UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1999
COMMISSION FILE NUMBER 1-13108

VASTAR RESOURCES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE 95-4446177
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)

15375 MEMORIAL DRIVE
HOUSTON, TEXAS 77079
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)

__________________

(281) 584-6000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)

__________________

INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS.

YES [X] NO [ ]

NUMBER OF SHARES OF COMMON STOCK, $.01 PAR VALUE, OUTSTANDING AS OF SEPTEMBER
30, 1999: 97,643,700.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VASTAR RESOURCES, INC.
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

CONSOLIDATED STATEMENT OF INCOME

For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
--------------- ----------------
(Millions of dollars, 1999 1998 1999 1998
except per share amounts) ----- ----- ----- -----

REVENUES
Net sales and other operating
revenues............................ $304.4 $206.6 $783.2 $643.2
Earnings from equity affiliate....... 4.4 5.3 13.8 15.9
Other revenues....................... 7.3 5.4 40.2 30.3
------ ------ ------ ------
Net revenues...................... 316.1 217.3 837.2 689.4
------ ------ ------ ------
EXPENSES
Operating expenses................... 49.8 39.6 147.3 113.2
Exploration expenses................. 38.1 35.3 123.4 167.7
Selling, general and administrative
expenses............................ 13.7 12.6 38.8 38.8
Taxes other than income taxes........ 14.6 11.6 35.3 37.7
Depreciation, depletion and
amortization........................ 105.9 82.3 322.8 225.6
Interest............................. 18.7 14.4 59.7 40.7
------ ------ ------ ------
Total expenses.................... 240.8 195.8 727.3 623.7
------ ------ ------ ------
Income before income taxes........... 75.3 21.5 109.9 65.7
Income tax provision (benefit)....... 4.2 (16.1) (28.5) (52.7)
------ ------ ------ ------
Net income......................... $ 71.1 $ 37.6 $138.4 $118.4
====== ====== ====== ======

Basic earnings per share............. $ 0.73 $ 0.39 $ 1.42 $ 1.22
====== ====== ====== ======

Diluted earnings per share........... $ 0.72 $ 0.38 $ 1.40 $ 1.21
====== ====== ====== ======

Cash dividends paid per share
of common stock..................... $0.075 $0.075 $0.225 $0.225
====== ====== ====== ======

The accompanying notes are an integral part of
these consolidated financial statements.

VASTAR RESOURCES, INC.
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

CONSOLIDATED BALANCE SHEET

September 30, December 31,
1999 1998
(Millions of dollars) ------------- -----------

ASSETS
Current assets:
Cash and cash equivalents....................... $ 10.5 $ 4.3
Accounts receivable:
Trade.......................................... 137.6 110.0
Related parties................................ 131.5 130.9
Inventories..................................... 10.4 10.2
Prepaid expenses and other assets............... 33.4 37.5
-------- --------
Total current assets........................... 323.4 292.9

Oil and gas properties and equipment, net........ 2,226.1 2,220.8
Other long-term assets........................... 82.5 60.3
-------- --------
Total assets................................... $2,632.0 $2,574.0
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade.......................................... $ 186.4 $ 179.2
Related parties................................ 9.3 9.8
Accrued liabilities............................. 72.9 61.5
-------- --------
Total current liabilities..................... 268.6 250.5

Long-term debt................................... 1,067.7 1,288.6
Deferred liabilities and credits................. 310.7 205.4
Deferred income taxes............................ 246.4 214.3
-------- --------
Total liabilities.............................. 1,893.4 1,958.8

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS' EQUITY
Common stock, $.01 par value; authorized,
110,000,000 shares; issued and outstanding,
97,643,700 shares as of September 30, 1999 and
97,403,340 shares as of December 31, 1998....... 1.0 1.0
Capital in excess of par value of stock.......... 464.3 457.4
Accumulated earnings............................. 273.3 156.8
-------- --------
Total stockholders' equity..................... 738.6 615.2
-------- --------
Total liabilities and stockholders' equity....... $2,632.0 $2,574.0
======== ========

The accompanying notes are an integral part of
these consolidated financial statements.

