates. Using interest rate swap agreements with third parties effective
in January 1992, the Company fixed short-term borrowing costs for the year for
the equivalent of $225 million of its floating rate obligations. In addition,
two of the interest rate swap agreements in notional amounts totalling $75
million were for a two-year period extending through 1993. Effective January 1,
1993, Enron Corp. assumed the Company's remaining obligations under these swap
agreements.
INCOME TAXES. Income tax benefit in 1993 includes a benefit of
approximately $65 million associated with tight gas sand federal income tax
credit utilization, an approximate $7 million predominantly one-time non-cash
charge recorded in the third quarter of 1993 primarily to adjust the Company's
accumulated deferred federal income tax liability for the increase in the
corporate federal income tax rate from 34% to 35% and a $12 million benefit from
the reduction of the Company's accumulated deferred federal income tax liability
resulting from a year end reevaluation of deferred tax liability requirements.
The Company adopted SFAS No. 109 effective January 1, 1993 and applied the
provisions of the statement retroactively. As a result, the previously reported
income tax benefit and net income for 1991 were restated with a reduction to
both of $7 million. Net income for 1992 and 1993 was not affected by the
restatement. The Company's consolidated balance sheets at December 31, 1992 and
1991 were also restated to reflect the increase to deferred income taxes payable
of $7 million and the corresponding decrease to retained earnings of an equal
amount.
Income tax benefit in 1992 includes a benefit of approximately $43 million
associated with tight gas sand federal income tax credit utilization and $2.8
million primarily related to investment tax credit, tight gas sand federal
income tax credit and percentage depletion utilization based on actual returns
as filed and settlements on audit of tax returns of predecessor companies for
the years 1984 through 1985.
Income tax benefit in 1991 includes a benefit of approximately $17 million
associated with tight gas sand federal income tax credit utilization and $10.5
million related to utilization of net operating loss carryforwards, foreign tax
credit and settlements on audit of tax returns of predecessor companies for tax
years 1980 through 1983.
23
CAPITAL RESOURCES AND LIQUIDITY
CASH FLOW. The primary sources of cash for the Company during the
three-year period ended December 31, 1993 included funds generated from
operations, the sale of common stock, the sale of a volumetric production
payment and proceeds from the sale of certain oil and gas properties. Primary
cash outflows included funds used in operations, exploration and development
expenditures, dividends, and the repayment of debt.
Discretionary cash flow, a frequently used measure of performance for
exploration and production companies, is generally derived by adjusting net
income to eliminate the effects of depreciation, depletion and amortization,
impairment of unproved oil and gas properties, deferred taxes, property sales
net of tax, certain other miscellaneous non-cash amounts, except for
amortization of deferred revenue, and exploration and dry hole expenses. In the
case of the Company, the elimination of revenues associated with the
amortization of deferred revenues created by the sale by the Company of a
volumetric production payment is reflected in investing cash flows. The Company
generated discretionary cash flow of approximately $487 million in 1993, $320
million in 1992 and $252 million in 1991. The 1993 amount includes $50 million
associated with a federal income tax refund resulting from the settlement of an
audit of federal income taxes paid in prior years.
Net operating cash flows were approximately $480 million in 1993, $306
million in 1992 and $242 million in 1991. Increased 1993 net operating cash
flows were primarily due to increased net operating revenues and a decrease in
provision for current taxes resulting from both increased tight gas sand federal
income tax credit utilization and proceeds from the receipt of a refund on
settlement of an audit of federal income taxes paid in prior years. Increased
1992 net operating cash flows were primarily due to increased net operating
revenues and an increase in current tax benefits as a result of tight gas sand
federal income tax credit utilization.
SALE OF CERTAIN PROPERTIES. In 1993, the Company received proceeds of $42
million from the sale of certain producing and non-producing oil and gas
properties. Taxable gains resulting from these sales generated federal income
taxes of $8 million, leaving net proceeds of $34 million. During 1992, the
Company received proceeds of $33 million from the sale of certain producing and
non-producing oil and gas properties. Taxable gains resulting from these sales
generated federal income taxes of $8 million, leaving net proceeds of $25
million. In 1991, the Company received proceeds of $23 million from the sale of
certain producing and non-producing oil and gas properties. Taxable gains
resulting from these sales generated income taxes of $5 million, leaving net
proceeds of $18 million.
SALE OF COMMON STOCK. In August 1992, the Company completed the sale of 4.1
million shares of common stock resulting in aggregate net proceeds to the
Company of approximately $112 million used primarily to repay long-term debt.
Enron Corp. retained ownership of 80% of the Company.
SALE OF VOLUMETRIC PRODUCTION PAYMENT. In September 1992, the Company sold
a volumetric production payment for $326.8 million to a limited partnership.
(See 'Business - Marketing - Other Marketing' and Note 4 to Consolidated
Financial Statements). Under the terms of the production payment agreements, the
Company conveyed a real property interest in approximately 124 bcfe (136
trillion British thermal units) of natural gas and other hydrocarbons in the Big
Piney area of Wyoming to the purchaser. Effective October 1, 1993, the
agreements were amended providing for the extension of the original term of the
volumetric production payment through March 31, 1999 and including a revised
schedule of daily quantities of hydrocarbons to be delivered which is
approximately one-half of the original schedule. The revised schedule will total
approximately 89.1 Bcfe (97.8 trillion British thermal units) versus
approximately 87.9 Bcfe (96.4 trillion British thermal units) remaining to be
delivered under the original agreement. Daily quantities of hydrocarbons no
longer required to be delivered under the revised schedule during the period
from October 1, 1993 through June 30, 1996 are available for sale by the
Company. The Company retains responsibility for its working interest share of
the cost of operations. A portion of the proceeds of the sale was used to repay
a portion of the Company's long-term debt, with surplus funds advanced to Enron
Corp. under a promissory note which facilitates the deposit of funds temporarily
surplus to the Company. In
24
accordance with generally accepted accounting principles, the Company accounted
for the proceeds received in the transaction as deferred revenue which is being
amortized into revenue and income as natural gas and other hydrocarbons are
produced and delivered to the purchaser during the term, as revised, of the
volumetric production payment thereby matching those revenues with the
depreciation of asset values which remained on the balance sheet following the
sale and the operating expenses incurred for which the Company retained
responsibility. The Company expects the above transaction, as amended, to have
minimal impact on future earnings. However, cash made available by the sale of
the volumetric production payment has provided considerable financial
flexibility for the pursuit of investment alternatives.
EXPLORATION AND DEVELOPMENT EXPENDITURES. The table below sets out
components of actual exploration and development expenditures for the years
ended December 31, 1993, 1992 and 1991, along with those budgeted for the year
1994.
ACTUAL BUDGETED
EXPENDITURE CATEGORY 1993 1992 1991 1994
(IN MILLIONS)
Capital
Drilling and Facilities--------- $ 331.0 $ 259.9 $ 149.3 $ 360.0
Leasehold Acquisitions---------- 29.1 23.0 12.6 20.0
Producing Property
Acquisitions-------------------- 9.2 65.2 42.4 4.0
Capitalized Interest and
Other------------------------- 13.7 14.3 7.4 10.0
Total----------------------- 383.0 362.4 211.7 394.0
Exploration Expenses---------------- 55.3 44.0 46.1 56.0
Total------------------------------- $ 438.3 $ 406.4 $ 257.8 $ 450.0
Exploration and development expenditures in 1993 increased to $438 million,
an 8% increase, as compared to the $406 million expended in 1992. The increase
was attributable to increased domestic drilling activity with reduced emphasis
on development drilling expenditures associated with tight gas sand formations.
The Company also implemented its first development program outside of North
America. During 1992 and 1993, the Company had a platform set, production
facilities in place and natural gas flowing from the Kiskadee field offshore the
southeast coast of Trinidad.
Exploration and development expenditures increased $149 million, or 58%, in
1992 compared to 1991. The increase was primarily attributable to increased
development drilling expenditures associated with tight gas sand activities and
the acquisition in December 1992 of approximately $40 million of producing
properties in Canada. (See 'Business - Exploration and Production' for
additional information detailing the specific geographic locations of the
Company's drilling programs and 'Outlook' below for a discussion related to 1994
exploration and development expenditure plans).
FINANCING. The Company's long-term debt-to-total-capital ratio was 14% and
15% as of December 31, 1993 and 1992, respectively. The Company has entered into
an agreement with Enron Corp. pursuant to which the Company may borrow funds
from Enron Corp. at a representative market rate of interest on a revolving
basis. During 1993, there were no funds borrowed by the Company under this
agreement. Under a promissory note effective January 1, 1993 at a fixed interest
rate of 7%, the Company advances funds temporarily surplus to the Company to
Enron Corp. for investment purposes. Daily outstanding balances of funds
advanced to Enron Corp. under the note averaged $60 million during 1993 with a
balance of $97 million outstanding at December 31, 1993. There were no balances
outstanding at December 31, 1993 under a commercial paper program initiated in
1990. The proceeds from the commercial paper program outstanding from time to
time are used to fund current transactions. During 1993, total long-term debt
increased $3 million to $153 million as a result of $33 million of new
borrowings related to certain international drilling
25
activities partially offset by $30 million classified as current maturities.
(See Note 3 to the Consolidated Financial Statements). The estimated fair value
of the Company's long-term debt, including current maturities of $30 million, at
December 31, 1993 was $192 million based upon quoted market prices and, where
such prices were not available, upon interest rates currently available to the
Company at year end. (See Note 12 to the Consolidated Financial Statements).
OUTLOOK. While the wellhead natural gas price environment was, on average,
stronger during the year 1993, there continues to exist a good deal of
uncertainty as to the direction of future natural gas price trends. However,
recent experiences continue to suggest a possible converging of the overall
supply/demand relationship reflecting, at least partially, the significantly
reduced level of drilling activity during recent years. Management remains
confident that continually increasing recognition of natural gas as a more
environmentally friendly source of energy along with the availability of
significant domestically sourced supplies will result in further increases in
demand and a strengthening of the overall natural gas market over time. Being
primarily a natural gas producer, the Company is more significantly impacted by
changes in natural gas prices than by changes in crude oil and condensate
prices. (See 'Business - Other Matters - Energy Prices'). Based on the portion
of the Company's anticipated natural gas volumes for which prices have not, in
effect, been hedged using the futures market and long-term marketing contracts,
the Company's net income and cash flow sensitivity to changing natural gas
prices is approximately $7 million for each $.10 per Mcf change in average
wellhead natural gas prices. Using various commodity price hedging mechanisms,
the Company has, in effect, locked in prices for an average of about two-thirds
of its anticipated wellhead natural gas volumes for the year 1994. This level of
hedging may change during the remainder of 1994 and will change in future years.
Other factors representing positive impacts that are more certain continue
to hold good potential for the Company in future periods. While the drilling
qualification period for the tight gas sand federal income tax credit expired as
of December 31, 1992, the Company has continued in 1993, and should continue in
the future, to realize significant benefits associated with production from
wells drilled during the qualifying period as it will be eligible for the
federal income tax credit through the year 2002. However, all other factors
remaining equal, the annual benefit, which was $65 million in 1993 and estimated
to be approximately $40 million for 1994, is expected to continue to decline in
future periods as production from the qualified wells declines. The drilling
qualification period for a certain state severance tax exemption available on
certain high cost natural gas revenues continues through the latter part of
1996. Consequently, new qualifying production will be added prospectively to
that qualified at year end 1993. (See 'Business - Other Matters - Tight Gas Sand
Tax Credit (Section 29) and Severance Tax Exemption'). Other natural gas
marketing activities are also expected to continue to contribute meaningfully to
financial results. However, the Company completed a fairly significant
restructure of its other natural gas marketing portfolio during 1992 with the
sale of a volumetric production payment of approximately 124 Bcfe (136 trillion
British thermal units) for $326.8 million that was subsequently revised in 1993
(See 'Business - Marketing - Other Marketing' and Note 4 to Consolidated
Financial Statements) and elimination of most delivery obligations under four
long-term fixed price marketing contracts. The proceeds from the sale of the
volumetric production payment added substantially to the financial flexibility
of the Company supporting future development while the combined effect of all
elements of the restructuring on net income has not been, and will not in the
future be, significant. These factors are expected to contribute significantly
to earnings, cash flow, and the ability of the Company to pursue the
continuation of an active exploration, development and selective acquisition
program.
The Company will continue to focus development and certain exploration
expenditures in its core and other major producing areas, and include limited
but meaningful exploratory exposure in areas outside of North America. (See
'Business - Exploration and Production' for additional information detailing the
specific geographic locations of the related drilling programs). Early-in-year
activity will be managed within an annual expected expenditure level of
approximately $450 million. This early-in-year planning will address the
continuing uncertainty with regard to the future of the
26
natural gas price environment and will be structured to maintain the flexibility
necessary under the Company strategy of funding exploration, development and
acquisition activities primarily from available internally generated cash flow.
Expenditure plans for 1994 will continue to be focused toward certain areas that
were not addressed as actively in the recent past due to the increased emphasis
on tight gas sand drilling opportunities during 1991 and 1992 that were
completed in early 1993. The Company will also be continuing expenditures in new
areas outside of North America, primarily for additional development operations
in Trinidad, possible new development operations in other countries, such as
those currently being pursued in India, and the continued evaluation of coalbed
methane recovery potential in France, Australia, China and certain other
countries.
