ENRON OIL & GAS CO, 424B1, 1999-08-11

ENRON OIL & GAS CO
424B1, 1999-08-11
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

FILED PURSUANT TO RULE 424(B)(1)
REGISTRATION NO. 333-83533
333-84913

[ENRON LOGO] APPENDIX A

ENRON OIL & GAS COMPANY

Common Stock

----------------------

This prospectus relates to up to 11,500,000 shares of our common stock
which may be delivered by Enron Corp. upon mandatory exchange of the 7%
Exchangeable Notes due July 31, 2002 of Enron Corp. This prospectus is Appendix
A to a prospectus of Enron Corp. covering the sale of the Exchangeable Notes. We
will not receive any of the proceeds from the sale of the Exchangeable Notes or
the delivery by Enron Corp. of its shares of our common stock upon exchange of
the Exchangeable Notes at maturity.

Enron Oil & Gas Company concurrently is offering 27,000,000 shares of its
common stock and Enron Corp. is offering 4,000,000 shares of EOG's common stock
with a separate prospectus.

The common stock is listed on the New York Stock Exchange under the symbol
"EOG". The last reported sale price of the common stock on August 10, 1999 was
$22.375 per share.

Enron Corp. is offering concurrently, in a separate public offering with a
separate prospectus 10,000,000 (11,500,000 if the underwriters in that offering
fully exercise their over-allotment option) Exchangeable Notes, which are
mandatorily exchangeable into shares of EOG common stock currently owned by
Enron Corp. The offering of EOG common stock and the concurrent offering of
Exchangeable Notes by Enron Corp. are not conditioned on each other.

Consider carefully the risk factors beginning on page 10 of this
prospectus.

----------------------

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY
BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ACCURACY
OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL
OFFENSE.

----------------------

Prospectus dated August 10, 1999.
<PAGE> 2

ENRON OIL & GAS COMPANY
[MAP}

- -------------------------
*NATURAL GAS EQUIVALENT DAILY PRODUCTION AT DECEMBER 31, 1998.

OIL AND GAS TERMS

<TABLE>
<S> <C> <C>
When describing commodities
produced and sold: gas = natural gas
oil = crude oil
liquids = crude oil, condensate and natural gas liquids
When describing natural gas: Mcf = thousand cubic feet
MMcf = million cubic feet
Bcf = billion cubic feet
MMBtu = million British Thermal Units
When describing oil: Bbl = barrel
MBbl = thousand barrels
MMBbl = million barrels
When comparing oil to natural gas: 1 Bbl of oil = 6 Mcf of natural gas equivalent
Mcfe = thousand cubic feet equivalent
MMcfe = million cubic feet equivalent
Bcfe = billion cubic feet equivalent
</TABLE>

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<PAGE> 3

PROSPECTUS SUMMARY

This summary highlights selected information we have included or
incorporated by reference in this prospectus. However, it does not contain all
information that may be important to you. More detailed information about this
offering, our business and our financial and operating data is contained
elsewhere in this prospectus. We encourage you to read this prospectus in its
entirety before making an investment decision.

In this prospectus, we refer to Enron Oil & Gas Company and its
subsidiaries as "we", "us", "our" or "EOG" unless the context clearly indicates
otherwise.

ABOUT EOG

EOG is one of the largest independent exploration and production companies
in the United States. We explore for and produce natural gas and oil in almost
every major producing basin in the United States and Canada and internationally
in India and Trinidad and, to a lesser extent, selected other areas.

SHARE EXCHANGE WITH ENRON CORP.

On July 20, 1999, EOG and Enron Corp. announced an agreement to exchange
62,270,000 shares of our common stock out of 82,270,000 shares currently owned
by Enron Corp. for all the stock of our subsidiary, EOGI-India, Inc. Prior to
the Share Exchange, we will make an indirect $600,000,000 cash capital
contribution, plus certain intercompany receivables, to EOGI-India, Inc. At the
time of completion of this transaction, this subsidiary will own, through
subsidiaries, all of our assets and operations in India and China. We expect
this transaction to be tax-free to Enron Corp. and us. We refer to this
transaction elsewhere in this prospectus as the Share Exchange. Some time after
the Share Exchange, we expect to change our corporate name to "EOG Resources,
Inc." and we will make appropriate changes to our subsidiaries' names. See
"Relationship with Enron Corp."

The completion of the Share Exchange is subject to specific conditions and
we currently expect the Share Exchange to close on August 16, 1999. We will use
borrowed funds for the cash capital contribution in connection with the Share
Exchange, and we will repay a portion of those borrowed funds with the net
proceeds of this offering which will close after the Share Exchange, also on
August 16, 1999.

Upon completion of the Share Exchange, all of the directors of EOG who are
affiliated with Enron Corp. will resign from our Board of Directors.

For the complete terms of our agreement with Enron Corp., please refer to
the Share Exchange Agreement between Enron Corp. and us filed as an exhibit to
the registration statement that includes this prospectus.

EOG RESOURCES, INC.

As EOG Resources, Inc., our reserves and production will be predominantly
comprised of natural gas, and will be primarily located in North America. On a
pro forma basis, 77% of our total reserves will be located in, and 85% of our
production will be derived from, the United States or Canada, with natural gas
comprising 87% of total production, on a natural gas equivalent basis as of or
for the year ended December 31, 1998.

After giving effect to the Share Exchange, at December 31, 1998, our
estimated total net proved reserves included:

- 4,294 Bcf of gas, including:

- 1,180 Bcf of proved undeveloped methane reserves in the Big Piney deep
Paleozoic formations in Wyoming and

- 61 MMBbl of liquids.
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<PAGE> 4

After giving effect to the Share Exchange, at December 31, 1998,

- 66% of our reserves (on a natural gas equivalent basis) was located in
the United States

- 11% in Canada and

- 23% in Trinidad.

After giving effect to the Share Exchange, for the year ended December 31,
1998 our delivered volumes (on a natural gas equivalent basis) were

- 282 Bcfe in the United States,

- 46 Bcfe in Canada and

- 57 Bcfe in Trinidad.

BUSINESS STRATEGY

Our strategy is to maximize the return on invested capital by achieving
operating and finding costs that are among the lowest in the industry. We are
focused on growing our domestic natural gas reserves and production by
concentrating our efforts in known North American reserve basins. We focus on
selected international opportunities where we can successfully apply our core
competencies in the exploitation of reserves. Our strategy is intended to
enhance the generation of cash flow and earnings from each unit of production on
a cost effective basis.

Our North American operations are organized into seven largely autonomous
business units, each focusing on a basin or basins, utilizing personnel who have
developed experience and expertise unique to the geology of the region, thereby
leveraging our knowledge and cost structure into enhanced returns on invested
capital.

We focus our drilling activity toward natural gas deliverability in
addition to natural gas reserve enhancement and to a lesser extent crude oil
exploitation. We also focus on the cost-effective utilization of advances in
technology associated with gathering, processing and interpretation of 3-D
seismic data, developing reservoir simulation models and drilling operations
through the use of new and/or improved drill bits, mud motors, mud additives,
formation logging techniques and reservoir fracturing methods. These advanced
technologies are used, as appropriate, throughout the company to reduce the
risks associated with all aspects of oil and gas reserve exploration,
exploitation and development.

We implement our strategy by emphasizing the drilling of internally
generated prospects in order to find and develop low cost reserves. We also make
selected tactical acquisitions that give us additional economies of scale or
land positions with significant additional prospects. Achieving and maintaining
the lowest possible operating cost structure are also important goals in the
implementation of our strategy.

Consistent with our desire to optimize the use of our assets, we also sell
selected oil and gas properties that for various reasons may no longer fit into
future operating plans or which we believe do not have sufficient future growth
potential. We do this when we believe the economic value to be obtained by
selling the properties and reserves in the ground is greater than what we would
obtain by holding the properties and producing the reserves over time. As a
result, we typically receive each year a varying but substantial level of
proceeds related to such sales. We use these proceeds for general corporate
purposes.

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<PAGE> 5

RECENT DEVELOPMENTS

We have executed a series of new credit agreements totaling $1.3 billion,
and have simultaneously cancelled our existing credit facilities which totaled
$450 million. Of the $1.3 billion credit facilities, $500 million will expire in
364 days, $400 million is structured as a 364-day revolving credit facility with
a one-year term subsequent to the revolving period, and $400 million is
structured as a 5-year revolving credit facility. The $500 million credit
facility will be cancelled when we receive the proceeds from our offering of
27,000,000 shares of our common stock. If advances have been made under the $500
million credit facility when that offering is completed, such advances will be
repaid and the facility then will be cancelled. These new credit agreements
contain financial covenants which may restrict to some extent our ability to
incur additional indebtedness. However, we do not believe these covenants to be
materially restrictive given current market conditions.

On July 21, 1999, two stockholders of EOG filed separate lawsuits
purportedly on behalf of EOG against Enron Corp. and EOG's directors, alleging
that Enron Corp. and EOG's directors breached their fiduciary duties of good
faith and loyalty in approving the Share Exchange. The lawsuits seek to
temporarily and permanently enjoin the Share Exchange and seek compensatory
damages and costs and expenses, including reasonable attorneys' and experts'
fees. EOG, Enron Corp. and the EOG directors believe the lawsuits are without
merit and intend to vigorously contest them.

As a result of the change to our portfolio of assets subsequent to the
Share Exchange, we are currently re-evaluating our overall business. We expect
to complete this re-evaluation by the end of third quarter 1999. As a result of
this re-evaluation, some of our current projects may no longer be deemed central
to our business. In that case, we may incur non-cash charges in connection with
the disposition of such projects of up to approximately $75 million, after-tax.

5
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[THIS PAGE INTENTIONALLY LEFT BLANK]

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<PAGE> 7
SUMMARY OF HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table sets forth our summary selected historical financial
and operating data as of and for each of the three years in the period ended
December 31, 1998 and the six-month periods ended June 30, 1998 and 1999 and our
pro forma financial and operating data as of and for the year ended December 31,
1998 and the six-month period ended June 30, 1999. This information should be
read in conjunction with our consolidated financial statements and the related
notes incorporated by reference in this prospectus (see "Where You Can Find More
Information") and our condensed consolidated pro forma financial statements and
the related notes included elsewhere in this prospectus. Financial information
for each of the three years in the period ended December 31, 1998 has been
derived from audited financial statements. Financial information for the
six-month periods ended June 30, 1998 and 1999 has been derived from unaudited
financial statements. The interim data reflects all adjustments which, in the
opinion of our management, are necessary to present fairly such information for
the interim periods. Results of the six-month periods are not necessarily
indicative of the results expected for a full year or any other interim period.
The unaudited condensed consolidated pro forma information is for informational
purposes only, and does not necessarily represent what our actual results of
operations would have been had the Share Exchange occurred on the dates
indicated under "Unaudited Condensed Consolidated Pro Forma Financial
Information".

<TABLE>
<CAPTION>
PRO FORMA
PRO FORMA SIX MONTHS ENDED SIX MONTHS
YEAR ENDED DECEMBER 31, YEAR ENDED JUNE 30, ENDED
---------------------------------- DECEMBER 31, ---------------------- JUNE 30,
1996 1997 1998 1998 1998 1999 1999
-------- -------- -------- ------------ -------- -------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF INCOME DATA:
Net operating revenues........ $730,648 $783,501 $769,188 $696,351 $383,138 $346,149 $305,880
Operating expenses
Lease and well............... 76,618 96,064 98,868 87,749 47,766 47,607 40,462
Exploration costs............ 55,009 57,696 65,940 63,408 33,998 27,091 25,444
Dry hole costs............... 13,193 17,303 22,751 22,751 10,162 2,475 2,475
Impairment of unproved oil
and gas properties......... 21,226 27,213 32,076 32,076 15,703 15,987 15,987
Depreciation, depletion and
amortization............... 251,278 278,179 315,106 305,786 145,032 170,803 164,992
General and administrative... 56,405 54,415 69,010 57,967 31,758 50,019 39,486
Taxes other than income...... 48,089 59,856 51,776 45,161 27,764 26,076 21,774
-------- -------- -------- -------- -------- -------- --------
Total.................. 521,818 590,726 655,527 614,898 312,183 340,058 310,620
-------- -------- -------- -------- -------- -------- --------
Operating income (loss)....... 208,830 192,775 113,661 81,453 70,955 6,091 (4,740)
Other income (expense), net... (5,007) (1,588) (4,800) 306 (1,043) 58,290(1) 59,217(1)
Interest expense (net of
interest capitalized)........ 12,861 27,717 48,579 56,990 19,533 29,041 33,009
-------- -------- -------- -------- -------- -------- --------
Income before income taxes.... 190,962 163,470 60,282 24,769 50,379 35,340 21,468
Income tax provision
(benefit)(2)................. 50,954(3) 41,500(4) 4,111(5) (7,944)(5) 10,117(6) 9,636(7)(8) 5,325(7)(8)
-------- -------- -------- -------- -------- -------- --------
Net income.................... $140,008 $121,970 $ 56,171 $ 32,713 $ 40,262 $ 25,704 $ 16,143
======== ======== ======== ======== ======== ======== ========
Net income per share of common
stock
Basic........................ $ 0.88 $ 0.78 $ 0.36 $ 0.27 $ 0.26 $ 0.17 $ 0.14
======== ======== ======== ======== ======== ======== ========
Diluted...................... $ 0.87 $ 0.77 $ 0.36 $ 0.27 $ 0.26 $ 0.17 $ 0.13
======== ======== ======== ======== ======== ======== ========
Average number of common
shares
Basic........................ 159,853 157,376 154,345 119,075 154,797 153,779 118,509
======== ======== ======== ======== ======== ======== ========
Diluted...................... 161,525 158,160 155,054 119,784 155,646 154,943 119,673
======== ======== ======== ======== ======== ======== ========
</TABLE>