VASTAR RESOURCES, INC.
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

CONSOLIDATED STATEMENT OF CASH FLOWS

For the Nine Months Ended
September 30,
--------------------------
1999 1998
(Millions of dollars) ------- -------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.......................................... $ 138.4 $ 118.4
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization.......... 322.8 225.6
Deferred income taxes............................. 32.1 25.4
Dry hole expense and undeveloped leasehold
amortization.................................... 65.6 99.6
Gain on asset sales............................... (25.5) (21.0)
Earnings from equity affiliate.................... (13.8) (15.9)
Net change in accounts receivable, inventories
and accounts payable............................ (21.7) (95.8)
Other............................................. 86.9 (23.0)
------- -------
Net cash provided by operating activities........... 584.8 313.3
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties and equipment,
including dry hole costs......................... (391.7) (528.4)
Proceeds from asset sales........................... 52.1 47.0
Other............................................... (3.1) 0.7
------- -------
Net cash used by investing activities............... (342.7) (480.7)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock............................ 6.9 1.5
Proceeds from long-term debt issuance............... 604.7 196.4
Repayments of long-term debt........................ (825.6) (1.3)
Dividends paid...................................... (21.9) (21.9)
------- -------
Net cash provided (used) by financing activities.... (235.9) 174.7
------- -------
Net change in cash and cash equivalents............. 6.2 7.3

Cash and cash equivalents at beginning of period.... 4.3 10.2
------- -------
Cash and cash equivalents at end of period.......... $ 10.5 $ 17.5
======= =======

The accompanying notes are an integral part of
these consolidated financial statements.

VASTAR RESOURCES, INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1. INTRODUCTION.

The accompanying financial statements are unaudited and have been prepared from
our records. In the opinion of our management, these financial statements
reflect all adjustments (consisting only of items of a normal recurring nature)
necessary for a fair presentation of our financial position and results of
operations in conformity with generally accepted accounting principles. These
statements are presented in accordance with the requirements of Regulation S-X,
which does not require all disclosures normally required by generally accepted
accounting principles or those normally required in an annual report on
Form 10-K. These interim financial statements should be read in conjunction with
the following:
(1) the annual financial statements for the year ended December 31, 1998 and the
related notes contained in our annual report on Form 10-K for the year ended
December 31, 1998; (2) the quarterly financial statements for the quarter ended
March 31, 1999, and the related notes in our quarterly report on Form 10-Q for
the quarter ended March 31, 1999; and (3) the quarterly financial statements for
the quarter ended June 30, 1999 and the related notes in our quarterly report on
Form 10-Q for the quarter ended June 30, 1999. We have restated certain
previously reported amounts to classifications we adopted in 1999.

NOTE 2. NET SALES AND OTHER OPERATING REVENUES.

For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
------------------ --------------------
1999 1998 1999 1998
(Millions of dollars) -------- ------- -------- --------

Sales and other operating revenues:
Unrelated parties................... $ 277.1 $ 175.3 $ 733.2 $ 587.6
Related parties (1)................. 224.3 199.9 581.6 607.2
------- ------- -------- --------
Total.............................. 501.4 375.2 1,314.8 1,194.8

Less:
Purchases (2)....................... (191.5) (165.2) (515.8) (543.9)
Delivery expense.................... (5.5) (3.4) (15.8) (7.7)
------- ------- -------- --------
Net sales and
other operating revenues............ $ 304.4 $ 206.6 $ 783.2 $ 643.2
======= ======= ======== ========
- --------------------
(1) Average costs of related-party
sales.......................... $ 183.1 $ 175.8 $ 523.2 $ 513.2
(2) Related-party purchase cost...... $ 20.6 $ 31.3 $ 54.2 $ 88.6

VASTAR RESOURCES, INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS -(Continued)
(Unaudited)

NOTE 3. SOUTHERN COMPANY ENERGY MARKETING L.P.