The level of exploration and development expenditures may vary in 1994 and
will vary in future periods depending on energy market conditions and other
related economic factors. Based upon existing economic and market conditions,
the Company believes net operating cash flow and available financing
alternatives in 1994 will be sufficient to fund its net investing cash
requirements for the year. However, the Company has significant flexibility with
respect to its financing alternatives and adjustment of its exploration and
development expenditure plans as circumstances warrant. There are no material
continuing commitments associated with expenditure plans.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set forth
in the 'Index to Financial Statements' on page F-1.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item regarding directors is set forth in
the Proxy Statement under the caption entitled 'Election of Directors', and is
incorporated herein by reference.
See list of 'Current Executive Officers of the Registrant' in Part I located
elsewhere herein.
There are no family relationships among the officers listed, and there are
no arrangements or understandings pursuant to which any of them were elected as
officers. Officers are appointed or elected annually by the Board of Directors
at its first meeting following the Annual Meeting of Shareholders, each to hold
office until the corresponding meeting of the Board in the next year or until a
successor shall have been elected, appointed or shall have qualified.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is set forth in the Proxy Statement
under the caption 'Compensation of Directors and Executive Officers', and is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is set forth in the Proxy Statement
under the captions 'Election of Directors' and 'Compensation of Directors and
Executive Officers', and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is set forth in the Proxy Statement
under the caption 'Compensation Committee Interlocks and Insider Participation',
and is incorporated herein by reference.
27
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See 'Index to Financial Statements' set forth on page F-1.
(A)(3) EXHIBITS
See pages E-1 through E-3 for a listing of the exhibits.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the Company during the last quarter of
1993.
28
INDEX TO FINANCIAL STATEMENTS
ENRON OIL & GAS COMPANY
PAGE
Consolidated Financial
Statements:
Management's Responsibility for Financial Reporting---- F-2
Report of Independent Public Accountants--------------- F-3
Consolidated Statements of Income for Each of the
Three Years in the Period Ended December 31, 1993---- F-4
Consolidated Balance Sheets -December 31, 1993
and 1992--------------------------------------------- F-5
Consolidated Statements of Shareholders' Equity
for Each of the Three Years in the Period
Ended December 31, 1993------------------------------ F-6
Consolidated Statements of Cash Flows for Each
of the Three Years in the Period Ended
December 31, 1993------------------------------------ F-7
Notes to Consolidated Financial Statements------------- F-8
Supplemental Information to Consolidated Financial
Statements----------------------------------------------- F-21
Financial Statement Schedules:
Schedule V -Property, Plant and Equipment----------- S-1
Schedule VI -Accumulated Depreciation, Depletion
and Amortization of Property, Plant and Equipment---- S-2
Schedule VIII -Valuation and Qualifying Accounts
and Reserves----------------------------------------- S-3
Schedule X -Supplemental Income Statement
Information------------------------------------------- S-4
Other financial statement schedules have been omitted because
they are inapplicable or the information required therein is
included elsewhere in the consolidated financial statements
or notes thereto.
F-1
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The following consolidated financial statements of Enron Oil & Gas Company
and its subsidiaries were prepared by management which is responsible for their
integrity, objectivity and fair presentation. The statements have been prepared
in conformity with generally accepted accounting principles and accordingly
include some amounts that are based on the best estimates and judgements of
management.
Arthur Andersen & Co., independent public accountants, was engaged to audit
the consolidated financial statements of Enron Oil & Gas Company and its
subsidiaries and issue a report thereon. In the conduct of the audit, Arthur
Andersen & Co. was given unrestricted access to all financial records and
related data including minutes of all meetings of shareholders, the Board of
Directors and committees of the Board. Management believes that all
representations made to Arthur Andersen & Co. during the audit were valid and
appropriate. Their audits of the years presented included developing an overall
understanding of the Company's accounting systems, procedures and internal
controls, and conducting tests and other auditing procedures sufficient to
support their opinion on the financial statements. The report of Arthur Andersen
& Co. appears on the following page.
The system of internal controls of Enron Oil & Gas Company and its
subsidiaries is designed to provide reasonable assurance as to the reliability
of financial records as represented in published interim and annual financial
statements and for the protection of assets. This system includes, but is not
limited to, written policies and guidelines including a published code for the
conduct of business affairs, the careful selection and training of qualified
personnel, and a documented organizational structure outlining the separation of
responsibilities among management representatives and staff groups, augmented by
a strong program of internal audit.
The adequacy of financial controls of Enron Oil & Gas Company and its
subsidiaries and the accounting principles employed in financial reporting by
the Company are under the general oversight of the Audit Committee of the Board
of Directors. No member of this committee is an officer or employee of the
Company. Both the independent public accountants and internal/contract auditors
have direct access to the Audit Committee and meet with the committee from time
to time to discuss accounting, auditing and financial reporting matters.
Effective January 1, 1994, Arthur Andersen & Co. has been contracted to provide
operational and internal control audit services previously handled by the
internal audit staff of the Company.
It should be recognized that there are inherent limitations to the
effectiveness of any system of internal control, including the possibility of
human error and circumvention or override. Accordingly, even an effective system
can provide only reasonable assurance with respect to the preparation of
reliable financial statements. Furthermore, the effectiveness of an internal
control system can change with circumstances.
It is management's opinion that, considering the criteria for effective
internal control over financial reporting which consists of interrelated
components including the control environment, risk-assessment process, control
activities, information and communication systems, and monitoring, the Company
maintained an effective system of internal control over the preparation of
published interim and annual financial statements for all periods presented.
BEN B. BOYD WALTER C. WILSON FORREST E. HOGLUND
Vice President and Senior Vice President and Chairman of the Board,
Controller Chief Financial Officer President and Chief
Executive Officer
Houston, Texas
March 18, 1994
F-2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Enron Oil & Gas Company:
We have audited the accompanying consolidated balance sheets of Enron Oil &
Gas Company (a Delaware corporation) and subsidiaries as of December 31, 1993
and 1992, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1993. These financial statements and the schedules referred to below are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Enron Oil &
Gas Company and subsidiaries as of December 31, 1993 and 1992, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1993, in conformity with generally accepted accounting
principles.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedules listed
in the index to financial statements are presented for purposes of complying
with the Securities and Exchange Commission's rules and are not part of the
basic financial statements. These schedules have been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly state in all material respects the financial data required to be
set forth therein in relation to the basic financial statements taken as a
whole.
As explained in Note 7 to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 109, 'Accounting for
Income Taxes', effective January 1, 1993, and applied the provisions of the
statement retroactively.
ARTHUR ANDERSEN & CO.
Houston, Texas
February 18, 1994 (except with
respect to the matters discussed in
Note 3, as to which the date is
March 11, 1994)
F-3
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
1993 1992 1991
(RESTATED)
NET OPERATING REVENUES
Natural Gas
Associated Companies----------- $ 279,921 $ 280,501 $ 275,362
Trade-------------------------- 225,241 108,487 46,241
Crude Oil, Condensate and Natural
Gas Liquids
Associated Companies----------- 38,953 38,775 41,237
Trade-------------------------- 16,881 20,152 21,599
Other----------------------------- 6,706 5,074 3,166
Total-------------------- 567,702 452,989 387,605
OPERATING EXPENSES
Lease and Well-------------------- 59,344 49,406 49,922
Exploration----------------------- 36,921 33,278 31,470
Dry Hole-------------------------- 18,355 10,764 14,698
Impairment of Unproved Oil and Gas
Properties---------------------- 20,467 15,136 12,791
Depreciation, Depletion and
Amortization-------------------- 249,704 179,839 160,885
General and Administrative-------- 45,274 36,648 36,216
Taxes Other Than Income----------- 35,396 28,346 18,222
Total-------------------- 465,461 353,417 324,204
OPERATING INCOME--------------------- 102,241 99,572 63,401
OTHER INCOME------------------------- 19,953 2,561 11,768
INCOME BEFORE INTEREST EXPENSE AND
TAXES------------------------------ 122,194 102,133 75,169
INTEREST EXPENSE
Incurred
Affiliate---------------------- - 1,747 9,503
Other-------------------------- 15,378 24,122 24,479
Capitalized----------------------- (5,457) (3,580) (4,482)
Net Interest Expense----------- 9,921 22,289 29,500
INCOME BEFORE INCOME TAXES----------- 112,273 79,844 45,669
INCOME TAX BENEFIT------------------- (25,752) (17,736) (2,247)
NET INCOME--------------------------- $ 138,025 $ 97,580 $ 47,916
EARNINGS PER SHARE OF COMMON
STOCK------------------------------ $ 1.73 $ 1.26 $ .63
AVERAGE NUMBER OF COMMON SHARES------ 79,983 77,267 75,900
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
ENRON OIL & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
AT DECEMBER 31,
1993 1992
(RESTATED)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents--------- $ 103,129 $ 132,618
Accounts Receivable
Associated Companies----------- 59,143 50,838
Trade-------------------------- 66,109 50,832
Inventories----------------------- 14,082 9,534
Other----------------------------- 6,962 3,190
Total----------------------- 249,425 247,012
OIL AND GAS PROPERTIES (Successful
Efforts Method)---------------------- 2,772,220 2,475,371
Less: Accumulated Depreciation,
Depletion and Amortization------ 1,226,175 1,007,360
Net Oil and Gas
Properties---------------- 1,546,045 1,468,011
OTHER ASSETS------------------------- 15,692 15,989
TOTAL ASSETS------------------------- $ 1,811,162 $ 1,731,012
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable
Associated Companies----------- $ 13,250 $ 1,889
Trade-------------------------- 143,542 128,695
Accrued Taxes Payable------------- 17,354 9,911
Dividends Payable----------------- 4,795 4,800
Current Maturities of Long-Term
Debt---------------------------- 30,000 -
Other----------------------------- 8,989 49,421
Total----------------------- 217,930 194,716
LONG-TERM DEBT----------------------- 153,000 150,000
OTHER LIABILITIES-------------------- 9,477 8,972
DEFERRED INCOME TAXES---------------- 270,154 248,943
DEFERRED REVENUE--------------------- 227,528 301,395
COMMITMENTS AND CONTINGENCIES
(Note 8)
SHAREHOLDERS' EQUITY
Common Stock, No Par, 80,000,000
Shares Authorized and Issued---- 200,800 200,800
Additional Paid In Capital-------- 417,531 421,747
Cumulative Foreign Currency
Translation Adjustment---------- (6,855) (1,726)
Retained Earnings----------------- 324,995 206,165
Common Stock Held in Treasury,
80,000 shares------------------- (3,398) -
Total Shareholders'
Equity---------------------- 933,073 826,986
TOTAL LIABILITIES AND SHAREHOLDERS'
EQUITY----------------------------- $ 1,811,162 $ 1,731,012
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
CUMULATIVE
FOREIGN COMMON TOTAL
ADDITIONAL CURRENCY STOCK SHAREHOLD-
COMMON PAID IN TRANSLATION RETAINED HELD IN ERS'
STOCK CAPITAL ADJUSTMENT EARNINGS TREASURY EQUITY
(RESTATED)
Balance at December 31, 1990--------- $ 200,759 $ 310,504 $ 6,540 $ 92,239 $ - $ 610,042
Net Income, as Restated----------- - - - 47,916 - 47,916
Dividends Paid/Declared, $.20 Per
Share--------------------------- - - - (15,180) - (15,180)
Translation Adjustment------------ - - 407 - - 407
Balance at December 31, 1991--------- 200,759 310,504 6,947 124,975 - 643,185
Net Income------------------------ - - - 97,580 - 97,580
Shares Issued by Public Offering-- 41 111,820 - - - 111,861
Dividends Paid, $.05 Per Share in
April, July and October, and
Declared, $.06 in December------ - - - (16,390) - (16,390)
Translation Adjustment------------ - - (8,673) - - (8,673)
Treasury Stock Purchased---------- - - - - (1,827) (1,827)
Treasury Stock Issued Under Stock
Option Plan--------------------- - (577) - - 1,827 1,250
Balance at December 31, 1992--------- 200,800 421,747 (1,726) 206,165 - 826,986
Net Income----------------------- - - - 138,025 - 138,025
Dividends Paid/Declared, $.24 Per
Share-------------------------- - - - (19,195) - (19,195)
Translation Adjustment----------- - - (5,129) - - (5,129)
Treasury Stock Purchased--------- - - - - (16,698) (16,698)
Treasury Stock Issued Under Stock
Option Plan-------------------- - (4,216) - - 13,300 9,084
Balance at December 31, 1993--------- $ 200,800 $ 417,531 $ (6,855) $ 324,995 $ (3,398) $ 933,073
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
1993 1992 1991
CASH FLOWS FROM OPERATING ACTIVITIES (RESTATED)
Reconciliation of Net Income to
Net Operating Cash Inflows:
Net Income------------------------ $ 138,025 $ 97,580 $ 47,916
Items Not Requiring (Providing)
Cash
Depreciation, Depletion and
Amortization----------------- 249,704 179,839 160,885
Impairment of Unproved Oil and
Gas Properties--------------- 20,467 15,136 12,791
Deferred Income Taxes---------- 25,612 (17,917) (11,997)
Other, Net--------------------- 1,768 5,713 5,073
Exploration Expenses-------------- 36,921 33,278 31,470
Dry Hole Expenses----------------- 18,355 10,764 14,698
Gains On Sales of Oil and Gas
Properties---------------------- (13,318) (6,037) (14,983)
Other, Net------------------------ 1,242 (6,147) 614
Changes in Components of Working
Capital and Other Liabilities
Accounts Receivable------------ (24,586) (12,732) (821)
Inventories-------------------- (4,548) 3,687 (19)
Accounts Payable--------------- 26,208 46,327 381
Accrued Taxes Payable---------- 7,443 247 1,011
Other Liabilities-------------- 772 (2,886) (1,006)
Other, Net--------------------- (44,443) 33,784 3,839
Changes in Components of Working
Capital Associated with
Investing and Financing
Activities---------------------- 40,042 (74,232) (7,976)
NET OPERATING CASH INFLOWS----------- 479,664 306,404 241,876
INVESTING CASH FLOWS
Additions to Oil and Gas
Properties---------------------- (383,064) (362,403) (211,673)
Exploration Expenses-------------- (36,921) (33,278) (31,470)
Dry Hole Expenses----------------- (18,355) (10,764) (14,698)
Proceeds from Sale of
Properties---------------------- 41,815 33,412 22,827
Proceeds from Sale of Volumetric
Production Payment-------------- - 326,775 -
Amortization of Deferred
Revenue------------------------- (73,867) (25,380) -
Changes in Components of Working
Capital Associated with
Investing Activities------------ (37,256) 74,232 7,976
Other, Net------------------------ (4,905) (3,686) (3,020)
NET INVESTING CASH OUTFLOWS---------- (512,553) (1,092) (230,058)
FINANCING CASH FLOWS
Long-Term Debt
Affiliate---------------------- - (132,836) (145,082)
Other-------------------------- 33,000 (139,556) 149,114
Common Stock Issued--------------- - 111,861 -
Dividends Paid-------------------- (19,200) (15,385) (15,180)
Treasury Stock Purchased---------- (16,698) (1,827) -
Proceeds from Sales of Treasury
Stock--------------------------- 9,084 1,250 -
Other, Net------------------------ (2,786) - (466)
NET FINANCING CASH INFLOWS
(OUTFLOWS)------------------------- 3,400 (176,493) (11,614)
INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS------------------------ (29,489) 128,819 204
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR------------------ 132,618 3,799 3,595
CASH AND CASH EQUIVALENTS AT END OF
YEAR------------------------------- $ 103,129 $ 132,618 $ 3,799
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements of Enron
Oil & Gas Company (the 'Company'), 80% of the outstanding common stock of which
is owned by Enron Corp., include the accounts of all domestic and foreign
subsidiaries. All material intercompany accounts and transactions have been
eliminated. Certain reclassifications have been made to consolidated financial
statements for prior years to conform with the current presentation.