7
<PAGE> 8

<TABLE>
<CAPTION>
PRO FORMA
AT DECEMBER 31, AT AT
------------------------------------ JUNE 30, JUNE 30,
1996 1997 1998 1999 1999
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Oil and gas properties - net........................... $2,099,589 $2,387,207 $2,676,363 $2,666,848 $2,424,696
Total assets........................................... 2,458,353 2,723,355 3,018,095 2,962,046 2,649,103
Long-term debt
Trade................................................ 466,089 548,775 942,779 1,073,883 1,123,883
Affiliate............................................ - 192,500 200,000 66,000 66,000
Deferred revenue....................................... 56,383 39,918 4,198 2,099 2,099
Shareholders' equity................................... 1,265,090 1,281,049 1,280,304 1,310,044 1,013,582
</TABLE>

<TABLE>
<CAPTION>
PRO FORMA
SIX
YEAR ENDED PRO FORMA SIX MONTHS MONTHS
DECEMBER 31, YEAR ENDED ENDED JUNE 30, ENDED
------------------------ DECEMBER 31, --------------- JUNE 30,
1996 1997 1998 1998 1998 1999 1999
------ ------ ------ ------------- ------ ------ ---------
<S> <C> <C> <C> <C> <C> <C> <C>
OPERATING DATA:
Wellhead Volumes and Prices
Natural Gas Volumes (MMcf per day).............. 830 889 971 915 904 982 908
Average Natural Gas Prices ($/Mcf).............. $ 1.78 $ 2.07 $ 1.78 $ 1.74 $ 1.87 $ 1.67 $ 1.65
Crude/Condensate Volumes (MBbl per day)......... 19.6 19.9 24.7 19.6 22.3 25.1 18.4
Average Crude/Condensate Prices ($/Bbl)......... $20.60 $19.30 $12.66 $12.61 $13.82 $13.04 $13.49
</TABLE>

- ---------------

(1) Includes a gain of $60 million related to the sale of options held by EOG to
purchase 3.2 million shares of Enron Corp. common stock.

(2) Includes benefits of approximately $16 million, $12 million, $12 million,
$12 million, $4 million, $3 million and $3 million in the year ended
December 31, 1996, 1997, 1998 and 1998 (pro forma), and the six-month period
ended June 30, 1998, 1999 and 1999 (pro forma), respectively, relating to
tight gas sand federal income tax credits.

(3) Includes a benefit of $9 million primarily associated with a reassessment of
deferred tax requirements and the successful resolution on audit of Canadian
income taxes for certain prior years.

(4) Includes a benefit of $15 million primarily associated with the refiling of
certain Canadian tax returns and the sale of certain international assets
and subsidiaries.

(5) Includes a benefit of $2 million related to the final audit assessments of
India taxes for certain prior years, a benefit of $4 million related to
reduced deferred franchise taxes, and $4 million related to Venezuela
deferred tax benefits.

(6) Includes a benefit of $8 million related to certain international costs and
the resolution of certain state and international issues.

(7) Federal income taxes accrued in the six-month interim periods are calculated
using the estimated annual effective income tax rate.

(8) Includes a benefit of $4 million related to anticipated disposition of
certain international assets.

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<PAGE> 9

SUMMARY OF HISTORICAL AND PRO FORMA OIL AND GAS RESERVE INFORMATION

The following table sets forth summary information with respect to EOG's
estimates of its net proved natural gas, crude oil, condensate and natural gas
liquids reserves at December 31, 1998. For additional information relating to
reserves, see "Business -- Oil and Gas Exploration and Production Properties and
Reserves".

<TABLE>
<CAPTION>
NATURAL GAS
EQUIVALENTS (BCFE)
GAS LIQUIDS -------------------------------
(BCF) (MBBL) DEVELOPED UNDEVELOPED TOTAL
----- --------- --------- ----------- -----
<S> <C> <C> <C> <C> <C>
HISTORICAL:
Net proved reserves at
December 31, 1998:
United States........................ 2,854(1) 36,827 1,628 1,446(1) 3,074(1)
Canada............................... 464 7,592 432 78 510
Trinidad............................. 976 16,204 312 762 1,074
India................................ 825 42,785 608 473 1,081
Other................................ 110 1,162 - 117 117
----- ------- ----- ----- -----
Total........................... 5,229 104,570 2,980 2,876 5,856
===== ======= ===== ===== =====
</TABLE>

<TABLE>
<CAPTION>
NATURAL GAS
EQUIVALENTS (BCFE)
GAS LIQUIDS -------------------------------
(BCF) (MBBL) DEVELOPED UNDEVELOPED TOTAL
------- --------- --------- ----------- -----
<S> <C> <C> <C> <C> <C>
PRO FORMA:
Net proved reserves at
December 31, 1998, as adjusted(2):
United States......................... 2,854(1) 36,827 1,628 1,446(1) 3,074(1)
Canada................................ 464 7,592 432 78 510
Trinidad.............................. 976 16,204 312 762 1,074
----- ------- ----- ----- -----
Total............................ 4,294 60,623 2,372 2,286 4,658
===== ======= ===== ===== =====
</TABLE>

- ---------------

(1) Includes 1,180 Bcf of methane reserves in the Big Piney deep Paleozoic
formations in Wyoming.

(2) Adjusted to reflect the effect of the Share Exchange.

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<PAGE> 10

RISK FACTORS

In considering whether to purchase shares of our common stock, you should
carefully consider the risk factors described below and all the information we
have included or incorporated by reference in this prospectus. In addition,
please read "Cautionary Statement Regarding Forward-Looking Statements" on page
15 of this prospectus, where we describe uncertainties associated with our
business and the forward-looking statements included or incorporated by
reference in this prospectus.

A SUBSTANTIAL OR EXTENDED DECLINE IN OIL OR GAS PRICES WOULD HAVE A MATERIAL
ADVERSE EFFECT ON US.

Prices for natural gas and oil fluctuate widely. For example, natural gas
and oil prices declined significantly in 1998 and, for an extended period of
time, remained substantially below prices obtained in previous years. Since we
are primarily a natural gas company, we are more significantly affected by
changes in natural gas prices than changes in the prices for crude oil,
condensate or natural gas liquids. Among the factors that can cause these price
fluctuations are:

- the level of consumer demand,

- weather conditions,

- price and availability of alternative fuels,

- domestic drilling activity and

- overall economic conditions.

During 1995, 1996, 1997 and 1998, the high and low prices for natural gas and
oil on the twelve-month forward NYMEX strip were:

The average North America wellhead natural gas prices we received increased
43% from 1995 to 1996 and 15% from 1996 to 1997, while the average North America
wellhead natural gas prices we realized from 1997 to 1998 decreased by 15%.
Wellhead natural gas volumes from the Trinidad SECC Block are sold at prices
that are based on a fixed schedule with periodic escalations. No formal contract
has been entered into regarding future production of proved reserves from the
Trinidad U(a) Block. 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, we are unable to predict what changes may occur in
natural gas prices in the future.

We sell substantially all of our wellhead crude oil and condensate under
various terms and arrangements at market responsive prices. Crude oil and
condensate prices also have fluctuated during the last three years. Due to the
many uncertainties associated with the world political environment, the
availabilities of other worldwide energy supplies and the relative competitive
relationships of the various energy sources in the view of the consumers, the
level of consumer demand and the availability of alternative fuels, we are
unable to predict what changes may occur in crude oil and condensate prices in
the future.

Our cash flow and earnings depend to a great extent on the prevailing
prices for natural gas and oil. Prolonged or substantial declines in these
commodity prices may adversely affect our liquidity, the amount of cash flow
available for capital expenditures and our ability to maintain our credit
quality and access to the credit and capital markets.

OUR ABILITY TO SELL OUR OIL AND GAS PRODUCTION COULD BE MATERIALLY HARMED IF WE
FAIL TO OBTAIN ADEQUATE SERVICES SUCH AS TRANSPORTATION AND PROCESSING.

The sale of our oil and gas production depends on a number of factors
beyond our control, including the availability and capacity of transportation
and processing facilities. Our failure to obtain such services on acceptable
terms could materially harm our business.

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<PAGE> 11

THE OIL AND GAS RESERVES DATA AND FUTURE NET REVENUES ESTIMATES WE REPORT ARE
UNCERTAIN.

Estimates of reserves by necessity are projections based on engineering
data, the projection of future rates of production and the timing of future
expenditures. Estimates of our proved oil and gas reserves and projected future
net revenues are based on reserve reports which we prepare and a portion of
which are reviewed by independent petroleum engineers. The process of estimating
oil and gas reserves requires substantial judgment on the part of the petroleum
engineers, resulting in imprecise determinations, particularly with respect to
new discoveries. Different reserve engineers may make different estimates of
reserve quantities and revenues attributable thereto based on the same data.
Future performance that deviates significantly from the reserve reports could
have a material adverse effect on us. The accuracy of any reserve estimate
depends on the quality of the available data as well as engineering and
geological interpretation and judgment. Results of drilling, testing and
production and changes in the assumptions regarding decline and production
rates, the ability to market oil and gas that is produced, oil and gas prices,
revenues, taxes, capital expenditures, operating expenses, geologic success and
quantities of recoverable oil and gas may vary substantially from those assumed
in the estimates, may result in revisions to such estimates and could materially
affect the estimated quantities and related value of reserves. The estimates of
future net revenues reflect oil and gas prices as of the date of estimation,
without escalation or reduction. Fluctuations in the price of natural gas and
oil have the effect of significantly altering reserve estimates as the economic
projections inherent in the estimates may reduce or increase the quantities of
recoverable reserves. There can be no assurance, however, that such prices will
be realized or that the estimated production volumes will be produced during the
periods indicated. Actual future production, natural gas and oil prices,
revenues, taxes, development expenditures, operating expenses and quantities of
recoverable natural gas and oil reserves most likely will vary from our
estimates.

IF WE FAIL TO ACQUIRE OR FIND ADDITIONAL RESERVES, OUR RESERVES AND PRODUCTION
WILL DECLINE MATERIALLY FROM THEIR CURRENT LEVELS.

The rate of production from oil and gas properties generally declines as
reserves are depleted. Except to the extent that we acquire additional
properties containing proved reserves, conduct successful exploration and
development activities or, through engineering studies, identify additional
behind-pipe zones or secondary recovery reserves, our proved reserves will
decline materially as reserves are produced. Future oil and gas production is,
therefore, highly dependent upon our level of success in acquiring or finding
additional reserves.

WE INCUR CERTAIN COSTS TO COMPLY WITH GOVERNMENT REGULATIONS, ESPECIALLY
REGULATIONS RELATING TO ENVIRONMENTAL PROTECTION, AND COULD INCUR EVEN GREATER
COSTS IN THE FUTURE.

Our exploration, production and marketing operations are regulated
extensively at the federal, state and local levels, as well as by other
countries in which we do business. We have made and will continue to make
expenditures in our efforts to comply with the requirements of environmental and
other regulations. Further, the oil and gas regulatory environment could change
in ways that might substantially increase these costs.

Hydrocarbon-producing states regulate conservation practices and the
protection of correlative rights. These regulations affect our operations and
limit the quantity of hydrocarbons we may produce and sell. In addition, at the
U.S. federal level, the Federal Energy Regulatory Commission regulates
interstate transportation of natural gas under the Natural Gas Act. Other
regulated matters include marketing, pricing, transportation and valuation of
royalty payments.

As an owner or lessee and operator of oil and gas properties, we are
subject to various federal, state, local and foreign regulations relating to
discharge of materials into, and

11
<PAGE> 12

protection of, the environment. These regulations may, among other things,
impose liability on us for the cost of pollution clean-up resulting from
operations, subject us to liability for pollution damages, and require
suspension or cessation of operations in affected areas. Changes in or additions
to regulations regarding the protection of the environment could hurt our
business.

OUR INDUSTRY IS VERY COMPETITIVE.

The oil and gas industry is extremely competitive. This is especially true
with regard to exploration for, and exploitation and development of, new sources
of crude oil and natural gas. As an independent oil and gas company, we
frequently compete against other companies that are larger and financially
stronger in acquiring properties suitable for exploration, in contracting for
drilling equipment and other services and in securing trained personnel.

WE DO NOT INSURE AGAINST ALL POTENTIAL LOSSES AND COULD BE SERIOUSLY HARMED BY
UNEXPECTED LIABILITIES.

Exploration for and production of oil and gas can be hazardous, involving
natural disasters and other unforeseen occurrences such as blowouts, cratering,
fires and loss of well control, which can damage or destroy wells or production
facilities, injure or kill people, and damage property and the environment.
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. We maintain insurance against many, but not all,
potential losses or liabilities arising from our operations in accordance with
customary industry practices and in amounts that we believe to be prudent.
Losses and liabilities arising from such events could reduce our revenues and
increase our costs to the extent not covered by insurance.

The occurrence of any of the aforementioned events and any payments made as
a result of such events and the liabilities related thereto, would reduce the
funds available for exploration, drilling and production and could have a
material adverse effect on our financial position or results of operations.