Southern Company Energy Marketing is a strategic marketing alliance between
Southern Energy, Inc. and Vastar Resources, Inc. Through subsidiaries, we
currently hold a 40 percent interest in Southern Company Energy Marketing and
Southern Energy holds a 60 percent interest.

We account for our interest in Southern Company Energy Marketing using the
equity method of accounting. Our $48.3 million equity investment in Southern
Company Energy Marketing is reflected as a long-term asset in our consolidated
balance sheet.

For the first five years of operation, we are entitled to receive, subject to
certain exceptions, minimum cash distributions from Southern Company Energy
Marketing of $20 million for the year 1998, $20 million for the year 1999, $25
million for the year 2000, $30 million for the year 2001 and $30 million for the
year 2002. In 1999 and 1998, we have recognized our accrued share of minimum
distributions, net of any contractual obligations, in the amounts of (1) $4.4
million for the three months ended September 30, 1999, (2) $5.3 million for the
three months ended September 30, 1998, (3) $13.8 million for the nine months
ended September 30, 1999 and (4) $15.9 million for the nine months ended
September 30, 1998. For additional details, including a discussion concerning a
dispute between Vastar and Southern Energy relating to the minimum cash
distribution payment for 1998, refer to our annual report on Form
10-K for the year ended December 31, 1998.

NOTE 4. EXPLORATION EXPENSES.

For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
------------- -------------
(Millions of dollars) 1999 1998 1999 1998
----- ----- ------ -----

Dry hole costs...................... $12.4 $ 8.2 $ 39.3 $ 73.3
Geological and geophysical.......... 3.6 4.6 21.8 29.7
Undeveloped leasehold amortization.. 8.8 8.8 26.3 26.3
Staff............................... 10.4 10.3 29.8 31.3
Lease rentals....................... 2.9 3.4 6.2 7.1
----- ----- ------ ------
Total.............................. $38.1 $35.3 $123.4 $167.7
===== ===== ====== ======

VASTAR RESOURCES, INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)

NOTE 5. EARNINGS PER SHARE.
For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
------------- -------------
1999 1998 1999 1998
---- ---- ---- ----
(Millions, except per share amounts)

Basic earnings per share:
Income available to common shareholders. $71.1 $37.6 $138.4 $118.4
Average shares of stock outstanding....... 97.6 97.4 97.5 97.3
Basic earnings per share................... $0.73 $0.39 $ 1.42 $ 1.22

Diluted earnings per share:
Income available to common shareholders.. $71.1 $37.6 $138.4 $118.4
Incremental shares assuming the exercise
of stock options......................... 1.1 0.5 0.8 0.6
Average shares of stock outstanding plus
effect of dilutive securities........... 98.7 97.9 98.3 97.9
Diluted earnings per share................ $0.72 $0.38 $ 1.40 $ 1.21

Set forth in the table below are all of our outstanding stock options granted
under all of our stock option plans and programs for directors, officers and
employees as of September 30, 1999. The exercise price of stock options range
from $14.00 to $46.66 per share.

Vested and exercisable(1)......... 1.2 million
Vested and unexercisable.......... 0.6 million
Non-vested........................ 0.5 million
-------------
Total............................. 2.3 million
-------------
(1) Stock options generally vest one year after the date of grant, become
exercisable in increments of 25 percent per year during the first four years
after the grant and expire ten years after the date of grant.

Our board of directors has adopted various arrangements that will become
operative upon a change of control of Vastar. One of these arrangements, our
Amended and Restated Executive Long-Term Incentive Plan, provides that, if a
change of control occurs, all unexercisable and/or unvested stock options
granted under the plan will become immediately vested and exercisable. All stock
options granted under our other stock option plans and programs are vested and
exercisable.