CASH EQUIVALENTS. The Company records as cash equivalents all highly liquid
short-term investments with maturities of three months or less. (See Note 3
'Long-Term Debt, Financing Arrangements with Enron Corp.')
OIL AND GAS OPERATIONS. The Company accounts for its natural gas and crude
oil exploration and production activities under the successful efforts method of
accounting.
Oil and gas lease acquisition costs are capitalized when incurred. Unproved
properties with significant acquisition costs are assessed quarterly on a
property-by-property basis and any impairment in value is recognized. Unproved
properties with acquisition costs that are not individually significant are
aggregated, and the portion of such costs estimated to be nonproductive, based
on historical experience, is amortized over the average holding period. If the
unproved properties are determined to be productive, the appropriate related
costs are transferred to proved oil and gas properties. Lease rentals are
expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling exploratory
wells, are charged to expense as incurred. The costs of drilling exploratory
wells are capitalized pending determination of whether they have discovered
proved commercial reserves. If proved commercial reserves are not discovered,
such drilling costs are expensed. The costs of all development wells and related
equipment used in the production of crude oil and natural gas are capitalized.
Depreciation, depletion and amortization of the cost of proved oil and gas
properties is calculated using the unit-of-production method. Estimated future
dismantlement, restoration and abandonment costs (classified as long-term
liabilities), net of salvage values, are taken into account. Certain other
assets are depreciated on a straight-line basis.
Inventories, consisting primarily of tubular goods and well equipment held
for use in the exploration for, and development and production of crude oil and
natural gas reserves, are carried at cost with selected adjustments made from
time to time to recognize changes in condition value.
Natural gas revenues are recorded to recognize that during the course of
normal production operations joint interest owners will, from time to time, take
more or less than their ultimate share of natural gas volumes from jointly owned
reservoirs. These volumetric imbalances are monitored over the life of the
reservoir to achieve balancing, or minimize imbalances, by the time reserves are
depleted. Final cash settlements are made, generally at the time a property is
depleted, under one of a variety of arrangements generally accepted by the
industry depending on the specific circumstances involved. The Company accrues
revenues associated with undertakes and defers revenues associated with
overtakes to recognize these potential ultimate imbalances.
ACCOUNTING FOR FUTURES CONTRACTS. Futures transactions are entered into as
hedges of commodity prices associated with the sales and purchases of natural
gas and crude oil, in order to mitigate the risk of market price fluctuations.
Changes in the market value of futures transactions entered into as hedges are
deferred until the gain or loss is recognized on the hedged transactions.
F-8
CAPITALIZED INTEREST COSTS. Certain interest costs have been capitalized as
a part of the historical cost of unproved oil and gas properties. Interest costs
capitalized during each of the three years in the period ended December 31, 1993
are set out in the Consolidated Statements of Income.
INCOME TAXES. Taxable income of the Company, excluding that of any foreign
subsidiaries, is included in the consolidated federal income tax return filed by
Enron Corp. Pursuant to a tax allocation agreement between the Company, the
Company's subsidiaries and Enron Corp., either Enron Corp. will pay to the
Company and each subsidiary an amount equal to the tax benefit realized in the
Enron Corp. consolidated federal income tax return resulting from the
utilization of the Company's or the subsidiary's net operating losses and/or tax
credits, or the Company and each subsidiary will pay to Enron Corp. an amount
equal to the federal income tax computed on its separate taxable income less the
tax benefits associated with any net operating losses and/or tax credits
generated by the Company or the subsidiary which are utilized in the Enron Corp.
consolidated return. Enron Corp. will pay the Company and each subsidiary for
the tax benefits associated with their net operating losses and tax credits
utilized in the Enron Corp. consolidated return, provided that a tax benefit was
realized except as discussed in the following paragraph, even if such benefits
could not have been used by the Company or the subsidiary on a separately filed
tax return.
In 1991, the Company and Enron Corp. modified the tax allocation agreement
to provide that through 1992, the Company would realize the benefit of certain
tight gas sand tax credits available to the Company on a stand alone basis. The
Company has also entered into an agreement with Enron Corp. providing for the
Company to be paid for all realizable benefits associated with tight gas sand
tax credits concurrent with tax reporting and settlement for the periods in
which they are generated.
The tax allocation agreement applies to the Company and each of its
subsidiaries for all years in which the Company or any of its subsidiaries are
or were included in the Enron Corp. consolidated return. Taxes for any foreign
subsidiaries of the Company are calculated on a separate return basis.
The Company adopted the provisions of Statement of Financial Accounting
Standards (SFAS) No. 109 -'Accounting for Income Taxes' effective January 1,
1993 and applied the provisions of the statement retroactively. The Company
previously accounted for income taxes under the provisions of SFAS No. 96 which
was superceded by SFAS No. 109. SFAS No. 109 retains the asset and liability
approach for accounting for income taxes. Under this approach, deferred tax
assets and liabilities are recognized based on anticipated future tax
consequences attributable to differences between financial statement carrying
amounts of assets and liabilities and their respective tax bases.
FOREIGN CURRENCY TRANSLATION. For subsidiaries whose functional currency is
deemed to be other than the U.S. dollar, asset and liability accounts are
translated at year end rates of exchange and revenue and expenses are translated
at average exchange rates prevailing during the year. Translation adjustments
are included as a separate component of shareholders' equity.
EARNINGS PER SHARE. Earnings per share is computed on the basis of the
average number of common shares outstanding during the periods.
F-9
2. NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING
REVENUES
Natural Gas Net Operating Revenues are comprised of the following:
1993 1992 1991
Wellhead Natural Gas Revenues
Associated Companies(1)---------- $340,508(2) $223,249(2) $171,056
Trade---------------------------- 156,301 103,288 75,037
Total-------------------- $496,809 $326,537 $246,093
Other Natural Gas Marketing
Activities
Gross Revenues from:
Associated Companies(3)------ $139,576 $186,600 $220,152
Trade------------------------ 135,606(4) 57,482(4) 7,215
Total-------------------- 275,182 244,082 227,367
Associated Costs from:
Associated
Companies(1)(5)-------------- 182,456(6) 133,170(6) 115,601
Trade------------------------ 66,273 52,283 36,011
Total-------------------- 248,729 185,453 151,612
Net---------------------- 26,453 58,629 75,755
NYMEX Commodity Price Hedging
Gain (Loss)(7)----------------- (18,100) 3,822 (245)
Total-------------------- $ 8,353 $ 62,451 $ 75,510
Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues are
comprised of the following:
1993 1992 1991
Wellhead Crude Oil, Condensate and
Natural Gas Liquids Revenues
Associated Companies------------- $ 38,953 $ 38,474 $ 37,029
Trade---------------------------- 16,881 20,152 21,599
Total------------------------ $ 55,834 $ 58,626 $ 58,628
Other Crude Oil and Condensate
Marketing Activities
NYMEX Commodity Price Hedging
Gain(7)------------------------ $ - $ 301 $ 4,208
(1) Wellhead Natural Gas Revenues in 1993, 1992 and 1991 include $129,504,
$84,317 and $69,175, respectively, associated with deliveries by Enron Oil
& Gas Company to Enron Oil & Gas Marketing, Inc., a wholly-owned
subsidiary, reflected as a cost in Other Natural Gas Marketing
Activities -Associated Costs.
(2) Includes $46,358 and $20,667 in 1993 and 1992, respectively, associated
with the equivalent wellhead value of volumes delivered under the terms of
a volumetric production payment agreement effective October 1, 1992, as
amended, net of transportation.
(3) Includes the effect of a price swap agreement with an Enron Corp.
affiliated company which in effect fixed the price of certain sales.
(4) Includes $73,867 and $25,380 in 1993 and 1992, respectively, associated
with the amortization of deferred revenues under the terms of volumetric
production payment and exchange agreements effective October 1, 1992, as
amended.
(5) Includes the effect of a price swap agreement with a third party which in
effect fixed the price of certain purchases.
(6) Includes $65,042 and $23,977 in 1993 and 1992, respectively, for volumes
delivered under volumetric production payment and exchange agreements
effective October 1, 1992, as amended, including equivalent wellhead
value, any applicable transportation costs and exchange differentials.
(7) Represents gain or loss associated with commodity futures transactions
primarily with Enron Corp. affiliated companies based on NYMEX prices in
effect on dates of execution, less customary transaction fees.
F-10
3. LONG-TERM DEBT
REVOLVING CREDIT AGREEMENT. In March 1994, the Company replaced an existing
credit agreement with a Revolving Credit Agreement dated as of March 11, 1994,
among the Company and the banks named therein (the 'Credit Agreement'). The
Credit Agreement provides for aggregate borrowings of up to $100 million, with
provisions for increases, at the option of the Company, up to $300 million.
Advances under the Credit Agreement bear interest, at the option of the Company,
based on a base rate, an adjusted CD rate or a Eurodollar rate. Each advance
under the Credit Agreement matures on a date selected by the Company at the time
of the advance, but in no event after January 15, 1998.
FINANCING ARRANGEMENTS WITH ENRON CORP. The Company engages in various
transactions with Enron Corp. that are characteristic of a consolidated group
under common control. Activities of the Company not internally funded from
operations have been and may be funded from time to time by advances from Enron
Corp. The Company entered into an agreement with Enron Corp., effective October
12, 1989 (as amended effective September 29, 1992), under which the Company may
borrow funds from Enron Corp. at a representative market rate of interest on a
revolving basis. During 1993, there were no funds borrowed by the Company under
this agreement. Any loan balance that may be outstanding from time to time is
payable on demand but no later than September 29, 1995, the maturity date of
this agreement. Any balances outstanding are classified as long-term based on
the Company's intent and ability to refinance such amounts using available
borrowing capacity. Interest expense recorded in 1992 and 1991 under the terms
of this agreement totaled $.1 million and $.2 million, respectively. There was
no interest expense relating to this agreement recorded in 1993.
The Company also entered into an agreement with Enron Corp., effective
October 12, 1989 (as amended effective September 29, 1992), which provides the
Company the option of depositing any excess funds that may be available from
time to time with Enron Corp. with interest at a representative market rate
during the periods the funds were held by Enron Corp. Interest income recorded
in 1992 and 1991 under the terms of this agreement totaled $1.4 million and $.3
million, respectively. Effective January 1, 1993, the Company executed a
promissory note at a fixed interest rate of 7% with Enron Corp. providing for
the investment of funds temporarily surplus to the Company from time to time
with Enron Corp. Daily outstanding balances of funds advanced to Enron Corp.
under this note averaged $60.3 million during 1993 with a balance of $96.6
million outstanding and included in Cash and Cash Equivalents at December 31,
1993. Interest income recorded in 1993 under the terms of this note totaled $4.4
million.