OUR HEDGING ACTIVITIES MAY PREVENT US FROM BENEFITING FROM PRICE INCREASES AND
MAY EXPOSE US TO OTHER RISKS.

We engage in price risk management activities from time to time primarily
for non-trading and to a lesser extent for trading purposes. We use derivative
financial instruments (primarily price swaps and costless collars) for
non-trading purposes to hedge the impact of market fluctuations on natural gas
and crude oil market prices and net income and cash flow.

To the extent that we engage in hedging activities, we may be prevented
from realizing the benefits of price increases above the levels of the hedges.
In addition, we are subject to risks associated with differences in prices at
different locations, particularly where transportation constraints restrict our
ability to deliver oil and gas volumes to the delivery point to which the
hedging transaction is indexed.

Further, hedging contracts are subject to the risk that the other party may
prove unable or unwilling to perform its obligations under such contracts. Any
significant nonperformance could adversely affect us financially.

WHEN WE ACQUIRE OIL AND GAS PROPERTIES, OUR FAILURE TO FULLY IDENTIFY POTENTIAL
PROBLEMS, TO PROPERLY ESTIMATE RESERVES OR PRODUCTION RATES OR COSTS, OR TO
EFFECTIVELY INTEGRATE THE ACQUIRED OPERATIONS COULD SERIOUSLY HARM US.

We from time to time acquire oil and gas properties. When we do so, our
failure to fully identify potential problems, to properly estimate reserves or
production rates or costs, or to effectively integrate the acquired operations
could seriously harm us. Although we perform reviews of acquired properties that
we believe are consistent with industry practices, we do not review in depth
every individual property involved in each acquisition. Ordinarily we focus on
higher-value properties and sample the remainder.

12
<PAGE> 13

However, even a detailed review of records and properties may not necessarily
reveal existing or potential problems, nor will it permit a buyer to become
sufficiently familiar with the properties to assess fully their deficiencies and
potential. Inspections may not always be performed on every well, and
environmental problems, such as ground water contamination, are not necessarily
observable even when an inspection is undertaken.

Even when problems are identified, we often assume environmental and other
risks and liabilities in connection with acquired properties. There are numerous
uncertainties inherent in estimating quantities of proved oil and gas reserves
and actual future production rates and associated costs with respect to acquired
properties. Actual results may vary substantially from those assumed in the
estimates. In addition, acquisitions may have adverse effects on our operating
results, particularly during the periods in which the operations of acquired
businesses are being integrated into our ongoing operations.

OUR NON-U.S. OPERATIONS ARE SUBJECT TO RISKS OF DOING BUSINESS ABROAD.

Our non-U.S. oil and natural gas exploration, exploitation, development and
production activities are subject to certain political and economic risks
including, among others:

- cancellation or renegotiation of contracts;

- disadvantages of competing against companies from countries that are not
subject to U.S. laws and regulations, including the Foreign Corrupt
Practices Act;

- changes in foreign laws or regulations;

- changes in tax laws;

- royalty and tax increases;

- retroactive tax claims;

- expropriation or nationalization of property;

- currency fluctuations;

- foreign exchange controls;

- import and export regulations;

- environmental controls;

- risks of loss due to civil strife, acts of war, guerilla activities and
insurrection; and

- other risks arising out of foreign governmental sovereignty over the
areas in which our operations are conducted.

Consequently, our non-U.S. exploration, exploitation, development and
production activities may be substantially affected by factors beyond our
control, any of which could materially adversely affect our financial position
or results of operations. Furthermore, in the event of a dispute arising from
non-U.S. operations, we may be subject to the exclusive jurisdiction of courts
outside the United States or may not be successful in subjecting non-U.S.
persons to the jurisdiction of the courts in the United States, which could
adversely affect the outcome of the dispute.

A DECLINE IN THE CONDITION OF THE CAPITAL MARKETS OR A SUBSTANTIAL RISE IN
INTEREST RATES COULD HARM US.

If the condition of the capital markets utilized by us to finance our
operations materially declines, we might not be able to finance our operations
on terms we consider acceptable. In addition, a substantial rise in interest
rates would decrease our net cash flows available for reinvestment.

OUR COMPUTER SYSTEMS OR OTHER ASSETS USED IN OUR OPERATIONS AND THOSE OF THIRD
PARTIES MAY NOT BE YEAR 2000 COMPLIANT, WHICH MAY CAUSE SYSTEM FAILURES AND
DISRUPTIONS IN OPERATIONS.

The inability of some computer programs and embedded computer chips to
distinguish between the year 1900 and the year 2000 poses a serious threat of
business disruption to any organization that uses computer technology and
computer chip technology in their business systems or equipment. Each major
business unit has been required to

13
<PAGE> 14

inventory and assess the risk associated with hardware, software,
telecommunications systems, office equipment, embedded chip controls and
systems, process control systems, facility control systems and dependencies on
external mission critical entities.

We presently believe that, with updates to software that are substantially
complete or well under way, conversions to new software and completion of
efforts planned by each major business unit to update imbedded microprocessors,
the risk associated with year 2000 will be significantly reduced. However, we
are unable to assure that the consequences of year 2000 failures of systems
maintained by us or by third parties will not materially adversely impact our
results of operations or financial condition. More detailed information about
the year 2000 risks and our efforts to address this issue is contained in our
Annual Report on Form 10-K for the year ended December 31, 1998, as amended by
Amendment No. 1 on Form 10-K/A, and our Quarterly Report on Form 10-Q for the
three-month and six-month periods ended June 30, 1999, both of which are
incorporated by reference into this prospectus.

14
<PAGE> 15

CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

This prospectus and the documents incorporated by reference contain
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All
statements other than statements of historical facts, including, among others,
statements regarding our future financial position, business strategy, budgets,
reserve information, projected levels of production, projected costs and plans
and objectives of management for future operations, are forward-looking
statements.

We typically use words such as "expect", "anticipate", "estimate",
"strategy", "intend", "plan" and "believe" or the negative of those terms or
other variations of them or by comparable terminology to identify our
forward-looking statements. In particular, statements, express or implied,
concerning future operating results or the ability to generate income or cash
flows are forward-looking statements.

Although we believe our expectations reflected in forward-looking
statements are based on reasonable assumptions, no assurance can be given that
these expectations will be achieved. Important factors that could cause actual
results to differ materially from the expectations reflected in the
forward-looking statements include, among others:

- timing and extent of changes in commodity prices for crude oil, natural
gas and related products and interest rates;

- extent of our success in discovering, developing, marketing and producing
reserves and in acquiring oil and gas properties;

- successful implementation of our Year 2000 Plan, the effectiveness of our
Year 2000 Plan, and the Year 2000 readiness of outside entities;

- political developments around the world; and

- financial market conditions.

Some of these factors are discussed under "Risk Factors" beginning on page
10 of this prospectus.

In light of these risks, uncertainties and assumptions, the events
anticipated by our forward-looking statements might not occur. We undertake no
obligation to update or revise our forward-looking statements, whether as a
result of new information, future events or otherwise.

USE OF PROCEEDS

We expect the net proceeds from the offering of common stock by EOG to be
approximately $577.7 million after deducting discounts to the underwriters and
estimated expenses of the offering that we will pay. We expect to use the net
proceeds from the offering of common stock to repay a portion of the
indebtedness incurred in connection with the Share Exchange to fund a cash
capital contribution to our subsidiaries that conduct our India and China
operations. The pending Share Exchange with Enron Corp. is discussed in
"Prospectus Summary -- Share Exchange With Enron Corp." We will not receive any
proceeds from the sale of our common stock by Enron Corp. or the underwriters'
exercise of the over-allotment option.

15
<PAGE> 16

CAPITALIZATION

The following table sets forth as of June 30, 1999:

- Our actual capitalization;

- Our as-adjusted capitalization showing the effects of our receipt of the
estimated net proceeds from the sale of the shares we are selling in the
concurrent offering of 27,000,000 shares of our common stock assuming
that the net proceeds are used to repay outstanding commercial paper,
bank debt and advances from affiliates; and

- Our pro forma as-adjusted capitalization showing the effects of

- our receipt of the estimated net proceeds from the sale of the shares
we are selling in this offering; and

- our receipt of 62,270,000 shares of our common stock currently owned
by Enron Corp. in exchange for all the stock of our subsidiary,
EOGI-India, Inc. after we have made, indirectly, a $600,000,000 cash
capital contribution and a contribution of receivables due from
subsidiaries of EOGI-India, Inc. as of June 30, 1999, funded in part
from borrowings under a new credit facility.

The as-adjusted capitalization and the pro forma as-adjusted capitalization
assume that the net proceeds from the offering of the common stock are used to
make capital contributions to our subsidiaries that conduct our India and China
operations in connection with the pending Share Exchange. If the Share Exchange
has already taken place when the offering is completed, the net proceeds would
be used to repay a portion of the indebtedness incurred to fund such capital
contribution.

<TABLE>
<CAPTION>
JUNE 30, 1999
--------------------------------------
PRO FORMA
ACTUAL AS ADJUSTED AS ADJUSTED
---------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Long-term debt
Company:
Commercial paper and bank debt............ $ 293,643 $ - $ 343,643
Notes due 2004 (6.50%).................... 100,000 100,000 100,000
Notes due 2006 (6.70%).................... 150,000 150,000 150,000
Notes due 2007 (6.50%).................... 100,000 100,000 100,000
Notes due 2008 (6.00%).................... 175,000 175,000 175,000
Notes due 2028 (6.65%).................... 150,000 150,000 150,000
Subsidiary companies:
Notes due 2001 (floating)................. 105,000 105,000 105,000
Other..................................... 240 240 240
Affiliates(1)................................ 66,000 - 66,000
---------- ---------- ----------
Total long-term debt................. 1,139,883 780,240 1,189,883
Shareholders' equity
Common stock................................. 201,600 201,870 201,870
Additional paid in capital................... 401,042 978,512 978,512
Unearned compensation........................ (4,183) (4,183) (4,183)
Cumulative foreign currency translation
adjustment................................ (26,124) (26,124) (26,124)
Retained earnings............................ 854,846 854,846 1,366,152
Common stock held in treasury................ (117,137) (117,137) (1,502,645)
---------- ---------- ----------
Total shareholders' equity........... 1,310,044 1,887,784 1,013,582
---------- ---------- ----------
Total capitalization................. $2,449,927 $2,668,024 $2,203,465
========== ========== ==========
</TABLE>

(1) Subsequent to June 30, 1999, we have repaid the advances from affiliates,
and there are currently no amounts outstanding.
16
<PAGE> 17

PRICE RANGE OF COMMON STOCK AND CASH DIVIDENDS

The following table sets forth, for the periods indicated, the high and low
sales prices per share for our common stock, as reported on the New York Stock
Exchange Composite Tape, and the amount of cash dividends paid per share.

<TABLE>
<CAPTION>
PRICE RANGE
---------------- CASH
HIGH LOW DIVIDENDS
------ ------ ---------
<S> <C> <C> <C>
1997
First Quarter....................................... $27.00 $19.88 $0.03
Second Quarter...................................... 21.75 17.50 0.03
Third Quarter....................................... 25.06 17.69 0.03
Fourth Quarter...................................... 23.81 18.50 0.03
1998
First Quarter....................................... $24.13 $18.56 $0.03
Second Quarter...................................... 24.50 18.13 0.03
Third Quarter....................................... 20.69 11.75 0.03
Fourth Quarter...................................... 18.50 12.69 0.03
1999
First Quarter....................................... $18.38 $15.69 $0.03
Second Quarter...................................... 21.50 16.00 0.03
Third Quarter(through August 10, 1999).............. 25.19 19.25 0.03
</TABLE>

As of July 1, 1999, there were approximately 430 record holders of our
common stock, including individual participants in security position listings.
There are an estimated 20,000 beneficial owners of our common stock, including
shares held in street name.

We currently intend to continue to pay quarterly cash dividends on the
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, our financial condition, funds from operations, level of
exploration, exploitation and development expenditure opportunities and future
business prospects of EOG.

17
<PAGE> 18

ENRON OIL & GAS COMPANY

UNAUDITED CONDENSED CONSOLIDATED PRO FORMA FINANCIAL INFORMATION

The following unaudited condensed consolidated pro forma statements of
income for the year ended December 31, 1998 and the six months ended June 30,
1999, give effect to the offering and the Share Exchange as described below, as
though they occurred on January 1, 1998. The unaudited condensed consolidated
pro forma balance sheet at June 30, 1999 gives effect to the offering and the
Share Exchange as though they occurred on June 30, 1999.

The unaudited condensed consolidated pro forma statements of income and
balance sheet have been prepared based upon our historical consolidated
statements of income and balance sheet of EOG included in our Annual Report on
Form 10-K for the year ended December 31, 1998, as amended by Amendment No. 1 on
Form 10-K/A, and our Quarterly Report on Form 10-Q for the three-month and
six-month periods ended June 30, 1999, both of which are incorporated by
reference in this prospectus and have been prepared based upon available
information and assumptions that our management believes are reasonable. The
unaudited condensed consolidated pro forma statements of income are for
informational purposes only, and do not necessarily represent what our actual
results of operations would have been had the offering and the Share Exchange
occurred on January 1, 1998. The unaudited condensed consolidated pro forma
balance sheet is for informational purposes only, and does not purport to
represent our actual financial position had the offering and the Share Exchange
occurred on June 30, 1999. In addition, the unaudited condensed consolidated pro
forma financial statements are not necessarily indicative of our future results
of operations or financial position and should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements of EOG and the related
notes included in our Annual Report on Form 10-K for the year ended December 31,
1998, as amended by Amendment No. 1 on Form 10-K/A, and our Quarterly Report on
Form 10-Q for the three-month and six-month periods ended June 30, 1999, both of
which are incorporated by reference in this prospectus.