In March 1999, ARCO (Atlantic Richfield Company), which owns approximately 81.9
percent of our common stock, entered into a merger agreement with BP Amoco
p.l.c. which provides for the merger of a subsidiary of BP Amoco p.l.c. into
ARCO. If this transaction is consummated it would constitute a change of control
under the above-described arrangements, including our Amended and Restated
Executive Long-Term Incentive Plan. For additional information on the change of
control arrangements, refer to our proxy statement relating to our 1999 annual
meeting of stockholders, which we filed with the SEC on March 23, 1999. We filed
a copy of the Amended and Restated Executive Long-Term Incentive Plan as
Appendix A to our proxy statement relating to our 1998 annual meeting of
stockholders, which we filed with the SEC on March 26, 1998.

VASTAR RESOURCES, INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)

NOTE 6. COMMITMENTS AND CONTINGENCIES.

We are involved in a number of lawsuits, all of which have arisen in the
ordinary course of our business. We believe any ultimate liability resulting
from these lawsuits will not have a material adverse effect on our financial
position or results of operations.

Our operations and financial position continue to be affected from time to time
in varying degrees by domestic and foreign political developments as well as
legislation and regulations pertaining to restrictions on oil and gas
production, imports and exports, natural gas regulation, taxes, environmental
regulations and cancellation of contract rights. Both the likelihood of such
occurrences and their overall effect on us vary greatly and are not predictable.
These uncertainties are among a number of items we have taken and will continue
to take into account in periodically establishing accounting reserves.

Vastar and ARCO have agreements whereby we have agreed to indemnify ARCO against
certain claims or liabilities. Our indemnity obligations cover claims and
liabilities, which could be made against ARCO relating to ARCO's historical
ownership and operation of the properties ARCO transferred to us upon the
formation of Vastar. They also include liabilities under laws relating to the
protection of the environment and the workplace and liabilities arising out of
certain litigation described in the agreements. ARCO has agreed to indemnify us
with respect to other claims and liabilities and other litigation matters not
related to our business or properties as reflected in our consolidated financial
statements.

In September 1996, we entered into a contract with Diamond Offshore Drilling
Company (Diamond) for the major upgrade and operation of a semisubmersible
drilling rig, Ocean Victory, for a three-year deepwater drilling program in the
Gulf of Mexico, which began in November 1997. Since November 1997, scheduled
increases in the day rates and our request of Diamond to make improvements to
the rig have resulted in higher costs during the remaining contract term. This
contract has a remaining life as of September 30, 1999 of 1.4 years. Remaining
costs for this contract and other contracts for related support boats are
approximately $87.0 million. This amount does not take into consideration any
reimbursements we might receive from partners or potential partners. We have
three one-year options to renew the term of the contract, subject to
renegotiating the day rates.

In December 1998, we finalized an agreement with R&B Falcon Drilling Co. for the
operation of a semisubmersible, ultra-deepwater drilling rig, Deepwater Horizon,
for a three-year deepwater-drilling program in the Gulf of Mexico. The drilling
program is scheduled to commence in 2001. This contract is for three years and
has an anticipated cost of approximately $220.0 million, before any
reimbursements from partners or potential partners and operating cost
escalations. We have several options relating to the term and pricing of the
contract, including the option to extend the term of the contract for up to five
additional years.

Vastar and Southern Energy have agreed to guarantee certain obligations of
Southern Company Energy Marketing. In connection with these guarantees and
certain other matters, we have significant credit risk exposure to Southern
Company Energy Marketing and Southern Energy which are described in our annual
report on Form 10-K for the year ended December 31, 1998.

Pursuant to a working capital loan arrangement, we have agreed to loan Southern
Company Energy Marketing up to $20.0 million. At September 30, 1999, no loans
were outstanding under this arrangement.

VASTAR RESOURCES, INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)

NOTE 6. COMMITMENTS AND CONTINGENCIES - (continued).