OTHER LONG-TERM DEBT. Other long-term debt at December 31 consisted of the
following:
1993 1992
Loans Payable-------------------- $ 50,000 $ 50,000
Senior Notes--------------------- 70,000 100,000
Promissory Note------------------ 33,000 -
Total---------------- $ 153,000 $ 150,000
The Loans Payable are due in 1995 and bear interest at a variable rate based
on the London Interbank Offered Rate which has, in effect, been converted to
fixed interest rates ranging from 8.92% to 8.98% through maturity using interest
rate swap agreements in equivalent dollar amounts.
The Senior Notes bear interest at 9.1% with principal repayments of $30
million due in 1996 and $20 million due in 1997 and 1998. A principal repayment
of $30 million is due in 1994 and is classified as current maturities of
long-term debt at December 31, 1993.
The Promissory Note is payable by one of the Company's subsidiaries to a
bank, bears interest at 3 3/8% and represents interim financing under Section
936(d)(4) of the Internal Revenue Code of 1986, as amended, of a project
involving the development of gas and oil fields. The note is due the earlier of
April 30, 1994, as extended, or the closing date of the permanent financing and
is collateralized with a letter of credit issued by a bank on behalf of the
subsidiary and guaranteed by the Company. The note
F-11
is classified as long-term based on the subsidiary's intent and ability to
convert the balance of the note to permanent long-term financing. In March 1994,
the subsidiary received two advances aggregating $31 million under a credit
agreement dated as of March 8, 1994, between the subsidiary and a financial
institution. The credit agreement provides for aggregate borrowings of up to $75
million. One of the advances is in the amount of $16 million, bears interest at
a fixed rate of 4.52% and is due in 1998. The other advance is in the amount of
$15 million, bears interest at a floating rate that resets quarterly equal to
84% of the LIBID Rate which is 1/8 of 1% less than the London Interbank Offered
Rate and is due in 1998. Both advances are collaterized with a letter of credit
issued by a bank on behalf of the subsidiary and guaranteed by the Company. The
advances were used to partially repay the Promissory Note.
There were no balances outstanding at December 31, 1993 and 1992 under a
commercial paper program initiated in 1990. The proceeds from the commercial
paper program outstanding from time to time are used to fund current
transactions.
Certain of the borrowings described above contain covenants requiring the
maintenance of certain financial ratios and limitations on liens, debt issuance
and dispositions of assets.
In September 1991, the Company filed with the Securities and Exchange
Commission a registration statement providing for the issuance and sale from
time to time of up to $250 million of debt securities to the public. As of
December 31, 1993, no debt securities had been issued under this registration
statement.
4. DEFERRED REVENUE
In September 1992, the Company sold a volumetric production payment for
$326.8 million to a limited partnership of which an Enron Corp. affiliated
company is general partner with a 1% interest. Under the terms of the production
payment agreements, the Company conveyed a real property interest of
approximately 124 billion cubic feet equivalent ('Bcfe') (136 trillion British
thermal units) of natural gas and other hydrocarbons in the Big Piney area of
Wyoming. The natural gas and other hydrocarbons were originally scheduled to be
produced and delivered over a period of forty-five months which period commenced
October 1, 1992. Effective October 1, 1993, the agreements were amended
providing for the extension of the original term of the volumetric production
payment through March 31, 1999 and including a revised schedule of daily
quantities of hydrocarbons to be delivered which is approximately one-half of
the original schedule. The revised schedule will total approximately 89.1 Bcfe
(97.8 trillion British thermal units) versus approximately 87.9 Bcfe (96.4
trillion British thermal units) remaining to be delivered under the original
agreement. Daily quantities of hydrocarbons no longer required to be delivered
under the revised schedule during the period from October 1, 1993 through June
30, 1996 are available for sale by the Company. The Company retains
responsibility for its working interest share of the cost of operations. The
Company also entered into a separate agreement with the same limited partnership
whereby it has agreed to exchange volumes owned by the Company in the
Midcontinent area and the Texas Gulf Coast area for equivalent volumes produced
and owned by the limited partnership in the Big Piney area. The costs incurred,
if any, to effect redeliveries pursuant to such exchange are borne by the
Company. A portion of the proceeds of the sale was used to repay a portion of
the Company's long-term debt, with surplus funds advanced to Enron Corp. under a
note agreement which facilitates the deposit of funds temporarily surplus to the
Company. The Company accounted for the proceeds received in the transaction as
deferred revenue which is being amortized into revenue and income as natural gas
and other hydrocarbons are produced and delivered during the term, as revised,
of the volumetric production payment. Annual remaining amortization of deferred
revenue, based on revised
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scheduled deliveries under the volumetric production payment agreement, as
amended, at December 31, 1993 was as follows:
1994--------------------------------- $ 43,344
1995--------------------------------- 43,344
1996--------------------------------- 43,463
1997--------------------------------- 43,344
1998--------------------------------- 43,344
1999--------------------------------- 10,689
Total------------------------ $ 227,528
5. SHAREHOLDERS' EQUITY
In August 1992, the Company completed the offering and sale of 4.1 million
shares of common stock. The shares were priced to the public at $28.50 per
share. Net proceeds, after underwriting commissions and expenses, totaled
approximately $112 million and were used primarily to repay long-term debt.
In December 1992, the Board of Directors of the Company approved the
reduction of the authorized common shares from 100 million to 80 million shares
and cancelled the authorization for preferred shares. Such actions were approved
by the shareholders in May 1993.
Also in December 1992, the Board of Directors of the Company approved the
purchase of up to 250,000 shares of common stock of the Company for, but not
limited to, meeting obligations associated with stock option grants to qualified
employees pursuant to the Enron Oil & Gas Company 1992 Stock Plan. (See Note 8
'Commitments and Contingencies -Enron Oil & Gas Company 1992 Stock Plan'). At
December 31, 1993, 80,000 shares were held in treasury under this authorization.
In February 1994, the Board of Directors authorized submission of a
resolution to shareholders for approval at their annual meeting in May 1994 that
would, contingent upon the Board of Directors of the Company declaring, on or
before May 3, 1995, a stock split of either two-for-one or three-for-two, amend
the Restated Certificate of Incorporation of the Company to increase the total
number of authorized shares of the common stock of the Company from 80 million
to 160 million shares in the event of a two-for-one stock split or to 120
million shares in the event of a three-for-two stock split. Such charter
amendment, if adopted, will become effective when the appropriate Certificate of
Amendment to the Company's Restated Certificate of Incorporation is filed with
the Secretary of State of Delaware, which filing will only be authorized at such
time as the Board of Directors takes the requisite action to approve either a
two-for-one or a three-for-two stock split in either case effected as a dividend
which action, if to be carried out under this resolution, must occur on or
before May 3, 1995.
6. TRANSACTIONS WITH ENRON CORP. AND RELATED PARTIES
NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING
REVENUES. Wellhead Natural Gas and Crude Oil, Condensate and Natural Gas
Liquids Revenues and Other Natural Gas and Other Crude Oil and Condensate
Marketing Activities include revenues from and associated costs paid to various
subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the
opinion of management, are no less favorable than could be obtained from third
parties. Other Natural Gas and Other Crude Oil and Condensate Marketing
Activities also include certain price swap and futures transactions with Enron
Corp. affiliated companies which, in the opinion of management, are no less
favorable than could be obtained from third parties. (See Note 2 'Natural Gas
and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues').
GENERAL AND ADMINISTRATIVE EXPENSES. The Company is charged by Enron Corp.
for all direct costs associated with its operations. Such direct charges,
excluding benefit plan charges (See Note 8 'Commitments and
Contingencies -Employee Benefit Plans'), totaled $11.5 million, $4.9 million
and $7.4 million for the years ended December 31, 1993, 1992 and 1991,
respectively. Management believes that these charges are reasonable.
F-13
Additionally, certain administrative costs not directly charged to any Enron
Corp. operations or business segments are allocated to the entities of the
consolidated group. Allocation percentages are generally determined utilizing
weighted average factors derived from property gross book value, net operating
revenues and payroll costs. Effective January 1, 1989, the Company entered into
an agreement with Enron Corp., with an initial term of five years, providing
for, among other things, an annual cap of $8.0 million to be applied to indirect
allocated charges subject to adjustment for inflation and certain changes in the
allocation bases of the Company. Approximately $7.9 million, $9.5 million, and
$9.4 million were charged to the Company for indirect general and administrative
expenses for the years ended December 31, 1993, 1992 and 1991, respectively.
Management believes the indirect allocated charges for the numerous types of
support services provided by the corporate staff are reasonable. Effective
January 1, 1994, the Company and Enron Corp. entered into a new services
agreement pursuant to which Enron Corp. will, among other things, provide for
the Company similar services substantially identical in nature and quality to
those provided under terms of the previous agreement. The Company has agreed to
pay and to reimburse Enron Corp. on bases essentially consistent with those
included in the previous agreement, except that allocated indirect costs are
subject to an annual maximum of $6.7 million for the year 1994 with any increase
in such maximum for subsequent years not to exceed 7.5% per year. The new
services agreement is for an initial term of five years through December 1998
and will continue thereafter until terminated by either party.
FINANCING. See Note 3 'Long-Term Debt' for a discussion of financing
arrangements with Enron Corp.
7. INCOME TAXES
As discussed in Note 1, effective January 1, 1993, the Company adopted SFAS
No. 109 and applied the provisions of the statement retroactively. Under the
provisions of SFAS No. 109, the effect of a change in a tax rate is recognized
in income for the period that includes the date of enactment of such change.
Consequently, the previously reported net income for 1991 was restated to $47.9
million ($.63 per share) from $54.9 million ($.72 per share), a reduction of
$7.0 million primarily to recognize the enactment of a change in the computation
of certain state franchise taxes, a portion of which is treated as an income tax
under SFAS No. 109. Net income for 1992 and 1993 was not affected by the
restatement. The Company's consolidated balance sheet at December 31, 1992 was
also restated to reflect the increase to Deferred Income Taxes of $7.0 million
and the corresponding decrease to Retained Earnings of an equal amount. In
August 1993, the corporate federal income tax rate increased from 34% to 35%
retroactive to January 1, 1993 resulting in an increase to the Company's 1993
deferred income tax provision of approximately $5.9 million with a corresponding
increase to the Company's deferred income tax liability of an equal amount and a
decrease of approximately $1.2 million to the Company's 1993 current income tax
benefit.
F-14
The principal components of the Company's net deferred income tax liability
at December 31, 1993 and 1992 were as follows (in thousands):
1993 1992
(RESTATED)
Deferred Income Tax Assets
Non-Producing Leasehold Costs------ $ 5,234 $ 4,661
Seismic Costs Capitalized for
Tax------------------------------ 5,643 6,505
Other------------------------------ 6,337 13,167
Total Deferred Income Tax
Assets----------------------- 17,214 24,333
Deferred Income Tax Liabilities
Oil & Gas Exploration and
Development Costs Deducted for
Tax Over Book Depreciation,
Depletion and Amortization------- 276,422 253,009
Capitalized Interest--------------- 6,866 4,604
Other------------------------------ 4,080 15,663
Total Deferred Income Tax
Liabilities------------------ 287,368 273,276
Net Deferred Income Tax
Liability-------------------- $ 270,154 $ 248,943
The components of income (loss) before income taxes were as follows:
[CAPTION]
1993 1992 1991
United States------------------------ $ 117,460 $ 74,226 $ 49,187
Foreign------------------------------ (5,187) 5,618 (3,518)
Total------------------------ $ 112,273 $ 79,844 $ 45,669
Total income tax provision (benefit) was as follows:
1993 1992 1991
(RESTATED)
Current:
Federal-------------------------- $ (52,555) $ (292) $ 9,226
State---------------------------- 5 2 -
Foreign-------------------------- 1,186 471 524
Total------------------------ (51,364) 181 9,750
Deferred:
Federal-------------------------- 20,845 (21,729) (23,917)
State---------------------------- 4,357 3,119 11,962
Foreign-------------------------- 410 693 (42)
Total------------------------ 25,612 (17,917) (11,997)
Income Tax Benefit----------------- $ (25,752) $ (17,736) $ (2,247)
The differences between taxes computed at the U.S. federal statutory rate
and the Company's effective rate were as follows:
1993 1992 1991
(RESTATED)
Statutory Federal Income Tax--------- $ 39,296 $ 27,147 $ 15,528
State Income Tax, Net of Federal
Benefit---------------------------- 2,835 2,059 877
Income Tax Related to Foreign
Operations------------------------- 3,461 (1,649) 1,677
Tight Gas Sand Federal Income Tax
Credits---------------------------- (65,172) (42,500) (16,926)
Revision of Prior Years' Tax
Estimates-------------------------- (12,060) (2,842) (10,461)
SFAS No. 109 Restatement------------- - - 7,018
Federal Tax Rate Increase------------ 5,875 - -
Other-------------------------------- 13 49 40
Income Tax Benefit--------------- $ (25,752) $ (17,736) $ (2,247)
F-15
Current income tax receivable from (payable to) Enron Corp. at December 31,
1993, 1992 and 1991 amounted to $(6,892), $5,619 and $(4,522), respectively.