18
<PAGE> 19

UNAUDITED CONDENSED CONSOLIDATED PRO FORMA STATEMENT OF INCOME
FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 1999
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS AS ADJUSTED
---------- ----------- -----------
<S> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas
Trade......................................... $244,775 $(25,920)(a) $218,855
Associated Companies(h)....................... 41,094 41,094
Crude Oil, Condensate and Natural Gas Liquids
Trade......................................... 63,257 (14,349)(a) 48,908
Associated Companies(h)....................... 1,259 1,259
Losses on Sales of Reserves and Related Assets
and Other, Net................................ (4,236) (4,236)
-------- -------- --------
Total.................................... 346,149 (40,269) 305,880
OPERATING EXPENSES
Lease and Well................................... 47,607 (7,145)(a) 40,462
Exploration Costs................................ 27,091 (1,647)(a) 25,444
Dry Hole Costs................................... 2,475 2,475
Impairment of Unproved Oil and Gas Properties.... 15,987 15,987
Depreciation, Depletion and Amortization......... 170,803 (5,811)(a) 164,992
General and Administrative....................... 50,019 (10,533)(a) 39,486
Taxes Other Than Income.......................... 26,076 (4,302)(a) 21,774
-------- -------- --------
Total.................................... 340,058 (29,438) 310,620
-------- -------- --------
OPERATING INCOME (LOSS)............................ 6,091 (10,831) (4,740)
OTHER INCOME, NET.................................. 58,290 927(a) 59,217
-------- -------- --------
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES.... 64,381 (9,904) 54,477
INTEREST EXPENSE
Incurred
Trade......................................... 35,208 1,868(b) 37,076
Affiliate(h).................................. 139 139
Capitalized...................................... (6,306) 2,100(a) (4,206)
-------- -------- --------
Net Interest Expense.......................... 29,041 3,968 33,009
-------- -------- --------
INCOME BEFORE INCOME TAXES......................... 35,340 (13,872) 21,468
INCOME TAX PROVISION............................... 9,636 (3,657)(a) 5,325
(654)(b)
-------- -------- --------
NET INCOME......................................... $ 25,704 $ (9,561) $ 16,143
======== ======== ========
NET INCOME PER SHARE OF COMMON STOCK
Basic............................................ $ 0.17 $ 0.14
======== ========
Diluted.......................................... $ 0.17 $ 0.13
======== ========
AVERAGE NUMBER OF COMMON SHARES
Basic............................................ 153,779 118,509
======== ========
Diluted.......................................... 154,943 119,673
======== ========
</TABLE>

The following notes are an integral part of these condensed consolidated pro
forma financial statements.

19
<PAGE> 20

UNAUDITED CONDENSED CONSOLIDATED PRO FORMA STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL ADJUSTMENTS AS ADJUSTED
---------- ----------- -----------
<S> <C> <C> <C>
NET OPERATING REVENUES
Natural Gas
Trade............................................ $558,376 $(48,722)(a) $509,654
Associated Companies(h).......................... 62,929 62,929
Crude Oil, Condensate and Natural Gas Liquids
Trade............................................ 120,366 (24,115)(a) 96,251
Associated Companies(h).......................... 9,266 9,266
Gains on Sales of Reserves and Related Assets and
Other, Net....................................... 18,251 18,251
-------- -------- --------
Total....................................... 769,188 (72,837) 696,351
OPERATING EXPENSES
Lease and Well...................................... 98,868 (11,119)(a) 87,749
Exploration Costs................................... 65,940 (2,532)(a) 63,408
Dry Hole Costs...................................... 22,751 22,751
Impairment of Unproved Oil and Gas Properties....... 32,076 32,076
Depreciation, Depletion and Amortization............ 315,106 (9,320)(a) 305,786
General and Administrative.......................... 69,010 (11,043)(a) 57,967
Taxes Other Than Income............................. 51,776 (6,615)(a) 45,161
-------- -------- --------
Total....................................... 655,527 (40,629) 614,898
-------- -------- --------
OPERATING INCOME...................................... 113,661 (32,208) 81,453
OTHER INCOME (EXPENSE), NET........................... (4,800) 5,106(a) 306
-------- -------- --------
INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES....... 108,861 (27,102) 81,759
INTEREST EXPENSE
Incurred
Trade............................................ 60,701 (99)(a) 65,134
4,532(b)
Affiliate(h)..................................... 589 589
Capitalized......................................... (12,711) 3,978(a) (8,733)
-------- -------- --------
Net Interest Expense............................. 48,579 8,411 56,990
-------- -------- --------
INCOME BEFORE INCOME TAXES............................ 60,282 (35,513) 24,769
INCOME TAX PROVISION (BENEFIT)........................ 4,111 (10,469)(a) (7,944)
(1,586)(b)
-------- -------- --------
NET INCOME............................................ $ 56,171 $(23,458) $ 32,713
======== ======== ========
NET INCOME PER SHARE OF COMMON STOCK
Basic............................................... $ 0.36 $ 0.27
======== ========
Diluted............................................. $ 0.36 $ 0.27
======== ========
AVERAGE NUMBER OF COMMON SHARES
Basic............................................... 154,345 119,075
======== ========
Diluted............................................. 155,054 119,784
======== ========
</TABLE>

The following notes are an integral part of these condensed consolidated pro
forma financial statements.

20
<PAGE> 21

UNAUDITED CONDENSED CONSOLIDATED PRO FORMA BALANCE SHEET
AT JUNE 30, 1999
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
ADDITIONAL EXCHANGE OF
BORROWINGS TRANSFERRED
AND EQUITY SUBSIDIARIES OTHER
HISTORICAL ISSUANCE SHARES ADJUSTMENTS AS ADJUSTED
----------- ---------- ------------ ----------- -----------
<S> <C> <C> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents.................. $ 11,411 $ 45,400(b) $ (606,287)(d) $(13,355)(f) $ 7,759
577,740(c) (10,000)(e) 2,850(g)
Accounts Receivable
Trade.................................... 159,469 (59,139)(d) 100,330
Associated Companies(h).................. 12,795 12,795
Inventories................................ 35,175 (10,058)(d) 25,117
Other...................................... 6,420 (1,354)(d) 5,066
----------- -------- ----------- -------- -----------
Total................................ 225,270 623,140 (686,838) (10,505) 151,067
OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS
METHOD).................................... 4,965,113 (262,085)(d) 4,703,028
Less: Accumulated Depreciation, Depletion
and Amortization......................... (2,298,265) 19,933(d) (2,278,332)
----------- -------- ----------- -------- -----------
Net Oil and Gas Properties........... 2,666,848 (242,152) 2,424,696
OTHER ASSETS................................. 69,928 4,600(b) (1,188)(d) 73,340
----------- -------- ----------- -------- -----------
TOTAL ASSETS................................. $ 2,962,046 $627,740 $ (930,178) $(10,505) $ 2,649,103
=========== ======== =========== ======== ===========

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable
Trade.................................... $ 119,664 $ (29,898)(d) $ 89,766
Associated Companies(h).................. 41,014 (8,352)(f) 32,662
Accrued Taxes Payable...................... 16,465 (1,685)(d) 29(f) 14,809
Dividends Payable.......................... 4,736 4,736
Other...................................... 17,608 (9,090)(d) 1,000(g) 9,518
----------- -------- ----------- -------- -----------
Total................................ 199,487 (40,673) (7,323) 151,491
LONG-TERM DEBT
Trade...................................... 1,073,883 50,000(b) 1,123,883
Affiliate.................................. 66,000 66,000
OTHER LIABILITIES
Trade...................................... 19,004 1,850(g) 20,854
Associated Companies(h).................... 26,085 (8,352)(f) 17,733
DEFERRED INCOME TAXES........................ 265,444 (15,499)(d) 3,516(f) 253,461
DEFERRED REVENUES............................ 2,099 2,099
SHAREHOLDERS' EQUITY
Common Stock, $.01 Par, 320,000,000 Shares
Authorized and 160,000,000 Shares Issued
Historical and 187,000,000 Shares Pro
Forma.................................... 201,600 270(c) 201,870
Additional Paid In Capital................. 401,042 577,470(c) 978,512
Unearned Compensation...................... (4,183) (4,183)
Cumulative Foreign Currency Translation
Adjustment............................... (26,124) (26,124)
Retained Earnings.......................... 854,846 521,502(d) (196)(f) 1,366,152
(10,000)(e)
Common Stock Held in Treasury, 6,104,863
Shares Historical and 68,374,863 Shares
Pro Forma................................ (117,137) (1,385,508)(d) (1,502,645)
----------- -------- ----------- -------- -----------
Total Shareholders' Equity........... 1,310,044 577,740 (874,006) (196) 1,013,582
----------- -------- ----------- -------- -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY... $ 2,962,046 $627,740 $ (930,178) $(10,505) $ 2,649,103
=========== ======== =========== ======== ===========
</TABLE>

The following notes are an integral part of these condensed consolidated pro
forma financial statements.

21
<PAGE> 22

NOTES TO UNAUDITED CONDENSED CONSOLIDATED
PRO FORMA FINANCIAL STATEMENTS

The following pro forma adjustments give effect to the sale by us of
27,000,000 shares of our common stock in this offering, additional borrowings of
$50.0 million under new revolving credit facilities executed on July 28, 1999,
and the Share Exchange (see note (a)), as though these transactions occurred on
January 1, 1998 for income statement purposes, and give effect to these
transactions as though they occurred on June 30, 1999 for balance sheet
purposes. Our historical results were derived from our historical financial
statements included in our Annual Report on Form 10-K for the year ended
December 31, 1998, as amended by Amendment No. 1 on Form 10-K/A, and our
Quarterly Report on Form 10-Q for the three-month and six-month periods ended
June 30, 1999, both of which are incorporated by reference in this prospectus.

(a) To reflect the elimination of the historical results of operations of
EOGI-India, Inc., Enron Oil & Gas India Ltd., EOGI China Company, Enron
Oil & Gas China Ltd., EOGI-China, Inc. and Enron Oil & Gas China
International Ltd. (collectively referred to as the "Transferred
Subsidiaries"), all wholly owned subsidiaries of EOG. All of EOG's
interest in the common shares of each of the Transferred Subsidiaries
is to be transferred to Enron Corp. in exchange for 62,270,000 shares
of our common stock owned by Enron Corp. pursuant to a share exchange
agreement (the "Share Exchange").

(b) To reflect the borrowing of $50.0 million under a new revolving credit
facility. Borrowings are assumed to be at 6.0% per annum, plus the
amortization of commitment fees of $4.6 million ($1.5 million for 1998
and $0.4 million for the six months ended June 30, 1999). Commitment
fees are deferred as "Other Assets" and are amortized over the related
commitment or loan period, as applicable.

(d) To reflect the elimination of the balances of the Transferred
Subsidiaries and the receipt of 62,270,000 shares of our common stock
pursuant to the Share Exchange. The shares of our common stock received
are reflected at their estimated fair market value on the date of the
transfer and a gain is reflected for the difference between the fair
market value of our shares of common stock received and our historical
cost basis in the Transferred Subsidiaries. The estimated fair market
value is based on an assumed market price per share of $22.250. The
actual market price per share on the date of the Share Exchange may
differ significantly from our estimate. Prior to the Share Exchange EOG
will contribute to the transferred subsidiaries $600.0 million in the
form of cash capital contributions plus contributions of net
intercompany accounts receivable of $173.2 million at June 30, 1999.
The actual balance of net intercompany accounts receivable on the date
of the Share Exchange may differ significantly from the balance at June
30, 1999. The Share Exchange is in the form of a non-taxable exchange
of shares; accordingly, no income taxes have been provided with respect
to the recognized gain.

(e) To reflect $10.0 million of transaction costs directly related to the
Share Exchange. As noted in footnote(d), the Share Exchange is in the
form of a non-taxable exchange of shares; accordingly, such transaction
costs are not deductible for income tax purposes.

(f) To reflect a net payment of $13.4 million from EOG to Enron Corp. to
settle amounts payable to Enron Corp. and other income tax related
issues, which were resolved as part of the Share Exchange and the
termination of the Tax Sharing Agreement, as amended, between EOG and
Enron Corp.

22
<PAGE> 23

(g) To reflect the payment by Enron Corp. of $1.9 million and the
assumption by EOG of a liability of the same amount related to certain
unvested benefit obligations under an Enron Corp. Cash Balance Plan and
the payment by Enron Corp. of $1.0 million and the assumption by EOG of
a liability of the same amount related to employee medical
reimbursement accounts concurrent with the loss of control of EOG by
Enron Corp.

(h) Associated companies and affiliate balances result from transactions
with Enron Corp., its subsidiaries or affiliates. If as a result of the
offering and the Share Exchange, Enron Corp.'s ownership of our common
stock declines to a level that Enron Corp. accounts for its investment
in EOG on the cost method, any balances with associated companies or
affiliates would be reclassified as trade.