We have performed and continue to perform ongoing credit evaluations of our
customers and generally do not require collateral on our credit sales. Any
amounts anticipated as uncollectible are charged to income and credited to a
valuation account. The amounts included in the allowance for uncollectible
accounts receivable at September 30, 1999 and 1998, were insignificant.

In July 1999, we entered into agreements with an unrelated third party that have
the effect of monetizing the value of one of our long-term natural gas sales
contracts. This particular contract is associated with gas sales to a certain
cogeneration facility, has a remaining life of approximately 11 years and has an
expected average price of approximately $3.00 per Mcf for 1999. Pursuant to
these agreements, we received an immediate payment of $88.0 million (net of
transaction costs) that has been recorded as a deferred liability and will be
amortized as the underlying contract volumes are delivered.

In March 1999, ARCO (Atlantic Richfield Company), which owns approximately 81.9
percent of our common stock, entered into a merger agreement with BP Amoco
p.l.c. which provides for the merger of a subsidiary of BP Amoco p.l.c. into
ARCO. The closing of the merger is subject to the approval of various regulatory
authorities some of which have yet to be obtained. ARCO and Vastar have entered
into a number of agreements, including technology assignments and licenses,
services agreements and insurance agreements. These agreements are more fully
described in our proxy statement relating to our 1999 annual meeting of
stockholders which we filed with the SEC on March 23, 1999 and copies of many of
these agreements have also been filed with the SEC. We do not anticipate that
the rights and obligations of the parties under these agreements, including any
termination rights, will be materially affected by the merger. Any amendments to
these agreements would have to be negotiated and agreed to by us. We do not
believe that the termination of any or all of the above-listed agreements with
ARCO would have a material adverse effect on our operations, cash flows or
financial condition.

Vastar and ARCO are also parties to a tax sharing agreement, which requires
Vastar, as a member of ARCO's consolidated tax group, to pay its share of the
group's federal and certain state income taxes to ARCO. If the merger is
consummated, we expect that the agreement would continue to govern consolidated
tax matters involving Vastar and ARCO. If any amendments become necessary as a
result of the merger, they will have to be negotiated and agreed to by us.

VASTAR RESOURCES, INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)

NOTE 7. TAXES.

The provision (benefit) for taxes on income is comprised of the following:

The following is a reconciliation of our income tax provision (benefit) with tax
at the federal statutory rate for the specified periods:

For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
---------------- ----------------
(Millions of dollars) 1999 1998 1999 1998
------- ------- ------- -------

Income before taxes............. $ 75.3 $ 21.5 $109.9 $ 65.7
====== ====== ====== ======
Tax at the statutory rate....... $ 26.4 $ 7.5 $ 38.5 $ 23.0
Increase (reduction) in taxes
resulting from:
State income taxes (net
of federal effect)........... 1.1 0.3 1.7 0.9
Tax credits and other......... (23.3) (23.9) (68.7) (76.6)
------ ------ ------ ------
Income tax provision (benefit).. $ 4.2 $(16.1) $(28.5) $(52.7)
====== ====== ====== ======

VASTAR RESOURCES, INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)

NOTE 7. TAXES - (continued).

Under the Tax Sharing Agreement with ARCO, we are paid currently for Internal
Revenue Code Section 29 ("Section 29") tax credits that reduce the ARCO
consolidated tax group's income tax liability in the current period. Pursuant to
the Internal Revenue Code, our Section 29 tax credits can be used to reduce the
ARCO consolidated tax group's regular income tax liability after foreign tax
credits (the "Regular Tax"), but not below the ARCO consolidated tax group's
tentative minimum tax liability. If Section 29 tax credits are not used by the
ARCO consolidated tax group due to this limitation, the portion of the unused
credits that does not exceed the Regular Tax is carried forward to be used by
ARCO and by us in a subsequent year.