The Company has an alternative minimum tax (AMT) credit carryforward of $2.7
million which can be used to offset regular income taxes payable in future
years. The AMT credit carryforward has an indefinite carryforward period.
The Company's foreign subsidiaries' undistributed earnings of approximately
$45 million at December 31, 1993 are considered to be indefinitely invested
outside the U.S. and, accordingly, no U.S. federal or state income taxes have
been provided thereon. Upon distribution of those earnings in the form of
dividends, the Company may be subject to both foreign withholding taxes and U.S.
income taxes, net of allowable foreign tax credits. Determination of any
potential amount of unrecognized deferred income tax liabilities is not
practicable.
In 1991, the Company recognized for financial reporting purposes the
benefits attributable to the utilization of a previously unrecognized separate
company net operating loss carryforward resulting in a tax benefit of
approximately $7 million reflected in 1991 net income.
8. COMMITMENTS AND CONTINGENCIES
EMPLOYEE BENEFIT PLANS. Employees of the Company are covered by various
retirement, stock purchase and other benefit plans of Enron Corp. During each of
the years ended December 31, 1993, 1992 and 1991, the Company was charged $4.5
million, $3.6 million and $3.6 million, respectively, for all such benefits,
including pension expense totalling $.5 million, $.5 million and $.4 million,
respectively, by Enron Corp.
As of September 30, 1993, the most recent valuation date, the plan net
assets of the Enron Corp. defined benefit plan in which the employees of the
Company participate exceeded the actuarial present value of projected plan
benefit obligations by approximately $25.3 million. The assumed discount rate,
rate of return on plan assets and rate of increases in wages used in determining
the actuarial present value of projected plan benefits were 7.0%, 10.5% and
4.0%, respectively.
The Company also has in effect a pension and a savings plan related to its
Canadian and Trinidadian subsidiaries. Activity related to these plans is not
significant to the Company's operations.
The Company provides certain medical, life insurance and dental benefits to
eligible employees who retire under the Enron Corp. Retirement Plan and their
eligible surviving spouses. Effective January 1, 1993, the Company adopted the
provisions of SFAS No. 106 'Employers' Accounting for Postretirement Benefits
Other Than Pensions'. The standard requires that employers providing
postretirement benefits accrue those costs over the service lives of the
employees expected to be eligible to receive such benefits. Such costs were
previously recorded on a pay-as-you-go basis. The net periodic cost under SFAS
No. 106 for 1993 was approximately $1.0 million, including service cost,
interest cost and amortization of transition obligation in the amounts of $.1
million, $.5 million and $.4 million, respectively. The transition obligation
existing at January 1, 1993 is being amortized over an average period of 19
years. The adoption of SFAS No. 106 did not have a material impact on the
Company's results of operations.
The accumulated postretirement benefit obligation ('APBO') existing at
December 31, 1993 totaled $8.7 million, of which $7.2 million is applicable to
current retirees and current employees eligible to retire. The measurement of
the APBO assumes a 7% discount rate and a health care cost trend rate of 13% in
1993 decreasing to 5% by the year 2005 and beyond. A 1% increase in the health
care cost trend rate would have the effect of increasing the APBO and the net
periodic expense by approximately $.8 million and $.1 million, respectively. The
Company does not currently intend to prefund its obligations under its
postretirement welfare benefit plans.
ENRON OIL & GAS COMPANY 1992 STOCK PLAN. In December 1991, the Board of
Directors of the Company adopted the Enron Oil & Gas Company 1992 Stock Plan
(the 'Stock Plan'). The Stock Plan was approved by the shareholders in May 1992.
Under the Stock Plan, employees of the
F-16
Company and its subsidiaries may be granted rights to purchase shares of common
stock of the Company generally at a price not less than the market price of the
stock at the date of grant. Options granted under the Stock Plan vest to the
employee over a period of time based on the nature of the grants and as defined
in the individual grant agreements.
The following table sets forth Stock Plan transactions for the years ended
December 31:
NUMBER OF STOCK OPTIONS
1993 1992
Outstanding at January 1------------- 1,954,025 -
Granted-------------------------- 460,300 2,024,025
Exercised------------------------ (335,925) (63,750)
Forfeited------------------------ (16,000) (6,250)
Outstanding at December 31 (Grant
Prices of $18.50-$47.63 per Share)- 2,062,400 1,954,025
Available for Grant at December 31--- 537,925 982,225
At December 31, 1993, 1,249,975 of the Stock Plan options outstanding were
vested. Of the remaining unvested Stock Plan options, approximately 377,550;
201,750; 157,375 and 75,750 vest in the years 1994, 1995, 1996 and 1997,
respectively.
During 1993 and 1992, the Company purchased 335,925 and 63,750 of its common
shares, respectively, and simultaneously delivered such shares upon the exercise
of stock options. The difference between the cost of the treasury shares and the
exercise price of the options, net of federal income tax benefit of $2.8
million, is reflected as an adjustment to Additional Paid In Capital. In
addition in October 1993, the Company commenced a stock repurchase program
authorized by the Board of Directors to facilitate the availability of treasury
shares of common stock for the settlement of employee stock option exercises
pursuant to, but not limited to, the Enron Oil & Gas Company 1992 Stock Plan. At
December 31, 1993, 80,000 shares were held in treasury under this authorization.
(See Note 5 'Shareholders' Equity').
Pursuant to an amendment to and extension of an employment agreement with
the Chairman of the Board, President and Chief Executive Officer of the Company
(the 'Chairman'), as of January 1, 1992, the Chairman agreed to the cancellation
of 1,000,000 previously issued stock appreciation right ('SAR') units. The
Chairman was granted 1,110,000 stock options pursuant to the 1992 Stock Plan.
These options have a grant price of $18.50 per share; 1,000,000 of the options
follow the same vesting schedule as did the SAR unit grant, 100,000 options vest
over four years and the remaining 10,000 options vested in one year since such
options were granted in lieu of part of the Chairman's 1991 cash bonus. In
addition, the Chairman was issued in May 1992, 463,320 shares of Enron Corp.
common stock. Such number of shares reflects the effect of a two-for-one split
of such stock on August 16, 1993. Of these shares, 370,656 shares are restricted
until such shares vest on the earlier to occur of five years after their date of
grant or when the Chairman commences receiving benefits from one or more of the
qualified pension plans sponsored by Enron Corp.
In February 1994, the Board of Directors of the Company adopted the Enron
Oil & Gas Company 1994 Stock Plan (the '1994 Stock Plan'). Under the 1994 Stock
Plan, employees of the Company and its subsidiaries may be granted rights to
purchase shares of common stock of the Company generally at a price not less
than the market price of the stock at the date of grant. Options granted under
the 1994 Stock Plan vest to the employee over a period of time based on the
nature of the grants and as defined in the individual grant agreements. The
number of shares available for granting awards under the 1994 Stock Plan is
1,000,000 shares subject to certain adjustments. It is the intention of the
Company that grants under the 1994 Stock Plan will be primarily to non-executive
employees.
LETTERS OF CREDIT. At December 31, 1993 and 1992, the Company had letters
of credit outstanding totalling approximately $46.2 and $52.9 million,
respectively. The letters of credit outstanding at December 31, 1993 include $33
million issued in connection with a promissory note between one of
F-17
the Company's subsidiaries and a bank. The letters of credit outstanding at
December 31, 1992 included $40 million issued in December 1992 in connection
with the acquisition of producing properties in Canada, which acquisition was
subsequently funded in early 1993. The related liability at December 31, 1992
for the acquisition was included in Other Current Liabilities.
CONTINGENCIES. There are various suits and claims against the Company
having arisen in the ordinary course of business. However, management does not
believe these suits and claims will individually or in the aggregate have a
material adverse effect on the Company's financial condition or results of
operations. TransAmerican Natural Gas Corporation ('TransAmerican') has filed a
petition against the Company and Enron Corp. alleging breach of contract,
tortious interference with contract, misappropriation of trade secrets and
violation of state antitrust laws. The petition, as amended, seeks actual
damages of $100 million plus exemplary damages of $300 million. The Company has
answered the petition and is actively defending the matter; in addition, the
Company has filed counterclaims against TransAmerican and a third-party claim
against its sole shareholder, John R. Stanley, alleging fraud, negligent
misrepresentation and breach of state antitrust laws. Trial, originally set for
February 7, 1994, is now set for September 12, 1994. Although no assurances can
be given, the Company believes that the claims made by TransAmerican are totally
without merit, that the ultimate resolution of the matter will not have a
materially adverse effect on its financial condition or results of operations,
and that such ultimate resolution could result in a recovery to the Company. The
Company has been named as a potentially responsible party in certain
Comprehensive Environmental Response Compensation and Liability Act proceedings.
However, management does not believe that any potential assessments resulting
from such proceedings will individually or in the aggregate have a materially
adverse effect on the financial condition or results of operations of the
Company.
9. CASH FLOW INFORMATION
Gains on sales of certain oil and gas properties in the amount of $13.3
million, $6.0 million and $15.0 million are required to be removed from Net
Income in connection with determining Net Operating Cash Inflows while the
related proceeds are classified as investing cash flows for the years ended
December 31, 1993, 1992 and 1991, respectively. However, current accounting
guidelines will not permit the relevant federal income tax impact of these
transactions to be reclassified to investing cash flows. The current federal
income tax impact of these sales transactions was calculated by the Company to
be $8.2 million, $8.2 million and $5.1 million for the years ended December 31,
1993, 1992 and 1991, respectively, which entered into the overall calculation of
current federal income tax. The Company believes that this federal income tax
impact should be considered in analyzing the elements of the cash flow
statement.
Cash paid for interest and paid (received) for income taxes was as follows
for the years ended December 31:
1993 1992 1991
Interest (net of amount
capitalized)----------------------- $ 10,517 $ 21,576 $ 30,967
Income taxes------------------------- (67,733) 7,365 6,618
F-18
10. BUSINESS SEGMENT INFORMATION
The Company's operations are all natural gas and crude oil exploration and
production related. Accordingly, such operations are classified as one business
segment. Financial information by geographic area is presented below for the
years ended December 31, or at December 31:
1993 1992 1991
Gross Operating Revenues
United States-------------------- $ 640,205 $ 521,128 $ 436,856
Foreign-------------------------- 46,722 32,997 33,186
Total(1)--------------------- $ 686,927 $ 554,125 $ 470,042
Operating Income (Loss)
United States-------------------- $ 112,686 $ 109,515 $ 77,333
Foreign-------------------------- (10,445) (9,943) (13,932)
Total------------------------ $ 102,241 $ 99,572 $ 63,401
Identifiable Assets
United States-------------------- $1,564,330 $1,568,093 $1,309,967
Foreign-------------------------- 246,832 162,919 145,641
Total------------------------ $1,811,162 $1,731,012 $1,455,608
(1) Not deducted are natural gas associated costs of $119,225, $101,136 and
$82,437 in 1993, 1992 and 1991, respectively.
11. OTHER INCOME
Other income consisted of the following for the years ended December 31:
1993 1992 1991
Gains on Sales of Oil and Gas
Properties------------------------- $ 13,318 $ 6,037 $ 14,983
Litigation Reserve Accruals---------- (2,520) (2,194) (1,200)
Interest Income---------------------- 5,789 1,555 424
Settlement of Natural Gas
Contracts-------------------------- 4,248 - -
Other, Net--------------------------- (882) (2,837) (2,439)
Total------------------------ $ 19,953 $ 2,561 $ 11,768
12. CONCENTRATIONS OF CREDIT RISK AND ESTIMATED FAIR VALUE OF FINANCIAL
INSTRUMENTS
ACCOUNTS RECEIVABLE. Substantially all of the Company's accounts receivable
at December 31, 1993 result from crude oil and natural gas sales and/or joint
interest billings to affiliate and third party companies in the oil and gas
industry. This concentration of customers and joint interest owners may impact
the Company's overall credit risk, either positively or negatively, in that
these entities may be similarly affected by changes in economic or other
conditions. In determining whether or not to require collateral from a customer
or joint interest owner, the Company analyzes the entity's net worth, cash
flows, earnings, and credit ratings. Receivables are generally not
collateralized. Historical credit losses incurred on receivables by the Company
have been immaterial.
LONG-TERM DEBT. At December 31, 1993, the Company had $153 million of
long-term debt and $30 million of current maturities outstanding. (See Note 3
'Long-Term Debt'). The estimated fair value of such debt, including current
maturities, at December 31, 1993 was approximately $192 million. The fair value
of long-term debt is the value the Company would have to pay to retire the debt,
including any premium or discount to the debtholder for the differential between
the stated interest rate and the year-end market rate. The fair value of
long-term debt is based upon quoted market prices and, where such quotes were
not available, upon interest rates available to the Company at year-end.
F-19
INTEREST RATE SWAP AGREEMENTS. In early 1992, the Company entered into $75
million in notional amount of interest rate swap agreements to hedge certain
floating interest rate exposure in 1992 and 1993. This floating rate exposure
arises from interest-bearing debt with interest payments subject to floating
interest rates. (See Note 3 'Long-Term Debt'). Effective January 1, 1993, Enron
Corp. assumed the Company's remaining obligations under these swap agreements.