23
<PAGE> 24

BUSINESS

GENERAL

Enron Oil & Gas Company, a Delaware corporation organized in 1985, together
with its subsidiaries, explores, develops, produces and markets, natural gas and
crude oil primarily in major producing basins in the United States, as well as
in Canada and Trinidad and, to a lesser extent, selected other international
areas. Our principal producing areas are further described under "Exploration
and Production" below. At December 31, 1998, our estimated net proved natural
gas reserves were 5,229 Bcf, including 1,180 Bcf of proved undeveloped methane
reserves in the Big Piney deep Paleozoic formations, and estimated net proved
crude oil, condensate and natural gas liquids reserves were 105 MMBbl. (See
"-- Oil and Gas Exploration and Production Properties and Resources".) After
giving effect to the Share Exchange, at December 31, 1998 our estimated net
proved reserves would have been 4,294 Bcf of gas and 61 MMBbl of oil. After
giving effect to the Share Exchange at December 31, 1998, 66% of our reserves,
on a natural gas equivalent basis, was located in the United States, 11% in
Canada and 23% in Trinidad.

BUSINESS STRATEGY

With respect to information on our 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 our working interest in the wells or acreage. Unless
otherwise defined, all references to wells are gross.

BUSINESS SEGMENTS

Our operations are all oil and gas exploration and production related. We
have not included a discussion of our India and China operations since they will
be transferred to Enron Corp. in connection with the Share Exchange.

EXPLORATION AND PRODUCTION

NORTH AMERICA OPERATIONS

United States. Our eight principal United States producing areas are the
Big Piney area of Wyoming, South Texas area, East Texas area, Offshore Gulf of
Mexico area, Canyon/ Strawn Trend area of West Texas, Sand Tank and Pitchfork
Ranch areas of New Mexico and Vernal area of Utah. Properties in these areas
represented approximately 81% of our United States reserves (on a natural gas
equivalent basis) and 82% of our United States net natural gas deliverability as
of December 31, 1998. We operate substantially all of these properties.

Our other United States oil and gas producing properties are located
primarily in other areas of Texas, Utah, New Mexico, Oklahoma, California,
Mississippi and Kansas.

At December 31, 1998, 93% of our proved United States reserves, including
the reserves in the Big Piney deep Paleozoic formations in Wyoming (on a natural
gas equivalent basis), was natural gas and 7% was crude oil, condensate and
natural gas liquids. A substantial portion of our United States natural gas
reserves is in long-lived fields with well-established production histories. We
believe that opportunities exist to increase production in many of these fields
through continued infill and other development drilling.

Big Piney Area. Our largest reserve accumulation is located in the Big
Piney area in Sublette and Lincoln counties in southwestern Wyoming. We are the
holder of the largest productive acreage base in this area, with approximately
280,000 net acres under lease directly within field limits. We operate
approximately 800 natural gas and crude oil wells in this area in which we own
an 85% average working interest. Deliveries from the area net to us averaged 118
MMcf per day of natural gas and 4.0 MBbl per day of crude oil, condensate, and
natural gas liquids in 1998. At December 31, 1998, natural gas deliverability
net to us was approximately 110 MMcf per day.

The current principal producing intervals are the Almy, Mesaverde and
Frontier formations. The Frontier formation, which occurs at 6,500 to 10,000
feet, contains approximately 64% of our Big Piney proved developed reserves. We
drilled 44 wells in the Big Piney area in 1998 and we plan to drill 50 wells
during 1999.

We have recorded as proved undeveloped reserves 1,180 Bcf of methane
contained, along with high concentrations of carbon dioxide as well as small
amounts of other gaseous substances, in the deep Wyoming Paleozoic (Madison)
formation located under acreage we hold by production in the Big Piney area. In
January 1999, we acquired certain adjacent Madison formation producing interests
that include the rights to an agreement covering the processing of natural gas
from such adjacent interests from the Madison formation through an existing
plant operated by another company in the industry.

South Texas Area. Our activities in South Texas are focused in the Lobo,
Wilcox and Frio producing horizons. The principal areas of activity are in the
Lobo and Wilcox Trends which occur primarily in Webb, Zapata and Duval counties,
as well as the Frio Trend in Matagorda County.

In Matagorda County, we completed two wells in 1998, each with a rate of 40
MMcf per day of natural gas and 2.0 MBbl per day of condensate. At December 31,
1998, we operated approximately 420 wells in the South Texas area, and
production is primarily from the Frio, Wilcox and Lobo sands at

25
<PAGE> 26

depths ranging from 5,000 to 16,000 feet. We have approximately 273,000 net
leasehold acres and more than 40,000 net mineral fee acres in this area. Natural
gas deliveries net to us averaged approximately 162 MMcf per day in 1998. At
December 31, 1998, natural gas deliverability from this area net to us was
approximately 182 MMcf per day. We drilled 47 wells in the South Texas area in
1998, acquired 758 square miles of new 3-D seismic and leased 64,500 net acres.
We plan to drill 54 wells in 1999 and plan to maintain an active drilling
program in South Texas for several years.

East Texas Area. Our activities in the East Texas area are primarily in the
Carthage field, located in Panola County, the North Milton field, located in
northern Harris County, and the Stowell/Big Hill area, located in Jefferson and
Chambers Counties.

The Carthage field production is primarily from the Cotton Valley, Travis
Peak and Pettit formations. At December 31, 1998, we held approximately 17,900
net acres under lease with an average 74% working interest in this area. We
drilled 29 wells in the Carthage area in 1998 and we anticipate drilling 15
wells in this area during 1999. We have continued our activity in the North
Milton area where we now operate 30 wells and hold a 100% working interest in
the acreage. We expect to drill three additional wells during 1999. We drilled
10 wells in the Stowell/Big Hill area in 1998, and we are continuing expansion
of the program in 1999. Net deliveries from the East Texas area averaged 56.4
MMcf per day of natural gas and 2.3 MBbl per day of crude oil, condensate and
natural gas liquids in 1998. At December 31, 1998, deliverability from the area
was approximately 80 MMcf per day of natural gas with 2.0 MBbl per day of crude
oil, condensate and natural gas liquids both net to us.

Offshore Gulf of Mexico Area. During 1998, we made a significant
acquisition on the Outer-Continental Shelf of the Gulf of Mexico, purchasing a
19% working interest in the Matagorda Island 623 field which increased our
natural gas deliveries, adding 55 MMcf per day net to us. Development of the
Eugene Island 135 discovery continued with a third development well increasing
our net field production to 17 MMcf per day and 760 barrels of condensate per
day. At December 31, 1998, we held an interest in 184 blocks in the Offshore
Gulf of Mexico area totaling approximately 544,000 net acres. Of these 184
blocks, located predominantly in federal waters offshore Texas and Louisiana, we
operate 127. Natural gas deliveries from this area averaged 116 MMcf per day
during 1998 net to us. A substantial portion of such deliveries was from
interests in the Matagorda Island and Mustang Island areas of offshore Texas
with significant volumes also coming from Eugene Island 135. During 1998, we
participated in the drilling of 10 wells (3.9 net wells) in the Gulf of Mexico.
In 1999, we anticipate participating in the drilling of four to six wells.

Canyon/Strawn Trend Area. Our activities in this area have been
concentrated in Crockett, Terrell and Val Verde Counties in Texas where we
drilled 21 natural gas wells during 1998. We hold approximately 66,000 net acres
and now operate approximately 350 natural gas wells in this area in which we own
a 90% average working interest. Production is from the Canyon sands and Strawn
limestone at depths from 5,500 to 12,500 feet. At December 31, 1998, natural gas
deliverability net to us was approximately 35 MMcf per day.

Sand Tank Area. The Sand Tank area located in Eddy County, New Mexico
produces from the Chester, Morrow, and Atoka formations. Natural gas deliveries
for 1998 averaged 16 MMcf per day and deliveries of crude oil, condensate and
natural gas liquids averaged .3 MBbl per day in 1998 both net to us. At year end
1998, deliverability, net to us, was approximately 15 MMcf per day of natural
gas and .2 MBbl per day of crude oil, condensate and natural gas liquids. We
hold 14,000 net acres and have an average working interest of approximately 60%.
In 1999, we plan to drill four wells in this stacked-pay area.

Pitchfork Ranch Area. The Pitchfork Ranch area located in Lea County, New
Mexico, produces primarily from the

26
<PAGE> 27

Bone Spring, Wolfcamp, Atoka and Morrow formations. In 1998, deliveries net to
us averaged 18 MMcf per day of natural gas and approximately 2.0 MBbl per day of
crude oil, condensate and natural gas liquids. At December 31, 1998,
deliverability net to us was approximately 21 MMcf per day of natural gas and
1.8 MBbl per day of crude oil, condensate and natural gas liquids. We hold
approximately 34,000 net acres and are continuing to interpret a 3-D seismic
survey shot over this entire area. We expect to maintain a drilling program in
this area in 1999.

Vernal Area. In the Vernal area, located primarily in Uintah County, Utah,
we operate approximately 305 producing wells and presently control approximately
77,000 net acres. In 1998, natural gas deliveries net to us from the Vernal area
averaged 21 MMcf per day. Deliverability at December 31, 1998, was approximately
26 MMcf per day. Production is from the Green River and Wasatch formations
located at depths between 4,500 and 8,000 feet. We have an average working
interest of approximately 60%. We anticipate numerous drilling opportunities
will be available in this area in 1999.

Canada. We are engaged in the exploration for and the exploitation,
development, production and marketing of natural gas, natural gas liquids and
crude oil in Western Canada, principally in the provinces of Alberta,
Saskatchewan, and Manitoba. We conduct operations from offices in Calgary,
Alberta, and produce natural gas and crude oil from five major areas. The
Sandhills area in southwestern Saskatchewan is the largest single natural gas
producing area in Canada for EOG. In 1998, we drilled 150 wells in the area and
we acquired additional acreage and wells in the area resulting in peak
deliverability of approximately 44 MMcf per day net to us at December 31, 1998.
We plan to drill approximately 223 wells during 1999. At the end of 1999, we
expect to realize 48 MMcf per day net deliverability. The Blackfoot area in
southeastern Alberta is our second largest natural gas producing area in Canada.
In 1998, we drilled 16 new wells and we performed numerous recompletions,
workovers and facility optimizations resulting in deliverability of
approximately 30 MMcf per day and 1.2 MBbl per day of crude oil and condensate
net to us at December 31, 1998. We plan to drill approximately 50 Blackfoot
wells during 1999. As a result, we expect the net deliverability from the
Blackfoot area to increase to 40 MMcf per day at the end of 1999. Total Canadian
natural gas deliverability net to us at December 31, 1998 was approximately 120
MMcf per day, and we held approximately 555,000 net undeveloped acres in Canada.
Total Canadian natural gas deliveries net to us for 1998 averaged approximately
105 MMcf per day.

OUTSIDE NORTH AMERICA OPERATIONS

We have producing operations offshore Trinidad, and are evaluating and
conducting exploration, exploitation and development in selected other
international areas.

Trinidad. In November 1992, we were awarded a 95% working interest
concession in the South East Coast Consortium Block offshore Trinidad,
encompassing three undeveloped fields, previously held by three government-owned
energy companies. We have developed the Kiskadee field. We are developing the
Ibis field and we anticipate that the Oilbird field will be developed over the
next several years. We are using existing surplus processing and transportation
capacity at the Pelican field facilities owned and operated by Trinidad and
Tobago government-owned companies to process and transport the production. We
are selling natural gas into the local market under a take-or-pay agreement with
the National Gas Company of Trinidad and Tobago. In 1998, deliveries net to us
averaged 139 MMcf per day of natural gas, which includes 24 MMcf per day of gas
balancing volumes relating to a field allocation agreement, and 3.0 MBbl per day
of crude oil and condensate.

In 1995, we were awarded the right to develop the modified U(a) block near
the South East Coast Consortium Block. We signed a production sharing contract
with the Government of Trinidad and Tobago in 1996. Under the contract we
committed to the acquisition of 3-D seismic data and the drilling

27
<PAGE> 28

of three wells. The first well was drilled in 1998 and was successful,
encountering over 400 feet of net pay, resulting in the largest exploration
discovery in our history. We estimate the gross proved reserves of the discovery
to be over 600 billion cubic feet equivalent. We expect to drill two significant
exploratory wells in 1999.

At December 31, 1998, we held approximately 144,000 net undeveloped acres
in Trinidad.

Venezuela. We were awarded exploration, exploitation and development rights
for a block offshore the eastern state of Sucre, Venezuela in early 1996. We
signed agreements with the government of Venezuela and other participants
associated with a concession awarded in the Gulf of Paria East. We hold an
initial 90% working interest in the joint venture and act as operator. We
drilled one exploratory well during 1998 and encountered hydrocarbons. We are
continuing to do additional evaluation work.

Other International. We continue to evaluate other selected conventional
natural gas and crude oil opportunities outside North America by pursuing other
exploitation opportunities in countries where indigenous natural gas and crude
oil reserves have been identified. We are also participating in discussions
concerning the potential for natural gas development opportunities in Mozambique
as well as other opportunities in Trinidad and other countries. (See
"Relationship with Enron Corp." for a further discussion of the relationship
between our company and Enron Corp. in the Mozambique project.)

MARKETING

Wellhead Marketing. We currently sell our North America wellhead natural
gas production 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. We sell wellhead natural gas volumes from Trinidad at prices that are
based on a fixed price schedule with annual escalations. We currently sell
approximately 7% of our wellhead natural gas production to pipeline and
marketing subsidiaries of Enron Corp. We believe that the terms of our
transactions and agreements with Enron Corp. are at least as favorable to us as
could be obtained from third parties.