During the third quarter of 1999, we entered into a Third Amendment to the Tax
Sharing Agreement with ARCO. The Third Amendment implements certain tax
assumptions made in a Stock Purchase Agreement entered into with ARCO in 1998.
Under the Stock Purchase Agreement, we agreed to acquire the stock of Western
Midway Company from ARCO for $470 million which amount was later adjusted after
closing to approximately $440 million (the Adjusted Purchase Price). We also
agreed that, for the purposes of the Tax Sharing Agreement, our tax basis in the
Western Midway Company assets on the closing date of the acquisition would be
equal to the Adjusted Purchase Price. ARCO agreed to indemnify and hold us
harmless in the event that our actual tax basis was determined to be less than
the Adjusted Purchase Price.

The Third Amendment also changes a provision in the Tax Sharing Agreement
dealing with the compensation due to us for our Section 29 tax credits in the
event we are no longer consolidated with ARCO for federal income tax purposes
("deconsolidation"). Under the Tax Sharing Agreement prior to the Third
Amendment, we were entitled to be paid for our Section 29 tax credits that are
being carried forward on the ARCO consolidated tax group's consolidated return
in the event of deconsolidation, but only to the extent those tax credits were
also being carried forward on Vastar's pro forma federal tax return (i.e., the
pro forma federal income tax return that is prepared by Vastar pursuant to the
Tax Sharing Agreement as if Vastar were not part of the ARCO consolidated tax
group). In the event of deconsolidation, the Third Amendment allows us to be
paid for our Section 29 tax credits carried forward on the ARCO consolidated tax
group's consolidated return whether or not we are also carrying forward those
tax credits on our pro forma federal tax return.

VASTAR RESOURCES, INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(Unaudited)

NOTE 8. LONG-TERM DEBT.

Our long-term debt is comprised of the following:

September 30, December 31,
1999 1998
------------- ------------
(Millions of dollars)

8.75% Notes, issued February 1995, due 2005... $ 149.6 $ 149.6
6.95% Notes, issued November 1996, due 2006*.. 75.0 75.0
6.96% Notes, issued February 1997, due 2007*.. 75.0 75.0
6.39% Notes, issued January 1998, due 2008*... 50.0 50.0
6.50% Notes, issued March 1999, due 2009...... 299.1 ---
6.00% Putable/Callable Notes, issued
April 1998, due 2010......................... 100.0 100.0
Notes due to ARCO, due 2003................... --- 300.0
Revolving Credit Agreement.................... --- 320.0
Commercial Paper.............................. 319.0 219.0
-------- --------
Total......................................... $1,067.7 $1,288.6
======== ========

- ---------------
* Issuances pursuant to our Medium-Term Note Program.

We had one interest rate swap for $100.0 million outstanding at September 30,
1999 related to the putable/callable notes. This swap will terminate in April
2000. The swap effectively changes the 6.0 percent fixed rate to a floating
rate. The financial impact of settling this swap was a favorable $0.2 million
for the third quarter 1999 and $0.5 million for the first nine months of 1999.

NOTE 9. NEW ACCOUNTING STANDARDS.

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This standard requires us to recognize all
of our derivative and hedging instruments in our statements of financial
position as either assets or liabilities and measured at fair value. In
addition, all hedging relationships must be designated, reassessed and
documented periodically. On July 7, 1999, the Financial Accounting Standards
Board delayed the effective date of SFAS 133 for one year. The delay, published
as SFAS No. 137, applies to quarterly and annual financial statements. SFAS No.
133, as revised by SFAS No. 137, is effective for all fiscal quarters of all
fiscal years beginning after June 15, 2000. We have not yet completed our
evaluation of the impact the provisions of these standards will have on us.

NOTE 10. SUBSEQUENT EVENTS.

On October 20, 1999, we declared a quarterly dividend of $0.075 per share of
common stock, payable on December 1, 1999, to our stockholders of record on
November 5, 1999.

ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS.