At December 31, 1993, the Company had outstanding interest rate swaps with
notional principal amounts of $50 million which terminate April 1995. The
estimated fair value of the outstanding swap agreements at December 31, 1993
was a negative $3.3 million. The fair value of interest rate swap agreements is
based upon termination values obtained from third parties.
FOREIGN CURRENCY CONTRACTS. The Company enters into foreign currency
contracts from time to time to hedge specific currency exposure from commercial
transactions. At December 31, 1993, there were no foreign currency contracts
outstanding.
PRICE RISK MANAGEMENT. During 1990 and 1991, the Company entered into
certain price swap agreements to, in effect, hedge the market risk caused by
fluctuations in the price of natural gas. The agreements call for the Company to
make payments to (or receive payments from) the other party based upon the
differential between a fixed and a variable price for natural gas as specified
by the contract. The current swap agreements run for periods of up to ten years
expiring in 2000 and have a notional contract amount of approximately $299
million at December 31, 1993.
While notional contract amounts are used to express the magnitude of price
and interest rate swap agreements, the amounts potentially subject to credit
risk, in the event of nonperformance by the third parties, are substantially
smaller. The Company does not anticipate nonperformance by the third parties.
F-20
ENRON OIL & GAS COMPANY
SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS UNLESS OTHERWISE INDICATED)
(UNAUDITED EXCEPT FOR RESULTS OF OPERATIONS FOR OIL AND GAS
PRODUCING ACTIVITIES)
OIL AND GAS PRODUCING ACTIVITIES
The following disclosures are made in accordance with SFAS No. 69 -
'Disclosures about Oil and Gas Producing Activities':
OIL AND GAS RESERVES. Users of this information should be aware that the
process of estimating quantities of 'proved' and 'proved developed' crude oil
and natural gas reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological, engineering and
economic data for each reservoir. The data for a given reservoir may also change
substantially over time as a result of numerous factors including, but not
limited to, additional development activity, evolving production history, and
continual reassessment of the viability of production under varying economic
conditions. Consequently, material revisions to existing reserve estimates occur
from time to time. Although every reasonable effort is made to ensure that
reserve estimates reported represent the most accurate assessments possible, the
significance of the subjective decisions required and variances in available
data for various reservoirs make these estimates generally less precise than
other estimates presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of crude oil, condensate,
natural gas and natural gas liquids that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in future years from
known reservoirs under economic and operating conditions existing at the time
the estimates were made.
Proved developed reserves are proved reserves expected to be recovered,
through wells and equipment in place and under operating methods being utilized
at the time the estimates were made.
Canadian provincial royalties are determined based on a graduated percentage
scale which varies with prices and production volumes. Canadian reserves, as
presented on a net basis, assume prices and royalty rates in existence at the
time the estimates were made, and the Company's estimate of future production
volumes. Future fluctuations in prices, production rates, or changes in
political or regulatory environments could cause the Company's share of future
production from Canadian reserves to be materially different from that
presented.
Estimates of proved and proved developed reserves at December 31, 1993, 1992
and 1991 were based on studies performed by the Company's engineering staff for
reserves in both the United States and Canada. Opinions by DeGolyer and
MacNaughton, independent petroleum consultants, for the years ended December 31,
1993, 1992 and 1991 covering producing areas containing 65%, 69% and 73%,
respectively, of proved reserves of the Company on a
net-equivalent-cubic-feet-of-gas basis, indicate that the estimates of proved
reserves prepared by the Company's engineering staff for the properties reviewed
by DeGolyer and MacNaughton, when compared in total on a net-equivalent-
cubic-feet-of-gas basis, do not differ materially from the estimates prepared by
DeGolyer and MacNaughton. Such estimates by DeGolyer and MacNaughton in the
aggregate varied by not more than 5% from those prepared by the Company's
engineering staff. All reports by DeGolyer and MacNaughton were developed
utilizing geological and engineering data provided by the Company.
No major discovery or other favorable or adverse event subsequent to
December 31, 1993 is believed to have caused a material change in the estimates
of proved or proved developed reserves as of that date.
F-21
The following table sets forth the Company's net proved and proved developed
reserves at December 31 for each of the four years in the period ended December
31, 1993, and the changes in the net proved reserves for each of the three years
in the period then ended as estimated by the Company's engineering staff.
NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
UNITED STATES CANADA TRINIDAD TOTAL
Natural Gas (MMcf)
Proved reserves at December 31,
1990--------------------------- 1,343,467 131,508 - 1,474,975
Revisions of previous
estimates------------------ 48,371 35 - 48,406
Purchases in place----------- 45,030 2,885 - 47,915
Extensions, discoveries and
other additions------------ 199,410 6,193 - 205,603
Sales in place--------------- (6,933) (2,477) - (9,410)
Production------------------- (173,460) (9,237) - (182,697)
Proved reserves at December 31,
1991--------------------------- 1,455,885 128,907 - 1,584,792
Revisions of previous
estimates------------------ (46,325) (4,082) - (50,407)
Purchases in place----------- 30,537 112,592 - 143,129
Extensions, discoveries and
other additions------------ 228,044 6,336 - 234,380
Sales in place--------------- (27,707) (2) - (27,709)
Production------------------- (200,054) (11,249) - (211,303)
Proved reserves at December 31,
1992--------------------------- 1,440,380(1) 232,502 - 1,672,882
Revisions of previous
estimates------------------ (31,282) 11,058 - (20,224)
Purchases in place----------- 9,183 2,627 - 11,810
Extensions, discoveries and
other additions------------ 234,858 47,678 101,292 383,828
Sales in place--------------- (12,453) (1,501) - (13,954)
Production------------------- (240,014) (21,308) (829) (262,151)
Proved reserves at December 31,
1993--------------------------- 1,400,672(1) 271,056 100,463 1,772,191
Liquids (MBbl)(2)
Proved reserves at December 31,
1990--------------------------- 16,272 6,856 - 23,128
Revisions of previous
estimates------------------ (86) 256 - 170
Purchases in place----------- 173 42 - 215
Extensions, discoveries and
other additions------------ 983 310 - 1,293
Sales in place--------------- (1,248) (25) - (1,273)
Production------------------- (2,272) (927) - (3,199)
Proved reserves at December 31,
1991--------------------------- 13,822 6,512 - 20,334
Revisions of previous
estimates------------------ 365 (885) - (520)
Purchases in place----------- 65 - - 65
Extensions, discoveries and
other additions------------ 2,320 698 - 3,018
Sales in place--------------- (296) (4) - (300)
Production------------------- (2,411) (963) - (3,374)
Proved reserves at December 31,
1992--------------------------- 13,865(1) 5,358 - 19,223
Revisions of previous
estimates------------------ 1,490 (536) - 954
Purchases in place----------- 15 489 - 504
Extensions, discoveries and
other additions------------ 3,552 1,115 2,251 6,918
Sales in place--------------- (3,230) (23) - (3,253)
Production------------------- (2,520) (932) (33) (3,485)
Proved reserves at December 31,
1993--------------------------- 13,172(1) 5,471 2,218 20,861
(TABLE CONTINUED ON FOLLOWING PAGE)
F-22
Proved developed reserves at
Natural Gas (MMcf)
December 31, 1990------------ 1,023,711 114,045 - 1,137,756
December 31, 1991------------ 1,138,530 112,975 - 1,251,505
December 31, 1992------------ 1,168,386(1) 194,366 - 1,362,752
December 31, 1993------------ 1,167,313(1) 250,572 71,393 1,489,278
Liquids (MBbl)(2)
December 31, 1990------------ 15,269 6,804 - 22,073
December 31, 1991------------ 13,002 6,484 - 19,486
December 31, 1992------------ 12,762(1) 5,329 - 18,091
December 31, 1993------------ 11,165(1) 5,409 1,591 18,165
(1) Includes approximately 87 billion cubic feet equivalent (96 trillion
British thermal units) in 1993 and 114 billion cubic feet equivalent (126
trillion British thermal units) in 1992 associated with a volumetric
production payment sold effective October 1, 1992 to be delivered over a
seventy-eight month period, as revised, which period commenced October 1,
1992.
(2) Includes crude oil, condensate and natural gas liquids.
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES. The
following table sets forth the capitalized costs relating to the Company's
natural gas and crude oil producing activities at December 31, 1993 and 1992:
1993 1992
Proved properties-------------------- $ 2,675,419 $ 2,396,601
Unproved properties------------------ 96,801 78,770
Total---------------------------- 2,772,220 2,475,371
Accumulated depreciation, depletion
and amortization------------------- (1,226,175) (1,007,360)
Net capitalized costs---------------- $ 1,546,045 1,468,011
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES. The acquisition, exploration and development costs
disclosed in the following tables are in accordance with definitions in SFAS
No. 19 - 'Financial Accounting and Reporting by Oil and Gas Producing
Companies'.
Acquisition costs include costs incurred to purchase, lease, or otherwise
acquire property.
Exploration costs include exploration expenses, additions to exploration
wells in progress, and depreciation of support equipment used in exploration
activities.
Development costs include additions to production facilities and equipment,
additions to development wells in progress and related facilities, and
depreciation of support equipment and related facilities used in development
activities.
The following tables set forth costs incurred related to the Company's oil
and gas activities for the years ended December 31:
FOREIGN
UNITED STATES CANADA TRINIDAD OTHER TOTAL
1993
Acquisition Costs of Properties
Unproved------------------------- $ 23,686 $ 4,556 $ - $ 887 $ 29,129
Proved--------------------------- 6,625 2,598 - - 9,223
Total------------------------ 30,311 7,154 - 887 38,352
Exploration Costs-------------------- 53,918 9,096 1,367 18,595 82,976
Development Costs-------------------- 247,705 28,045 41,262 - 317,012
Total------------------------ $ 331,934 $ 44,295 $ 42,629 $ 19,482 $ 438,340
(TABLE CONTINUED ON FOLLOWING PAGE)
F-23
1992
Acquisition Costs of Properties
Unproved------------------------- $ 21,844 $ 1,173 $ - $ 3 $ 23,020
Proved--------------------------- 25,958 39,281 - - 65,239
Total------------------------ 47,802 40,454 - 3 88,259
Exploration Costs-------------------- 38,547 5,787 151 10,990 55,475
Development Costs-------------------- 256,814 5,162 735 - 262,711
Total------------------------ $ 343,163 $ 51,403 $ 886 $ 10,993 $ 406,445
1991
Acquisition Costs of Properties
Unproved------------------------- $ 12,156 $ 223 $ - $ 176 $ 12,555
Proved--------------------------- 40,039 2,362 - - 42,401
Total------------------------ 52,195 2,585 - 176 54,956
Exploration Costs-------------------- 39,916 5,369 - 15,062 60,347
Development Costs-------------------- 132,200 10,338 - - 142,538
Total------------------------ $ 224,311 $ 18,292 $ - $ 15,238 $ 257,841
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES(1). The following
tables set forth results of operations for oil and gas producing activities for
the years ended December 31:
FOREIGN
UNITED STATES CANADA TRINIDAD OTHER TOTAL
1993
Operating Revenues
Associated Companies------------- $ 369,824 $ 9,637 $ - $ - $ 379,461
Trade---------------------------- 140,552 33,228 1,209 - 174,989
Total------------------------ 510,376 42,865 1,209 - 554,450
Exploration Expenses, including Dry
Hole------------------------------- 35,029 6,657 1,367 12,223 55,276
Production Costs--------------------- 75,767 14,063 1,496 - 91,326
Impairment of Unproved Oil and Gas
Properties------------------------- 19,499 968 - - 20,467
Depreciation, Depletion and
Amortization----------------------- 234,292 14,630 387 154 249,463
Income (Loss) before Income Taxes---- 145,789 6,547 (2,041) (12,377) 137,918
Income Tax Provision (Benefit)------- (20,329) 2,447 (1,020) (1,742) (20,644)
Results of Operations---------------- $ 166,118 $ 4,100 $ (1,021) $ (10,635) $ 158,562
1992
Operating Revenues
Associated Companies------------- $ 251,649 $ 10,074 $ - $ - $ 261,723
Trade---------------------------- 106,633 19,313 - - 125,946
Total------------------------ 358,282 29,387 - - 387,669
Exploration Expenses, including Dry
Hole------------------------------- 29,705 3,829 151 10,357 44,042
Production Costs--------------------- 63,571 9,271 - - 72,842
Impairment of Unproved Oil and Gas
Properties------------------------- 12,001 1,034 - 2,101 15,136
Depreciation, Depletion and
Amortization----------------------- 167,767 11,719 - 327 179,813
Income (Loss) before Income Taxes---- 85,238 3,534 (151) (12,785) 75,836
Income Tax Provision (Benefit)------- (16,030) 1,202 (75) (4,323) (19,226)
Results of Operations---------------- $ 101,268 $ 2,332 $ (76) $ (8,462) $ 95,062
(TABLE CONTINUED ON FOLLOWING PAGE)
F-24
1991 (RESTATED)(2)
Operating Revenues
Associated Companies------------- $ 197,841 $ 10,244 $ - $ - $ 208,085
Trade---------------------------- 78,964 19,004 - - 97,968
Total------------------------ 276,805 29,248 - - 306,053
Exploration Expenses, including Dry
Hole------------------------------- 28,107 3,659 - 14,402 46, 168
Production Costs--------------------- 56,167 9,418 - - 65,585
Impairment of Unproved Oil and Gas
Properties------------------------- 10,342 2,449 - - 12,791
Depreciation, Depletion and
Amortization----------------------- 148,401 12,385 - 99 160,885
Income (Loss) before Income Taxes---- 33,788 1,337 - (14,501) 20,624
Income Tax Provision (Benefit)------- (5,076) 455 - (4,930) (9,551)
Results of Operations---------------- $ 38,864 $ 882 $ - $(9,571) $ 30,175
(1) Excludes net revenues associated with other marketing activities, interest
charges, general corporate expenses and certain gathering and handling
fees for each of the three years in the period ended December 31, 1993.