We sell substantially all of our wellhead crude oil and condensate under
various terms and arrangements at market responsive prices. We currently sell
approximately 1% of our wellhead crude oil and condensate production to
subsidiaries of Enron Corp.

Other Marketing. Enron Oil & Gas Marketing, Inc., one of our wholly-owned
subsidiaries, is a marketing company engaging in various marketing activities.
Both we and this subsidiary contract to provide, under short and 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 our own production and arrange
for any necessary transportation to the points of delivery. In addition, this
subsidiary has purchased and constructed several small gathering systems in
order to facilitate its entry into the gathering business on a limited basis.
Both our company and this subsidiary use other short and long-term hedging and
trading mechanisms including sales and purchases utilizing NYMEX-related
commodity market transactions. These marketing activities have provided an
effective balance in managing a portion of our exposure to commodity price risks
for both natural gas and crude oil and condensate wellhead prices. (See
"-- Other Matters -- Risk Management".)

In September 1992, we sold a volumetric production payment for $326.8
million to a limited partnership. Delivery obligations were terminated in
December 1998. (See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Capital Resources and Liquidity -- Sale of
Volumetric Production Payment" included in our Annual Report on Form 10-K for
the year ended December 31, 1998, as amended by Amendment No. 1 on Form 10-K/A,
which is incorporated by reference into this prospectus.)

28
<PAGE> 29

In March 1995, in a series of transactions with Enron Corp., we exchanged
all of our fuel supply and purchase contracts and related price swap agreements
associated with a Texas City cogeneration plant (the "Cogen Contracts") for
certain natural gas price swap agreements (the "Swap Agreements") of equivalent
value. As a result of the transactions, we were relieved of all performance
obligations associated with the Cogen Contracts. We will realize net operating
revenues and receive corresponding cash payments of approximately $91 million
during the period extending through December 31, 1999, under the terms of the
Swap Agreements. The estimated fair value of the Swap Agreements was
approximately $81 million at the date the Swap Agreements were received. The net
effect of this series of transactions has resulted in increases in our net
operating revenues and cash receipts during 1995 and 1996 of approximately $13
million and $7 million, respectively, with offsetting decreases in 1998 and 1999
versus that anticipated under the Cogen Contracts.

29
<PAGE> 30

WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES

The following table sets forth certain information regarding our wellhead
volumes of and average prices for natural gas per Mcf, crude oil and condensate,
and natural gas liquids per Bbl, and average lease and well expenses per Mcfe
delivered during each of the three years in the period ended December 31, 1998
and the six months ended June 30, 1998 and 1999:

<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------ ---------------
1996 1997 1998 1998 1999
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
VOLUMES (PER DAY)
Natural Gas (MMcf)
United States(1)...................................... 608 657 671 634 659
Canada................................................ 98 101 105 99 108
Trinidad.............................................. 124 113 139 121 141
India................................................. - 18 56 50 74
------ ------ ------ ------ ------
Total............................................ 830 889 971 904 982
====== ====== ====== ====== ======
Crude Oil and Condensate (MBbl)
United States......................................... 9.2 11.7 14.0 12.4 13.1
Canada................................................ 2.4 2.5 2.6 2.6 2.7
Trinidad.............................................. 5.2 3.4 3.0 2.8 2.6
India................................................. 2.8 2.3 5.1 4.5 6.7
------ ------ ------ ------ ------
Total............................................ 19.6 19.9 24.7 22.3 25.1
====== ====== ====== ====== ======
Natural Gas Liquids (MBbl)
United States......................................... 1.3 2.6 2.9 2.6 2.7
Canada................................................ 1.2 1.3 1.0 1.1 0.7
------ ------ ------ ------ ------
Total............................................ 2.5 3.9 3.9 3.7 3.4
====== ====== ====== ====== ======
AVERAGE PRICES
Natural Gas ($/Mcf)
United States(2)...................................... $ 2.04 $ 2.32 $ 1.93 $ 2.03 $ 1.80
Canada................................................ 1.15 1.43 1.40 1.40 1.51
Trinidad.............................................. 1.00 1.05 1.06 1.08 1.07
India................................................. - 2.79 2.41 2.63 1.95
Composite........................................ 1.78 2.07 1.78 1.87 1.67
Crude Oil and Condensate ($/Bbl)
United States......................................... $21.88 $19.81 $12.84 $13.90 $13.91
Canada................................................ 18.01 17.16 11.82 12.77 13.03
Trinidad.............................................. 19.76 18.68 12.26 13.66 11.83
India................................................. 20.17 20.05 12.86 14.31 11.80
Composite........................................ 20.60 19.30 12.66 13.82 13.04
Natural Gas Liquids ($/Bbl)
United States......................................... $14.67 $12.76 $ 8.38 $ 9.24 $ 8.15
Canada................................................ 9.14 8.94 5.32 5.48 5.83
Composite........................................ 11.99 11.54 7.56 8.15 7.68
LEASE AND WELL EXPENSES ($/MCFE)
United States........................................... $ .19 $ .23 $ .22 $ .23 $ .20
Canada.................................................. .34 .39 .37 .40 .41
Trinidad................................................ .16 .16 .12 .13 .12
India................................................... .99 .64 .24 .30 .28
Composite........................................ .22 .26 .24 .25 .23
</TABLE>

- ---------------

(1) Includes 48 MMcf per day for the year ended December 31, 1996, 1997 and 1998
and for the six-month period ended June 30, 1998 delivered under the terms
of a volumetric production payment agreement effective October 1, 1992, as
amended. Delivery obligations were terminated in December 1998.

(2) Includes an average equivalent wellhead value of $1.17, $1.73 and $1.53 per
Mcf for the year ended December 31, 1996, 1997 and 1998 and of $1.59 per Mcf
for the six-month period ended June 30, 1998, respectively, for the volumes
described in note (1), net of transportation costs.

30
<PAGE> 31

COMPETITION

We actively compete for reserve acquisitions and exploration/exploitation
leases, licenses and concessions, frequently against companies with
substantially larger financial and other resources. To the extent our
exploration budget is lower than that of certain of our competitors, we 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, we face competition from other producers and suppliers, including
competition from other world wide energy supplies, such as natural gas from
Canada.

OTHER MATTERS

Risk Management. We engage in price risk management activities from time to
time primarily for non-trading and to a lesser extent for trading purposes. We
use derivative financial instruments (primarily price swaps and costless
collars) for non-trading purposes to hedge the impact of market fluctuations of
natural gas and crude oil market prices on net income and cash flow.

At December 31, 1998, we had outstanding crude oil commodity price swap
transactions, designated as hedges, covering approximately 700 MBbl of crude oil
and condensate for 1999. The fair value of the positions was a net revenue
increase of $4 million at December 31, 1998.

At December 31, 1998, based on the portion of our anticipated natural gas
volumes for 1999 for which prices have not, in effect, been hedged using
NYMEX-related commodity market transactions and long-term marketing contracts,
our net income and after-tax cash flow sensitivity to changing natural gas
prices is approximately $18 million for each $.10 per Mcf change in average
wellhead natural gas prices. While we are not affected as significantly by
changing crude oil prices for those volumes not otherwise hedged, our net income
and cash flow sensitivity is approximately $6 million for $1.00 per barrel
change in average wellhead crude oil prices.

Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption. United
States 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 after
November 5, 1990 and 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 $49 per barrel in
current dollars. Significant benefits from the tax credit have accrued and
continue to accrue to us since a portion (and in some cases a substantial
portion) of our natural gas production from wells drilled after November 5,
1990, and before January 1, 1993, on our leases in several of our significant
producing areas qualify for this tax credit.

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 severance taxes, subject to
certain limitations. In 1995, the drilling qualification period was extended
from September 1996 through August 2002, and the tax exemption was modified in a
somewhat reduced form. In 1999, the drilling qualification period was extended
eight years through August 2010.

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<PAGE> 32

OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES

The following table sets forth our net proved and proved developed reserves
at December 31 for each of the four years in the period ended December 31, 1998,
and the changes in the net proved reserves for each of the three years in the
period then ended as estimated by our engineering staff. See "Risk Factors--The
oil and gas reserves data and future net revenues estimates we report are
uncertain".

NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY

<TABLE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL
------------- ------ -------- ------- ----- -------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas(Bcf)
Net proved reserves at December 31, 1995........ 2,654.1(1) 313.9 245.5 75.0 - 3,288.5
Revisions of previous estimates............... 3.6 (2.9) 79.6 - - 80.3
Purchases in place............................ 100.6 0.9 - - - 101.5
Extensions, discoveries and other additions... 256.8 49.2 90.7 124.6 - 521.3
Sales in place................................ (58.4) (4.3) - - - (62.7)
Production.................................... (210.2) (35.9) (45.6) - - (291.7)
------- ------ ------- ------- ----- -------
Net proved reserves at December 31, 1996........ 2,746.5(1) 320.9 370.2 199.6 - 3,637.2
Revisions of previous estimates............... (50.8) (1.5) (0.4) 25.1 - (27.6)
Purchases in place............................ 60.0 67.6 - - - 127.6
Extensions, discoveries and other additions... 275.9 37.8 - 253.5 7.7 574.9
Sales in place................................ (17.7) (0.4) - - - (18.1)
Production.................................... (229.1) (37.0) (41.0) (6.6) - (313.7)
------- ------ ------- ------- ----- -------
Net proved reserves at December 31, 1997........ 2,784.8(1) 387.4 328.8 471.6 7.7 3,980.3
Revisions of previous estimates............... (55.9) (2.5) 4.7 32.3 (0.4) (21.8)
Purchases in place............................ 123.0 54.9 - - - 177.9
Extensions, discoveries and other additions... 272.8 62.9 693.8 340.9 103.0 1,473.4
Sales in place................................ (37.5) - - - - (37.5)
Production.................................... (233.8) (38.5) (50.9) (20.2) - (343.4)
------- ------ ------- ------- ----- -------
Net proved reserves at December 31, 1998........ 2,853.4(1) 464.2 976.4 824.6 110.3 5,228.9
======= ====== ======= ======= ===== =======
Liquids (MBbl)(2)
Net proved reserves at December 31, 1995........ 25,399 6,585 6,870 11,542 - 50,396
Revisions of previous estimates............... 339 191 1,835 - - 2,365
Purchases in place............................ 312 2 - - - 314
Extensions, discoveries and other additions... 7,103 2,116 1,388 275 - 10,882
Sales in place................................ (447) (121) - - - (568)
Production.................................... (3,830) (1,321) (1,925) (1,026) - (8,102)
------- ------ ------- ------- ----- -------
Net proved reserves at December 31, 1996........ 28,876 7,452 8,168 10,791 - 55,287
Revisions of previous estimates............... 3,515 225 (31) 19 - 3,728
Purchases in place............................ 127 1,123 - - - 1,250
Extensions, discoveries and other additions... 6,037 1,590 - 20,123 - 27,750
Sales in place................................ (1,683) - - - - (1,683)
Production.................................... (5,223) (1,384) (1,236) (838) - (8,681)
------- ------ ------- ------- ----- -------
Net proved reserves at December 31, 1997........ 31,649 9,006 6,901 30,095 - 77,651
Revisions of previous estimates............... (152) (504) (1,049) 3,063 73 1,431
Purchases in place............................ 3,104 - - - - 3,104
Extensions, discoveries and other additions... 9,396 448 11,429 11,501 1,089 33,863
Sales in place................................ (1,039) - - - - (1,039)
Production.................................... (6,131) (1,358) (1,077) (1,874) - (10,440)
------- ------ ------- ------- ----- -------
Net proved reserves at December 31, 1998........ 36,827 7,592 16,204 42,785 1,162 104,570
======= ====== ======= ======= ===== =======
</TABLE>

(Table continued on following page)

32
<PAGE> 33

<TABLE>
<CAPTION>
UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL
------------- ------ -------- ------- ----- -------
<S> <C> <C> <C> <C> <C> <C>
Bcf Equivalent (Bcfe)
Net proved reserves at December 31, 1995........ 2,806.6(1) 353.3 286.7 144.3 - 3,590.9
Revisions of previous estimates............... 5.7 (1.8) 90.6 - - 94.5
Purchases in place............................ 102.5 0.9 - - - 103.4
Extensions, discoveries and other additions... 299.4 61.9 99.0 126.2 - 586.5
Sales in place................................ (61.0) (5.1) - - - (66.1)
Production.................................... (233.1) (43.9) (57.1) (6.2) - (340.3)
------- ------ ------- ------- ----- -------
Net proved reserves at December 31, 1996........ 2,920.1(1) 365.3 419.2 264.3 - 3,968.9
Revisions of previous estimates............... (29.8) (0.1) (0.5) 25.2 - (5.2)
Purchases in place............................ 60.7 74.4 - - - 135.1
Extensions, discoveries and other additions... 312.1 47.4 - 374.2 7.7 741.4
Sales in place................................ (27.7) (0.4) - - - (28.1)
Production.................................... (260.4) (45.3) (48.5) (11.7) - (365.9)
------- ------ ------- ------- ----- -------
Net proved reserves at December 31, 1997........ 2,975.0(1) 441.3 370.2 652.0 7.7 4,446.2
Revisions of previous estimates............... (57.0) (5.5) (1.7) 50.8 - (13.4)
Purchases in place............................ 141.6 54.9 - - - 196.5
Extensions, discoveries and other additions... 329.2 65.6 762.4 409.9 109.5 1,676.6
Sales in place................................ (43.7) - - - - (43.7)
Production.................................... (270.6) (46.6) (57.3) (31.4) - (405.9)
------- ------ ------- ------- ----- -------
Net proved reserves at December 31, 1998........ 3,074.5(1) 509.7 1,073.6 1,081.3 117.2 5,856.3
======= ====== ======= ======= ===== =======
Net proved developed reserves at
Natural Gas (Bcf)
December 31, 1995............................. 1,218.1 310.1 233.9 - - 1,762.1
December 31, 1996............................. 1,325.7 319.5 370.2 124.6 - 2,140.0
December 31, 1997............................. 1,349.0 370.9 328.8 286.6 - 2,335.3
December 31, 1998............................. 1,429.7 387.4 283.0 407.4 - 2,507.5
Liquids(MBbl)(2)
December 31, 1995............................. 19,977 6,505 5,607 11,542 - 43,631
December 31, 1996............................. 24,868 7,452 8,168 10,791 - 51,279
December 31, 1997............................. 27,707 8,885 6,901 23,322 - 66,815
December 31, 1998............................. 33,045 7,465 4,782 33,472 - 78,764
Bcf Equivalents
December 31, 1995............................. 1,338.0 349.1 267.5 69.3 - 2,023.9
December 31, 1996............................. 1,474.9 364.2 419.2 189.3 - 2,447.6
December 31, 1997............................. 1,515.3 424.2 370.2 426.5 - 2,736.2
December 31, 1998............................. 1,628.0 432.1 311.7 608.2 - 2,980.0
</TABLE>

- ---------------

(1) Includes 1,180 Bcf of proved undeveloped methane reserves contained, along
with high concentrations of carbon dioxide and other gases, in deep
Paleozoic (Madison) formations in the Big Piney area of Wyoming.