The following table sets forth sales and production volumes and average price
statistics for the specified periods:

For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
-------------- --------------
1999 1998 1999 1998
------ ------ ------ ------

NATURAL GAS
Sales (MMcfd)*..................... 1,389 1,380 1,475 1,358
Production (MMcfd)................. 1,043 977 1,102 940
Average sales price (per Mcf)*..... $ 2.32 $ 1.85 $ 1.96 $ 1.91
Average wellhead price (per Mcf)... $ 2.26 $ 1.79 $ 1.91 $ 1.88

CRUDE OIL
Sales (MBbld)*..................... 102.3 109.7 114.7 115.5
Production (MBbld)................. 44.7 32.8 44.8 34.6
Average realized price (per Bbl)*.. $18.23 $13.11 $14.83 $14.90

NATURAL GAS LIQUIDS ("NGLs")
Production (MBbld)................. 17.8 12.0 14.6 14.0
Average realized price (per Bbl)... $13.95 $ 8.38 $11.62 $ 9.67

Total production (MMcfed)*.......... 1,418 1,246 1,458 1,232

- --------------
* As generally used in the oil and gas business and in this Form 10-Q, the
following terms have the following meanings:
MMcfd = million cubic feet per day
Mcf = thousand cubic feet
MMcfed = million cubic feet equivalent per day
Bbl = barrel
MBbld = thousand barrels per day

In calculating Mcf and Bbl equivalents, we use a generally recognized standard
in which one Bbl is equal to six Mcf.

RESULTS OF OPERATIONS - (continued).

The following table sets forth the statement of income for the specified
periods:

For the Three For the Nine
Months Ended Months Ended
September 30, September 30,
----------------- ----------------
(Millions of dollars) 1999 1998 1999 1998
------ ------- ------ -------
REVENUES
Natural gas:
Sales.................................. $296.6 $234.7 $ 789.3 $ 710.1
Purchases.............................. (86.8) (74.8) (223.7) (241.6)
Delivery expense....................... (3.1) (2.2) (9.9) (2.8)
------ ------ ------- -------
Net sales - natural gas.............. 206.7 157.7 555.7 465.7
------ ------ ------- -------
Crude oil:
Sales.................................. 179.3 130.0 470.3 438.9
Purchases............................. (103.0) (89.2) (284.8) (294.4)
Delivery expense....................... (1.3) (1.3) (4.1) (3.8)
------ ------ ------- -------
Net sales - crude oil................. 75.0 39.5 181.4 140.7
------ ------ ------- -------
NGLs and other:
Sales.................................. 25.5 10.5 55.2 45.8
Purchases and other costs.............. (2.8) (1.1) (9.1) (9.0)
------ ------ ------- -------
Net sales - NGLs and other............ 22.7 9.4 46.1 36.8
------ ------ ------- -------
Net sales and other operating
revenues............................ 304.4 206.6 783.2 643.2
Earnings from equity affiliate.......... 4.4 5.3 13.8 15.9
Other revenues.......................... 7.3 5.4 40.2 30.3
------ ------ ------- -------
Net revenues......................... 316.1 217.3 837.2 689.4
------ ------ ------- -------
EXPENSES
Operating expenses...................... 49.8 39.6 147.3 113.2
Exploration expenses.................... 38.1 35.3 123.4 167.7
Selling, general and administrative
expenses............................... 13.7 12.6 38.8 38.8
Taxes other than income taxes........... 14.6 11.6 35.3 37.7
Depreciation, depletion and
amortization.......................... 105.9 82.3 322.8 225.6
Interest................................ 18.7 14.4 59.7 40.7
------ ------ ------- -------
Total expenses....................... 240.8 195.8 727.3 623.7
------ ------ ------- -------
Income before income taxes.............. 75.3 21.5 109.9 65.7
Income tax provision (benefit).......... 4.2 (16.1) (28.5) (52.7)
------ ------ ------- -------
Net income........................... $ 71.1 $ 37.6 $ 138.4 $ 118.4
====== ====== ======= =======

THIRD QUARTER 1999 vs. THIRD QUARTER 1998.