The gathering and handling fees and other marketing net revenues are
directly associated with oil and gas operations with regard to segment
reporting as defined in SFAS No. 14 - 'Financial Reporting for Segments of
a Business Enterprise', but are not part of Disclosures about Oil and Gas
Producing Activities as defined in SFAS No. 69.
(2) Effective January 1, 1993, the Company adopted SFAS No. 109 and applied
the provisions of the statement retroactively. As a result, the previously
reported Income Tax Provision (Benefit) and Results of Operations for 1991
were restated to $9.6 million benefit and $30.2 million, respectively,
from $16.6 million benefit and $37.2 million, respectively, a reduction of
$7.0 million primarily to recognize the enactment of a change in the
computation of certain state franchise taxes, a portion of which is
treated as an income tax under SFAS No. 109. The Results of Operations for
1992 and 1993 was not affected by the restatement.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES. The following information has been developed utilizing
procedures prescribed by SFAS No. 69 and based on crude oil and natural gas
reserve and production volumes estimated by the engineering staff of the
Company. It may be useful for certain comparison purposes, but should not be
solely relied upon in evaluating the Company or its performance. Further,
information contained in the following table should not be considered as
representative of realistic assessments of future cash flows, nor should the
Standardized Measure of Discounted Future Net Cash Flows be viewed as
representative of the current value of the Company.
The future cash flows presented below are based on sales prices, cost rates,
and statutory income tax rates in existence as of the date of the projections.
It is expected that material revisions to some estimates of crude oil and
natural gas reserves may occur in the future, development and production of the
reserves may occur in periods other than those assumed, and actual prices
realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment
and operating decisions. Such decisions are based upon a wide range of factors,
including estimates of probable as well as proved reserves, and varying price
and cost assumptions considered more representative of a range of possible
economic conditions that may be anticipated.
F-25
The following table sets forth the standardized measure of discounted future
net cash flows from projected production of the Company's crude oil and natural
gas reserves at December 31, for the years ended December 31:
1993 UNITED STATES CANADA TRINIDAD TOTAL
Future revenues(1)------------------- $ 3,343,900(3) $ 592,845 $ 147,542 $ 4,084,287
Future production costs-------------- (639,760) (230,230) (45,385) (915,375)
Future development costs------------- (165,473) (21,001) (7,582) (194,056)
Future net cash flows before income
taxes------------------------------ 2,538,667 341,614 94,575 2,974,856
Discount to present value at 10%
annual rate------------------------ (951,748) (143,992) (20,097) (1,115,837)
Present value of future net cash
flows before income taxes---------- 1,586,919 197,622 74,478 1,859,019
Future income taxes discounted at 10%
annual rate(2)--------------------- (219,228) (37,851) (24,899) (281,978)
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves(1)----- $ 1,367,691(4) $ 159,771 $ 49,579 $ 1,577,041
1992
Future revenues(1)------------------- $ 3,017,188(3) $ 363,284 - $ 3,380,472
Future production costs-------------- (573,763) (105,802) - (679,565)
Future development costs------------- (194,246) (12,881) - (207,127)
Future net cash flows before income
taxes------------------------------ 2,249,179 244,601 - 2,493,780
Discount to present value at 10%
annual rate------------------------ (790,027) (91,126) - (881,153)
Present value of future net cash
flows before income taxes---------- 1,459,152 153,475 - 1,612,627
Future income taxes discounted at 10%
annual rate(2)--------------------- (147,736) (28,056) - (175,792)
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves(1)----- $ 1,311,416(4) $ 125,419 $ - $ 1,436,835
1991
Future revenues(1)------------------- $ 2,501,439 $ 269,917 - $ 2,771,356
Future production costs-------------- (504,420) (79,413) - (583,833)
Future development costs------------- (189,091) (6,132) - (195,223)
Future net cash flows before income
taxes------------------------------ 1,807,928 184,372 - 1,992,300
Discount to present value at 10%
annual rate------------------------ (618,919) (62,137) - (681,056)
Present value of future net cash
flows before income taxes---------- 1,189,009 122,235 - 1,311,244
Future income taxes discounted at 10%
annual rate(2)--------------------- (127,188) (27,979) - (155,167)
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves(1)----- $ 1,061,821 $ 94,256 $ - $ 1,156,077
(1) Based on year end market prices determined at the point of delivery from
the producing unit.
(2) Future income taxes before discount were $540.3 million U.S., $91.7
million Canada, $35.5 million Trinidad and $667.5 million total; $394.1
million U.S., $63.0 million Canada and $457.1 million total; and $279.4
million U.S., $53.0 million Canada and $332.4 million total for the years
ended December 31, 1993, 1992 and 1991, respectively.
(3) 'Future revenues' includes approximately $189.1 million ($146.9 million
discounted at 10% annual rate) for 1993 and $203.5 million ($174.5 million
discounted at 10% annual rate) for 1992 related to volumes associated with
a volumetric production payment sold effective October 1, 1992, as
amended, to be delivered over a seventy-eight month period, as revised,
which period commenced October 1, 1992.
(4) Includes approximately $92.6 million in 1993 and $111.2 million in 1992
representing the discounted present value at a discount rate of 10% of the
'Future revenues' detailed in note (3) after deducting future income
taxes.
F-26
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The
following table sets forth the changes in the standardized measure of discounted
future net cash flows at December 31, for each of the three years in the period
ended December 31, 1993.
UNITED STATES CANADA TRINIDAD TOTAL
December 31, 1990-------------------- $ 928,584 $ 130,742 $ - $ 1,059,326
Sales and transfers of oil and gas
produced, net of production
costs--------------------------- (220,638) (19,830) - (240,468)
Net changes in prices and
production costs---------------- (150,061) (51,609) - (201,670)
Extensions, discoveries, additions
and improved recovery net of
related costs------------------- 212,097 4,802 - 216,899
Development costs incurred-------- 36,719 11 - 36,730
Revisions of estimated development
costs--------------------------- 1,640 2,833 - 4,473
Revisions of previous quantity
estimates----------------------- 37,535 1,178 - 38,713
Accretion of discount------------- 116,559 17,823 - 134,382
Net change in income taxes-------- 109,821 19,512 - 129,333
Purchases of reserves in place---- 38,350 (558) - 37,792
Sales of reserves in place-------- (17,321) (2,328) - (19,649)
Changes in timing and other------- (31,464) (8,320) - (39,784)
December 31, 1991-------------------- 1,061,821 94,256 - 1,156,077
Sales and transfers of oil and gas
produced, net of production
costs--------------------------- (294,711) (20,116) - (314,827)
Net changes in prices and
production costs---------------- 257,572 8,190 - 265,762
Extensions, discoveries, additions
and improved recovery net of
related costs------------------- 275,231 8,999 - 284,230
Development costs incurred-------- 49,668 177 - 49,845
Revisions of estimated development
costs--------------------------- (19,540) 1,406 - (18,134)
Revisions of previous quantity
estimates----------------------- (45,863) (7,539) - (53,402)
Accretion of discount------------- 118,901 12,224 - 131,125
Net change in income taxes-------- (20,548) (77) - (20,625)
Purchases of reserves in place---- 28,884 32,533 - 61,417
Sales of reserves in place-------- (34,984) (15) - (34,999)
Changes in timing and other------- (65,015) (4,619) - (69,634)
December 31, 1992-------------------- 1,311,416 125,419 - 1,436,835
Sales and transfers of oil and gas
produced, net of production
costs--------------------------- (434,609) (28,802) 287 (463,124)
Net changes in prices and
production costs---------------- 180,240 28,400 - 208,640
Extensions, discoveries, additions
and improved recovery net of
related costs------------------- 275,722 27,785 74,191 377,698
Development costs incurred-------- 58,500 13,900 - 72,400
Revisions of estimated development
costs--------------------------- 32,196 (1,345) - 30,851
Revisions of previous quantity
estimates----------------------- (26,118) 5,668 - (20,450)
Accretion of discount------------- 145,915 15,348 - 161,263
Net change in income taxes-------- (71,492) (9,795) (24,899) (106,186)
Purchases of reserves in place---- 9,462 2,707 - 12,169
Sales of reserves in place-------- (38,498) (1,140) - (39,638)
Changes in timing and other------- (75,043) (18,374) - (93,417)
December 31, 1993-------------------- $ 1,367,691 $ 159,771 $ 49,579 $ 1,577,041
F-27
UNAUDITED QUARTERLY FINANCIAL INFORMATION
QUARTER ENDED
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
1993
Net Operating Revenues--------------- $ 136,820 $ 140,493 $ 141,098 $ 149,291
Operating Income--------------------- $ 29,619 $ 31,524 $ 26,902 $ 14,196
Income before Income Taxes----------- $ 28,955 $ 29,598 $ 37,168 $ 16,552
Income Tax Provision (Benefit)------- (1,253) (3,923) 1,412 (21,988)
Net Income--------------------------- $ 30,208 $ 33,521 $ 35,756 $ 38,540
Earnings Per Share of Common
Stock------------------------------ $ .38 $ .42 $ .45 $ .48
Average Number of Common Shares------ 80,000 80,000 80,000 79,932
1992
Net Operating Revenues--------------- $ 98,630 $ 100,457 $ 111,858 $ 142,044
Operating Income--------------------- $ 20,936 $ 13,822 $ 24,392 $ 40,422
Income before Income Taxes----------- $ 14,079 $ 11,665 $ 18,639 $ 35,461
Income Tax Benefit------------------- (8,208) (2,900) (1,960) (4,668)
Net Income--------------------------- $ 22,287 $ 14,565 $ 20,599 $ 40,129
Earnings Per Share of Common
Stock------------------------------ $ .29 $ .19 $ .27 $ .50
Average Number of Common Shares------ 75,900 75,900 77,267 80,000
1991 (RESTATED)
Net Operating Revenues--------------- $ 95,894 $ 87,971 $ 83,956 $ 119,784
Operating Income--------------------- $ 19,139 $ 12,899 $ 6,050 $ 25,313
Income before Income Taxes----------- $ 11,182 $ 3,562 $ 11,265 $ 19,660
Income Tax Provision (Benefit)------- (705) (3,690) 4,856 (2,708)
Net Income--------------------------- $ 11,887 $ 7,252 $ 6,409 $ 22,368
Earnings Per Share of Common
Stock------------------------------ $ .16 $ .10 $ .08 $ .29
Average Number of Common Shares------ 75,900 75,900 75,900 75,900
F-28
SCHEDULE V
ENRON OIL & GAS COMPANY
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
BALANCE AT OTHER BALANCE AT
BEGINNING ADDITIONS CHANGES END
CLASSIFICATION OF YEAR AT COST RETIREMENTS ADD (DEDUCT)(A) OF YEAR
1993
Oil and Gas Properties--------------- $ 2,475,371 $ 383,064 $ 55,617 $ (30,598) $ 2,772,220
1992
Oil and Gas Properties--------------- $ 2,228,634 $ 362,403 $ 80,242 $ (35,424) $ 2,475,371
1991
Oil and Gas Properties--------------- $ 2,065,999 $ 211,673 $ 38,339 $ (10,699) $ 2,228,634
(a) Includes, among other things, amortized impairments of unproved oil and
gas properties and foreign currency translation adjustments.
S-1
SCHEDULE VI
ENRON OIL & GAS COMPANY
SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION
AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
ADDITIONS
BALANCE AT CHARGED TO OTHER BALANCE AT
BEGINNING COSTS AND CHANGES END
CLASSIFICATION OF YEAR EXPENSES RETIREMENTS ADD (DEDUCT) OF YEAR
1993
Oil and Gas Properties--------------- $ 1,007,360 $ 249,704 $ 26,818 $ (4,071) $ 1,226,175
1992
Oil and Gas Properties--------------- $ 888,968 $ 179,839 $ 52,681 $ (8,766) $ 1,007,360
1991
Oil and Gas Properties--------------- $ 760,863 $ 160,885 $ 30,802 $ (1,978) $ 888,968
S-2
SCHEDULE VIII
ENRON OIL & GAS COMPANY
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
ADDITIONS DEDUCTIONS
BALANCE AT CHARGED TO FOR PURPOSE FOR BALANCE AT
BEGINNING OF COSTS AND WHICH RESERVES END OF
DESCRIPTION YEAR EXPENSES WERE CREATED YEAR
1993
Reserves deducted from assets to
which they apply -
Revaluation of Accounts
Receivable--------------------- $ - $ 1,020 $ - $ 1,020
Litigation Reserve(a)---------------- $ 2,030 $ 2,520 $ 2,550 $ 2,000
1992
Reserves deducted from assets to
which they apply -
Revaluation of Accounts
Receivable--------------------- $ 5,656 $ 600 $ 6,256 $ -
Litigation Reserve(a)---------------- $ 1,082 $ 2,194 $ 1,246 $ 2,030
1991
Reserves deducted from assets to
which they apply -
Revaluation of Accounts
Receivable--------------------- $ 4,796 $ 2,600 $ 1,740 $ 5,656
Litigation Reserve(a)---------------- $ 1,400 $ 1,200 $ 1,518 $ 1,082
(a) Included in Other Liabilities on the consolidated balance sheets.