(2) Includes crude oil, condensate and natural gas liquids.

33
<PAGE> 34

Acreage. The following table summarizes our developed and undeveloped
acreage at December 31, 1998. Excluded is acreage in which our interest is
limited to owned royalty, overriding royalty and other similar interests.

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
--------------------- --------------------- ---------------------
GROSS NET GROSS NET GROSS NET
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
United States
California............. 21,324 16,747 821,738 748,238 843,062 764,985
Texas.................. 413,305 220,075 637,850 513,807 1,051,155 733,882
Offshore Gulf of
Mexico.............. 283,571 126,306 564,775 417,827 848,346 544,133
Wyoming................ 153,597 116,092 324,531 251,792 478,128 367,884
Oklahoma............... 188,963 104,633 122,848 87,264 311,811 191,897
Montana................ 119,686 1,651 146,013 103,779 265,699 105,430
New Mexico............. 71,945 35,091 106,133 64,232 178,078 99,323
Utah................... 74,454 50,311 40,873 27,205 115,327 77,516
Mississippi............ 5,144 5,052 43,174 42,950 48,318 48,002
Kansas................. 17,339 15,489 6,747 4,009 24,086 19,498
Colorado............... 20,619 1,233 30,908 13,618 51,527 14,851
Louisiana.............. 6,285 5,429 6,520 3,767 12,805 9,196
Arkansas............... 8,522 1,319 2,457 2,010 10,979 3,329
Other.................. 5,247 984 1,015 795 6,262 1,779
--------- --------- --------- --------- --------- ---------
Total.......... 1,390,001 700,412 2,855,582 2,281,293 4,245,583 2,981,705
Canada
Saskatchewan........... 251,805 235,121 288,834 283,732 540,639 518,853
Alberta................ 372,612 243,225 336,713 243,971 709,325 487,196
Manitoba............... 11,743 9,954 23,730 21,966 35,473 31,920
British Columbia....... 656 164 8,755 5,553 9,411 5,717
--------- --------- --------- --------- --------- ---------
Total Canada...... 636,816 488,464 658,032 555,222 1,294,848 1,043,686
Other International
China.................. 5,000 5,000 1,844,531 1,844,531 1,849,531 1,849,531
Venezuela.............. - - 268,413 241,572 268,413 241,572
India.................. 98,300 29,490 564,307 169,292 662,607 198,782
France................. - - 168,032 168,032 168,032 168,032
Trinidad............... 4,200 3,990 147,233 143,490 151,433 147,480
--------- --------- --------- --------- --------- ---------
Total Other
International... 107,500 38,480 2,992,516 2,566,917 3,100,016 2,605,397
--------- --------- --------- --------- --------- ---------
Total.......... 2,134,317 1,227,356 6,506,130 5,403,432 8,640,447 6,630,788
========= ========= ========= ========= ========= =========
</TABLE>

Producing Well Summary. The following table reflects the Company's
ownership in gas and oil wells located in Texas, the Gulf of Mexico, Oklahoma,
New Mexico, Utah, Wyoming, and various other states, Canada, Trinidad, India and
China at December 31, 1998.

<TABLE>
<CAPTION>
PRODUCTIVE WELLS
EXCLUDING INDIA
PRODUCTIVE WELLS AND CHINA
---------------- ----------------
GROSS* NET GROSS* NET
------- ------ ------- ------
<S> <C> <C> <C> <C>
Gas.................................................. 5,253 3,788 5,241 3,784
Oil.................................................. 897 506 831 486
----- ----- ----- -----
Total...................................... 6,150 4,294 6,072 4,270
===== ===== ===== =====
</TABLE>

- ---------------

* Gross gas and oil wells include 255 with multiple completions.

34
<PAGE> 35

DRILLING AND ACQUISITION ACTIVITIES

During the years ended December 31, 1996, 1997 and 1998, we spent
approximately $599 million, $693 million and $769 million, respectively, for
exploratory and development drilling and acquisition of leases and producing
properties. We drilled, participated in the drilling of or acquired wells as set
out in the table below for the periods indicated:

<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------------------------ --------------
1996 1997 1998 1999
-------------- -------------- -------------- --------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ------ ----- ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Development Wells Completed
North America
Gas.......................... 396 325.04 467 352.90 478 402.80 158 119.47
Oil.......................... 80 57.46 94 74.85 38 34.98 32 28.24
Dry.......................... 80 68.77 101 80.01 79 62.16 35 30.65
--- ------ --- ------ --- ------ --- ------
Total................... 556 451.27 662 507.76 595 499.94 225 178.36
Outside North America
Gas.......................... - - 12 3.60 - - 3 .90
Oil.......................... 1 .30 6 1.80 21 6.30 6 1.90
Dry.......................... - - - - - - - -
--- ------ --- ------ --- ------ --- ------
Total................... 1 .30 18 5.40 21 6.30 9 2.80
--- ------ --- ------ --- ------ --- ------
Total Development....... 557 451.57 680 513.16 616 506.24 234 181.16
--- ------ --- ------ --- ------ --- ------
Exploratory Wells Completed
North America
Gas.......................... 14 10.36 8 5.12 5 4.40 8 5.95
Oil.......................... 1 .78 - - 6 5.50 - -
Dry.......................... 26 19.00 12 7.53 22 15.70 7 5.05
--- ------ --- ------ --- ------ --- ------
Total................... 41 30.14 20 12.65 33 25.60 15 11.00
Outside North America
Gas.......................... - - - - 1 1.00 - -
Oil.......................... - - - - 1 .90 - -
Dry.......................... 1 .50 - - - - - -
--- ------ --- ------ --- ------ --- ------
Total................... 1 .50 - - 2 1.90 - -
--- ------ --- ------ --- ------ --- ------
Total Exploratory....... 42 30.64 20 12.65 35 27.50 15 11.00
--- ------ --- ------ --- ------ --- ------
Total................... 599 482.21 700 525.81 651 533.74 249 192.16
Wells in Progress at end of
period.......................... 87 61.08 44 36.39 28 15.73 54 42.33
--- ------ --- ------ --- ------ --- ------
Total................... 686 543.29 744 562.20 679 549.47 303 234.49
=== ====== === ====== === ====== === ======
Wells Acquired
Gas.......................... 350 148.20* 227 82.45* 333 317.23* 22 2.13*
Oil.......................... 5 .65 48 20.50* - 1.70* 2 .67
--- ------ --- ------ --- ------ --- ------
Total................... 355 148.85 275 102.95 333 318.93 24 2.80
=== ====== === ====== === ====== === ======
</TABLE>

- ---------------

* Includes the acquisition of additional interests in certain wells in which we
previously owned an interest.

All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We own no drilling equipment.

35
<PAGE> 36

MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The directors and executive officers of EOG (upon the closing of the Share
Exchange with Enron Corp., except as otherwise described below) and their names
and ages are as follows (all positions are with EOG unless otherwise noted):

<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Fred C. Ackman........................ 68 Director
Edward Randall, III................... 72 Director
Frank G. Wisner....................... 61 Director
Forrest E. Hoglund.................... 66 Chairman of the Board; Director
Mark G. Papa.......................... 52 President and Chief Executive Officer;
Director
Edmund P. Segner, III................. 45 Vice Chairman and Chief of Staff
Loren M. Leiker....................... 45 Executive Vice President, Exploration
Gary L. Thomas........................ 49 Executive Vice President, North
American Operations
Barry Hunsaker, Jr. .................. 49 Senior Vice President and General
Counsel
Walter C. Wilson...................... 56 Senior Vice President and Chief
Financial Officer
</TABLE>

Mr. Ackman has been a director since 1989. He also has been a consultant to
the oil and gas industry for over six years and has interests in ranching and
investments.

Mr. Randall has been a director since 1990, and his principal occupation is
investments. Mr. Randall also is a director of KN Energy, Inc. and PaineWebber
Group Inc.

Mr. Wisner has been a director since 1997. He also has served as Vice
Chairman of American International Group Inc. since 1997 following his
retirement as U.S. Ambassador to India. American International Group Inc. is an
insurance company, which provides insurance to companies investing in foreign
operations. Mr. Wisner's more than 35-year career with the U.S. State
Department, primarily in Africa, Asia and Washington, D.C., included serving as
U.S. Ambassador to the Philippines, Egypt and Zambia.

Forrest E. Hoglund joined EOG as Chairman of the Board and Director in
September 1987. He also served as Chief Executive Officer of EOG until September
1998 and served as President from May 1990 until December 1996. Mr. Hoglund is
an advisory director of Chase Bank of Texas, National Association. Mr. Hoglund
expects to retire effective August 15, 1999 and, therefore, will not be a
director or executive officer of EOG at the time of the closing of this
offering.

Mark G. Papa was elected President and Chief Executive Officer and Director
of EOG in September 1998, President and Chief Operating Officer in September
1997, President in December 1996 and was President North America Operations from
February 1994 to September 1998. From May 1986 through January 1994, Mr. Papa
served as Senior Vice President - Operations. Mr. Papa joined Belco Petroleum
Corporation, a predecessor of EOG, in 1981. We expect that Mr. Papa will be
elected Chairman of the Board following Mr. Hoglund's retirement.

Edmund P. Segner, III became Vice Chairman and Chief of Staff of EOG in
September 1997. Mr. Segner was a director of EOG from January 1997 to October
1997. Mr. Segner joined Enron Corp. in 1988 and

36
<PAGE> 37

was Executive Vice President and Chief of
Staff. We expect that Mr. Segner will be elected a director of EOG to fill the
vacancy created by Mr. Hoglund's retirement.

Loren M. Leiker joined EOG in April 1989 and has been Executive Vice
President, Exploration since May 1998. Mr. Leiker was previously Senior Vice
President, Exploration of EOG.

Gary L. Thomas was elected Executive Vice President, North American
Operations in May 1998. He was previously Senior Vice President and General
Manager of EOG's Midland Division. Mr. Thomas joined a predecessor of EOG in
July 1978.

Barry Hunsaker, Jr. has been Senior Vice President and General Counsel
since he joined EOG in May 1996. Prior to joining EOG, Mr. Hunsaker was a
partner in the law firm of Vinson & Elkins L.L.P.

Walter C. Wilson joined EOG in November 1987 and has been Senior Vice
President and Chief Financial Officer since May 1991.

THE SELLING STOCKHOLDER

<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP
BENEFICIAL OWNERSHIP AFTER STOCK OFFERING
BEFORE STOCK OFFERING AND SHARE EXCHANGE(1)(2)
------------------------ SHARES TO ------------------------
SELLING STOCKHOLDER SHARES PERCENTAGE BE SOLD(1) SHARES PERCENTAGE
- ------------------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Enron Corp. 82,270,000 53.5% 8,500,000 11,500,000 9.7%
</TABLE>

- ---------------

(1) Assumes the exercise of the over-allotment option in full, and the transfer
by Enron Corp. of 62,270,000 shares of our common stock to us in connection
with the Share Exchange.

(2) Concurrently with this offering, Enron Corp. is offering Exchangeable Notes,
which are mandatorily exchangeable into no more than 10,000,000 shares of
our common stock (no more than 11,500,000 shares if the over-allotment
option to the underwriters in the Exchangeable Notes offering is exercised
in full) owned by Enron Corp. Following consummation of the Exchangeable
Notes offering, the shares that may be delivered upon exchange therefor will
continue to be beneficially owned by Enron Corp. until such time as they are
delivered at maturity of the Exchangeable Notes. If the underwriters'
over-allotment options in this offering and the Exchangeable Notes offering
are exercised in full and the maximum number of shares of common stock are
delivered at maturity of the Exchangeable Notes, Enron Corp. will no longer
own any shares of our common stock.

The registration related to our common stock covered by the over-allotment
option and our common stock deliverable upon exchange of the Exchangeable Notes
is being provided pursuant to the terms of a stock restriction and registration
agreement with Enron Corp., under which we have agreed that, upon the request of
Enron Corp. (or certain assignees), we will register under the Securities Act
and applicable state securities laws the sale of our common stock owned by Enron
Corp. Our obligation is subject to certain limitations relating to a minimum
amount of our common stock required for registration, the timing of registration
and other similar matters. We are obligated to pay all expenses incidental to
such registration, excluding underwriters' discounts and commissions and certain
legal fees and expenses.

RELATIONSHIP WITH ENRON CORP.

After the Share Exchange and consummation of the concurrent offering of
31,000,000 shares of our common stock by us and Enron Corp., Enron Corp.'s
ownership of EOG will be reduced to 16,000,000 shares of common stock
(11,500,000 shares if the underwriters' over-allotment option in the offering is
exercised in full). The Share Exchange Agreement provides that Enron Corp. may
not sell these remaining shares of EOG common stock for a period of six months
after the Share Exchange. However,

37
<PAGE> 38

Enron Corp. may sell convertible securities that would be mandatorily
exchangeable into a maximum of 10,000,000 of its remaining EOG shares
(11,500,000 if the underwriters' over-allotment option in that offering is
exercised in full). (See "The Selling Stockholder".)

On closing of the Share Exchange, the EOG board of directors will be
reduced to five, and all of Enron Corp.'s officers and directors currently
serving as EOG directors will resign from the EOG board. We have the right to
use the name "Enron Oil & Gas Company" for the period of six months after the
Share Exchange. However, some time soon after the Share Exchange, we expect to
change our corporate name to "EOG Resources, Inc." We will also change the names
of our subsidiaries to reflect our new corporate name.

Enron Corp. currently provides us with various services, such as
maintenance of employee benefit plans, provision of some telecommunications and
computer support services, lease of office space and the provision of some
purchasing and operating services and other corporate staff and support
services. After the Share Exchange, we have the right to continue to use these
services for a period of up to one year. However, we expect to transition away
from using these services as soon as reasonably convenient for both Enron Corp.
and us. EOG believes that it has obtained these services at substantially market
terms, and, therefore, we expect that our costs to obtain these services from
third parties will not materially change.

EOG and Enron Corp. have in the past entered into material transactions and
agreements incident to their respective businesses. Such transactions and
agreements have related to, among other things, the purchase and sale of natural
gas and crude oil and hedging and trading activities. Those transactions and
agreements currently in place will continue after the Share Exchange, and we do
not expect any material changes to such transactions and agreements that would
not otherwise occur in a third party transaction. EOG and Enron Corp. may enter
into similar types of transactions and agreements in the future. We intend that
the terms of any future transactions and agreements between us and Enron Corp.
will be at least as favorable to us as could be obtained from other third
parties.

After the completion of the Share Exchange, we and Enron Corp. can compete
anywhere in the world, including India and China. In certain areas of the world,
affiliate rules may have prevented us from having exploration and production
opportunities while Enron Corp. owned a majority of our common stock. After the
Share Exchange, those rules will no longer restrict us.

EOG and Enron Corp. have entered into an agreement regarding the manner in
which they will share the burdens and benefits of the integrated project under
joint development in Mozambique. The agreement provides generally that our
interest in this project will be 20% of the combined ownership interest of EOG
and Enron Corp. This agreement will continue in place after the Share Exchange.

For further detail of our relationship with Enron Corp. after the Share
Exchange and the status of specific intercompany agreements, please refer to the
Share Exchange Agreement filed as an exhibit to the registration statement that
includes this prospectus.

38
<PAGE> 39

DESCRIPTION OF CAPITAL STOCK

AUTHORIZED AND OUTSTANDING CAPITAL STOCK

Our authorized capital stock consists of 10,000,000 shares of preferred
stock, par value $.01 per share, none of which are outstanding, and 320,000,000
shares of common stock, $.01 par value, of which 153,896,229 shares were
outstanding as of July 1, 1999. Following the Share Exchange and the offering,
there will be 35,270,000 fewer shares of common stock outstanding. The following
description of our capital stock summarizes the material terms and provisions of
these securities. For the complete terms of our common stock and preferred
stock, please refer to our restated certificate of incorporation and bylaws that
are incorporated by reference into the registration statement that includes this
prospectus.

PREFERRED STOCK

Our board of directors is authorized, subject to any limitations prescribed
by law, to provide for the issuance of the shares of preferred stock in series,
by filing a certificate pursuant to the applicable laws of the State of Delaware
to establish from time to time the number of shares to be included in each such
series, and to fix the powers, designations, preferences, and relative,
participating, optional or other rights, if any, of the shares of each such
series and any qualifications, limitations, or restrictions thereof, all without
stockholder approval. Any future issuance of preferred stock, while providing
desired flexibility in connection with acquisitions and other corporate
purposes, could adversely affect the voting power or other rights of holders of
common stock and the likelihood that such holders will receive dividend payments
and payments upon liquidation, and could have the effect of delaying, deferring
or preventing a change of control of EOG.

COMMON STOCK

Our common stock possesses ordinary voting rights for the election of
directors and in respect to other corporate matters, each share being entitled
to one vote. There are no cumulative voting rights, meaning that the holders of
a majority of the shares voting for the election of directors can elect all the
directors if they choose to do so. Our common stock carries no preemptive rights
and is not convertible, redeemable or assessable, or entitled to the benefits of
any sinking fund. The holders of our common stock are entitled to dividends in
such amounts and at such times as may be declared by the board of directors out
of legally available funds.

Upon liquidation or dissolution, holders of common stock are entitled to
share ratably in all net assets available for distribution to stockholders after
payment of any corporate debts and any liquidation preference established for
any preferred stock. All outstanding shares of common stock are duly authorized,
validly issued, fully paid and nonassessable.

LISTING

Our common stock is listed on the New York Stock Exchange.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar of our common stock is First Chicago Trust
Company of New York, Jersey City, New Jersey.

LIMITATION ON DIRECTORS' LIABILITY

Delaware corporation law authorizes corporations to limit or eliminate the
personal liability of directors to corporations and their stockholders for
monetary damages for breach of directors' fiduciary duty of care. The duty of
care requires that, when acting on behalf of the corporation, directors must
exercise an informed business judgment based on all material information
reasonably available to them. Absent the limitations authorized by such laws,
directors are accountable to corporations and their stockholders for monetary
damages for conduct constituting gross negligence in the exercise of their duty
of care. The Delaware laws enable corporations to limit available relief to
equitable remedies such as injunction

39
<PAGE> 40

or rescission. Our restated certificate of incorporation limits the liability of
our directors to EOG or its stockholders (in their capacity as directors but not
in their capacity as officers) to the fullest extent permitted by the Delaware
law. Specifically, our directors will not be personally liable for monetary
damages for breach of a director's fiduciary duty as a director, except for
liability

- for any breach of the director's duty of loyalty to the company or its
stockholders,

- for acts or omissions not in good faith or which involve intentional
misconduct or a knowing violation of law,

- for unlawful payments of dividends or unlawful stock repurchases or
redemptions as provided in Section 174 of the Delaware General
Corporation Law, or

- for any transaction from which the director derived an improper personal
benefit.

This provision in our restated certificate of incorporation may have the
effect of reducing the likelihood of derivative litigation against directors,
and may discourage or deter stockholders or management from bringing a lawsuit
against directors for breach of their duty of care, even though such an action,
if successful, might otherwise have benefited us and our stockholders.

40
<PAGE> 41

LEGAL MATTERS

The validity of our common stock deliverable upon exchange of the
Exchangeable Notes will be passed upon for EOG by Barry Hunsaker, Jr., Esq.,
Senior Vice President and General Counsel, and for the underwriters by Bracewell
& Patterson, L.L.P. Certain other matters will be passed on for EOG by Fulbright
& Jaworski L.L.P. Certain matters will be passed upon for Enron Corp. by Vinson
& Elkins L.L.P. Mr. Hunsaker owns substantially less than 1% of the outstanding
shares of our common stock. Bracewell & Patterson, L.L.P. provides services to
us and our affiliates on matters unrelated to the offering of the common stock.

EXPERTS

The consolidated financial statements and schedule included in our Annual
Report on Form 10-K for the year ended December 31, 1998 incorporated by
reference in this prospectus and elsewhere in the registration statement have
been audited by Arthur Andersen LLP, independent public accountants, as
indicated in their report with respect thereto, and are incorporated by
reference herein in reliance upon the authority of said firm as experts in
accounting and auditing in giving said report.

The letter report of DeGolyer and MacNaughton, independent petroleum
consultants, included as an exhibit to our Annual Report on Form 10-K for the
year ended December 31, 1998, and the estimates from the reports of that firm
appearing in such Annual Report, are incorporated by reference herein on the
authority of said firm as experts in petroleum engineering in giving such
reports.

PLAN OF DISTRIBUTION

This prospectus relates to up to 11,500,000 shares of EOG common stock that
may be delivered by Enron Corp. pursuant to its offering of Exchangeable Notes
and is Appendix A to the Enron Corp. Exchangeable Notes prospectus. At maturity
of the Exchangeable Notes, the principal amount of each note will be mandatorily
exchanged by Enron Corp. for shares of EOG common stock. For a description of
the Exchangeable Notes, see "Description of the Exchangeable Notes" in the Enron
Corp. Exchangeable Notes prospectus.

We, our directors and executive officers and Enron Corp. have agreed with
the underwriters not to offer, sell, contract to sell or otherwise dispose of or
hedge any shares of our common stock or securities convertible into or
exchangeable for shares of our common stock during the period from the date of
this prospectus continuing through the date 180 days after the date of this
prospectus, except with the prior written consent of Goldman, Sachs & Co. This
agreement does not apply to any existing employee benefit plans or the exercise
of stock options pursuant to our stock option plan.

In connection with the distribution of the Exchangeable Notes, we and Enron
Corp. have agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act, or to contribute to payments the
underwriters may be required to make in respect thereof.

41
<PAGE> 42

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and special reports, proxy statements and other
information with the SEC. Our SEC filings are available to the public over the
Internet at the SEC's web site at http://www.sec.gov. You may also read and copy
any document we file at the SEC's public reference rooms located at:

- 450 Fifth Street, N.W.
Washington, D.C. 20549;

- Seven World Trade Center
New York, New York 10048; and

- Northwest Atrium Center
500 West Madison Street
Chicago, Illinois 60661.

Please call the SEC at 1-800-SEC-0330 for further information on the public
reference rooms and their copy charges.

Our common stock has been listed and traded on the New York Stock Exchange
since 1989. Accordingly, you may inspect the information we file with the SEC at
the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

The SEC allows us to "incorporate by reference" the information we file
with them, which means that we can disclose important information to you by
referring you to those documents. The information incorporated by reference is
an important part of this prospectus, and information that we file later with
the SEC will automatically update and supersede this information. We incorporate
by reference the documents listed below and any future filings made with the SEC
under Sections 13(a), 13(c), 14 and 15(d) of the Securities Exchange Act of 1934
until we sell all of the common stock:

- Our Annual Report on Form 10-K for the fiscal year ended December 31,
1998, as amended by Amendment No. 1 on Form 10-K/A; and

- Our Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999
and June 30, 1999.

You may request a copy of these filings, excluding exhibits, at no cost by
writing or telephoning Angus H. Davis, Corporate Secretary, at our principal
executive office, which is:

Enron Oil & Gas Company
1400 Smith Street
Houston, Texas 77002
(713) 853-6161

YOU SHOULD RELY ONLY ON THE INFORMATION INCORPORATED BY REFERENCE OR
PROVIDED IN THIS PROSPECTUS. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
DIFFERENT INFORMATION.

WE ARE NOT MAKING AN OFFER OF THE SECURITIES COVERED BY THIS PROSPECTUS
WHERE THE OFFER IS NOT PERMITTED. YOU SHOULD NOT ASSUME THAT THE INFORMATION IN
THIS PROSPECTUS OR IN ANY OTHER DOCUMENT INCORPORATED BY REFERENCE IN THIS
PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT OF THOSE
DOCUMENTS.

42
<PAGE> 43

- ------------------------------------------------------
------------------------------------------------------
- ------------------------------------------------------
------------------------------------------------------

No dealer, salesperson or other person is authorized to give any
information or to represent anything not contained in this prospectus. You must
not rely on any unauthorized information or representations. This prospectus is
an offer to sell only the shares offered hereby, but only under circumstances
and in jurisdictions where it is lawful to do so. The information contained in
this prospectus is current only as of its date.

---------------------

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary.................... 3
Risk Factors.......................... 10
Cautionary Statement Regarding
Forward-Looking Statements.......... 15
Use of Proceeds....................... 15
Capitalization........................ 16
Price Range of Common Stock and Cash
Dividends........................... 17
Unaudited Condensed Consolidated Pro
Forma Financial Information......... 18
Business.............................. 24
Management............................ 36
The Selling Stockholder............... 37
Relationship with Enron Corp. ........ 37
Description of Capital Stock.......... 39
Legal Matters......................... 41
Experts............................... 41
Plan of Distribution.................. 41
Where You Can Find More
Information......................... 42
</TABLE>

[Enron Logo]
ENRON OIL & GAS COMPANY
Common Stock
-----------------------

PROSPECTUS

-----------------------