S-3
SCHEDULE X
ENRON OIL & GAS COMPANY
SCHEDULE X -- SUPPLEMENTAL INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(IN THOUSANDS)
COLUMN A COLUMN B
CHARGED TO EXPENSES
ITEM 1993 1992 1991
Maintenance and repairs-------------- $ 8,198 $ 7,169 $ 7,107
Taxes, other than payroll and income
taxes
Property-------------------------- $ 12,525 $ 11,488 $ 6,401
Production/Severance-------------- 19,578 11,985 9,262
Franchise------------------------- 563 2,788 575
Other----------------------------- 107 32 124
Total-------------------------- $ 32,773 $ 26,293 $ 16,362
S-4
EXHIBITS
Exhibits not incorporated herein by reference to a prior filing are
designated by an asterisk (*) and are filed herewith; all exhibits not so
designated are incorporated herein by reference to the Company's Form S-1
Registration Statement, Registration No. 33-30678, filed on August 24, 1989
('Form S-1'), or as otherwise indicated.
3.1(a) - Restated Certificate of Incorporation of Enron Oil & Gas Company
(Exhibit 3.1 to Form S-1).
3.1(b) - Certificate of Amendment of Restated Certificate of Incorporation of
Enron Oil & Gas Company (Exhibit 4.1(b) to Form S-8 Registration
Statement, Registration No. 33-52201, filed on February 8, 1994).
3.2* - Bylaws of Enron Oil & Gas Company.
3.3 - Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to Form
S-1).
4.1 - Promissory Note due May 1, 1996, dated May 1, 1991 (Exhibit 4.1 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1991).
4.2 - There have not been filed as exhibits to this Form 10-K debt instruments
defining the rights of holders of long-term debt of the Company, none of
which relates to authorized indebtedness that exceeds 10% of the
consolidated assets of the Company and its subsidiaries. The Company
hereby agrees to furnish a copy of any such instrument to the Commission
upon request.
4.3 - Enron Oil & Gas Company 1994 Stock Plan (Exhibit 4.1(b) to Form S-8
Registration Statement No. 33-52201, filed on February 8, 1994).
10.1* - Services Agreement, dated as of January 1, 1994, between Enron Oil & Gas
Company and Enron Corp.
10.2 - Stock Restriction and Registration Agreement dated as of August 23, 1989
(Exhibit 10.2 to Form S-1).
10.3 - Tax Allocation Agreement dated as of August 23, 1989 (Exhibit 10.3 to
Form S-1), and First Amended and Restated Tax Allocation Agreement dated
as of August 9, 1991, as amended on February 6, 1992 (Exhibit 10.3 to
Form S-1 Registration Statement, Registration No. 33-50462, filed on
August 5, 1992).
10.4 - Enron Corp. Deferral Plan dated December 10, 1985 (Exhibit 10.12 to Form
S-1).
10.5 - Enron Corp. 1988 Stock Plan (Exhibit 10.13 to Form S-1).
10.6 - Enron Oil & Gas Company Key Contributor Incentive Plan (Exhibit 10.6 to
the Company's Annual Report on Form 10-K for the year ended December 31,
1990).
10.7 - Enron Corp. 1984 Stock Option Plan (Exhibit 10.15 to Form S-1).
10.8 - Enron Corp. 1986 Stock Option Plan (Exhibit 10.16 to Form S-1).
10.9 - Employment Agreement between Enron Oil & Gas Company and Forrest
Hoglund, dated as of September 1, 1987, as amended (Exhibit 10.19 to
Form S-1), and Second and Third Amendments to Employment Agreement dated
June 30, 1989 and February 14, 1992, respectively (Exhibit 10.10 to Form
S-1 Registration Statement, Registration No. 33-50462, filed on August
5, 1992).
10.10 - Fuel Supply Contract, dated as of June 30, 1986, by and between Enron
Oil & Gas Company, HNG Oil Company, BelNorth Petroleum Corporation and
Enron Cogenration One Company, as amended (Exhibit 10.23 to Form S-1).
10.11 - Gas Sales Contract dated September 2, 1987 between Enron Oil & Gas Com-
pany and Cogenron Inc., as amended (Exhibit 10.24 to Form S-1).
E-1
10.12 - Letter Agreement dated August 20, 1987 between Enron Oil & Gas Company
and Panhandle Gas Company (Exhibit 10.25 to Form S-1).
10.13 - Pension Program for Enron Corp. Deferral Plan Participants, effective
January 1, 1985, as amended (Exhibit 10.29 to Form S-1).
10.14 - Enron Oil & Gas Company 1993 Nonemployee Director Stock Option Plan
(Exhibit 10.14 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1992).
10.15* - Credit Agreement, dated as of March 11, 1994, among Enron Oil & Gas
Company, the Banks named therein and Texas Commerce Bank, National
Association, as Administrative Agent and Promissory Note due January 15,
1998, dated March 11, 1994 to the order of Texas Commerce Bank National
Association, Promissory Note due January 15, 1998, dated March 11, 1994
to the order of The Bank of New York, Promissory Note due January 15,
1998, dated March 11, 1994 to the order of The Bank of Nova Scotia,
Promissory Note due January 15, 1998, dated March 11, 1994 to the order
of Credit Lyonnais Cayman Islands Branch, Promissory Note due January
15, 1998, dated March 11, 1994 to the order of Credit Suisse, Promissory
Note due January 15, 1998, dated March 11, 1994 to the order of The
First National Bank of Chicago, and Promissory Note due January 15,
1998, dated March 11, 1994 to the order of Bank of America National
Trust and Savings Association.
10.16* - Interest Rate and Currency Exchange Agreement, dated as of June 1, 1991,
between Enron Risk Management Services Corp. and Enron Oil & Gas Market-
ing, Inc. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1991), Confirmation dated June 14, 1992
(Exhibit 10.17 to Form S-1 Registration Statement, Registration No.
33-50462, filed on August 5, 1992) and Confirmations dated March 25,
1991, April 25, 1991, and September 23, 1992 (assigned to Enron Risk
Management Services Corp. by Enron Finance Corp. pursuant to an
Assignment and Assumption Agreement, dated as of November 1, 1993, by
and between Enron Finance Corp., Enron Risk Management Services Corp.
and Enron Oil & Gas Marketing, Inc.).
10.17* - Assignment and Assumption Agreement, dated as of November 1, 1993, by
and between Enron Oil & Gas Marketing, Inc., Enron Oil & Gas Company and
Enron Risk Management Services Corp.
10.18* - ISDA Master Agreement, dated as of November 1, 1993, between Enron Oil &
Gas Company and Enron Risk Management Services Corp., and Confirmation
Nos. 1268.0, 1286.0, 1291.0, 1292.0, 1304.0, 1305.0, 1321.0, 1335.0,
1338.0, 1370.0, 1471.0, 1485.0, 1486.0, 1494.0, 1495.0, 1509.0, 1514.0,
1533.01, 1569.0, 1986.0, 2217.0, 2227.0, 2278.0, 2299.0, 2372.0, 2647.0.
10.19 - Letter Agreement between Colorado Interstate Gas Company and Enron Oil &
Gas Marketing, Inc. dated November 1, 1990 (Exhibit 10.18 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1990).
10.20 - Gathering Agreement between Enron Oil & Gas Company and Northwest
Pipeline Corporation dated March 30, 1989, as amended (Exhibit 10.36 to
Form S-1).
10.21 - Processing Agreement between Enron Oil & Gas Company and Northwest
Pipeline Corporation dated March 30, 1989 (Exhibit 10.37 to Form S-1).
10.22 - Gas Sales Agreement between Enron Gas Marketing, Inc. and Enron Oil &
Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.38 to Form S-1).
10.23 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil &
Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.41 to Form S-1).
10.24 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil &
Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.42 to Form S-1).
10.25 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Corp. Annual Report
on Form 10-K for the year ended December 31, 1991).
10.26 - Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to Form S-1).
E-2
10.27 - Form of Enron Corp. Long-Term Incentive Plan Effective as of January 1,
1987 (Exhibit 10.50 to Form S-1).
10.28 - Enron Executive Supplemental Survivor Benefits Plan Effective January 1,
1987 (Exhibit 10.51 to Form S-1).
10.29 - 1988 FlexPerq Program Summary (Exhibit 10.52 to Form S-1).
10.30 - Credit Agreement between Enron Corp. and Enron Oil & Gas Company dated
September 29, 1992 (Exhibit 10.28 to the Company's Annual Report on Form
10-K for the year ended December 31, 1992).
10.31 - Credit Agreement between Enron Oil & Gas Company and Enron Corp. dated
September 29, 1992 (Exhibit 10.29 to the Company's Annual Report on Form
10-K for the year ended December 31, 1992).
10.33 - Swap Agreement between Banque Paribas and Enron Oil & Gas Company, dated
as of December 5, 1990 (Exhibit 10.37 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1990), and Confirmations dated
March 25, 1991 and April 25, 1991 (Exhibit 10.37 to Form S-1
Registration Statement, Registration No. 33-50462, filed on August 5,
1992).
10.34 - Enron Oil & Gas Company 1992 Stock Plan (Exhibit 10.40 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1991).
10.35 - Enron Corp. 1992 Deferral Plan (Exhibit 10.41 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1991).
10.36(a) - Conveyance of Production Payment, dated September 25, 1992, between
Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited
Partnership (Exhibit 10.34 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1992).
10.36(b)* - First Amendment to Conveyance of Production Payment, dated effective
April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon
1992-A Limited Partnership.
10.36(c)* - Second Amendment to Conveyance of Production Payment, dated effective
July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon
1992-A Limited Partnership.
10.36(d)* - Third Amendment to Conveyance of Production Payment, dated effective
October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon
1992-A Limited Partnership.
10.37* - Fourth Amendment to Hydrocarbon Exchange Agreement, dated effective
October 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon
1992-A Limited Partnership.
10.38 - Purchase and Sale Agreement, dated September 25, 1992, between Enron Oil
& Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit
10.36 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1992).
10.39(a) - Production and Delivery Agreement, dated September 25, 1992, between
Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited
Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1992).
10.39(b)* - First Amendment to Production and Delivery Agreement, dated effective
April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon
1992-A Limited Partnership.
10.39(c)* - Second Amendment to Production and Delivery Agreement, dated effective
July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon
1992-A Limited Partnership.
E-3
10.39(d)* - Third Amendment to Production and Delivery Agreement, dated effective
October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon
1992-A Limited Partnership.
10.40* - Credit Agreement, dated as of March 8, 1994 between Enron Gas & Oil
Trinidad Limited and Caribbean Regional Development Investment Trust,
and Request for Advance No. 1, dated March 4, 1993, and Request for
Advance No. 2, dated March 4, 1993.
10.41* - Promissory Note due May 1, 1998, dated as of March 8, 1994, to the order
of Caribbean Regional Development Investment Trust.
10.42* - Promissory Note due May 1, 1998, dated as of March 8, 1994 to the order
of Caribbean Regional Development Investment Trust.
10.43* - Letter of Credit and Reimbursement Agreement, dated March 8, 1994,
between Enron Gas & Oil Trinidad Limited and Credit Suisse.
10.44* - Parent Guaranty, dated March 8, 1994 between Enron Oil & Gas Company and
Credit Suisse.
22* - List of subsidiaries.
23.1* - Consent of DeGolyer and MacNaughton.
23.2* - Opinion of DeGolyer and MacNaughton dated January 27, 1994.
24* - Powers of Attorney.
E-4
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, ON THE 18TH DAY OF
MARCH, 1994.
ENRON OIL & GAS COMPANY
(REGISTRANT)
By /s/ WALTER C. WILSON
(WALTER C. WILSON)
SENIOR VICE PRESIDENT AND CHIEF
FINANCIAL OFFICER
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BY THE FOLLOWING PERSONS ON BEHALF OF REGISTRANT AND IN
THE CAPACITIES WITH ENRON OIL & GAS COMPANY INDICATED AND ON THE 18TH DAY OF
MARCH, 1994.
SIGNATURE TITLE
/s/ FORREST E. HOGLUND Chairman of the Board, President and
(FORREST E. HOGLUND) Chief Executive Officer and Director
(Principal Executive Officer)
/s/ WALTER C. WILSON Senior Vice President and Chief
(WALTER C. WILSON) Financial Officer
(Principal Financial Officer)
/s/ BEN B. BOYD Vice President and Controller
(BEN B. BOYD) (Principal Accounting Officer)
FRED C. ACKMAN * Director
(FRED C. ACKMAN)
RICHARD D. KINDER * Director
(RICHARD D. KINDER)
KENNETH L. LAY * Director
(KENNETH L. LAY)
EDWARD RANDALL, III * Director
(EDWARD RANDALL, III)
*By /s/ ANGUS H. DAVIS
(ANGUS H. DAVIS)
(ATTORNEY-IN-FACT FOR PERSONS INDICATED)