Our net income for the third quarter of 1999 was $71.1 million compared to $37.6
million for the third quarter of 1998. This 89 percent increase was primarily
due to higher commodity prices and higher production volumes available for sale.

Our natural gas sales revenues increased in the third quarter of 1999 as
compared to the third quarter of 1998. The increase was primarily due to a
higher average sales price. Our natural gas purchases increased in the third
quarter of 1999 as compared to the third quarter of 1998 due to higher commodity
prices, partially offset by lower purchased volumes.

The average price for natural gas sold at Henry Hub, Louisiana (a benchmark from
which general natural gas price trends can be analyzed) was $2.63 per Mcf for
the third quarter of 1999 compared to $2.00 per Mcf for the corresponding period
last year. Our wellhead price increase of $0.47 per Mcf was less than the
improvement in the Henry Hub index primarily due to the widening of the basis
differential for our gas production from the San Juan basin in the third quarter
of 1999 as compared to the corresponding period last year. Basis differential is
the difference in value between gas at one delivery point (for example Henry
Hub) and gas at another delivery point (for example San Juan basin). Natural gas
hedging activity for the third quarter of 1999 resulted in a $0.2 million gain.
Natural gas hedging activity for the third quarter of 1998 resulted in a $4.0
million gain.

Our average natural gas production in the third quarter of 1999 increased by 66
MMcfd as compared to the corresponding period last year. The higher average
production level was a result of (1) natural gas volumes contributed from our
interests in 23 Gulf of Mexico shelf fields that we acquired late last year, (2)
successful exploitation programs in the San Juan basin, Deep Anadarko, and West
Cameron 645 fields, and (3) the addition of production from last year's African
Swallow discovery. Also, only one storm-related production curtailment occurred
in the Gulf of Mexico during the quarter, compared to four such events last
year. Production increases more than offset the impact of natural production
declines that normally occur in oil and gas fields.

Crude oil sales revenues for the third quarter of 1999 increased as compared to
the third quarter of 1998, primarily due to higher commodity prices. As a result
of an agreement by OPEC countries to limit production, crude oil prices began to
improve late in the first quarter of 1999. The average market price for the
third quarter of 1999 was higher as compared to the corresponding period last
year. This difference is reflected in the third quarter 1999 average price for
NYMEX-WTI-at-Cushing (a crude oil price benchmark from which general crude oil
price trends can be analyzed) of $19.49 per Bbl compared to the average price in
the third quarter of 1998 of $13.84 per Bbl. Our realized price for crude oil
recognized a smaller price increase compared to the general market, primarily
due to the widening of the basis differential between the Gulf Coast crude
markets and the WTI-at-Cushing benchmark. The majority of our production is
located in the Gulf Coast markets.

Our average crude oil production in the third quarter of 1999 increased 36
percent as compared to the third quarter of 1998. Our crude oil production
increased primarily as a result of volumes added from our interests in 23 Gulf
of Mexico shelf fields that we acquired late last year. In addition, the third
quarter of 1998 production levels were reduced due to the shut-in of production
at selected fields related to storms experienced during this time period.
Production increases more than offset the impact of natural field declines.

Our net sales revenues for NGLs and other for the third quarter of 1999 were
higher as compared to the third quarter of 1998. Our net NGL sales revenues for
the third quarter of 1999 reflect both an increase in our average NGL production
and an increase in average NGL prices. NGL prices often fluctuate with the price
of crude oil, and as crude oil prices increased in 1999, NGL prices generally
followed the corresponding trend. Our higher NGL production was due primarily to
selective decisions during the second quarter of 1999 to re-start the extraction
of NGLs from certain wet gas streams because of favorable NGL processing
economics. NGL processing economics remained favorable throughout the third
quarter of 1999.

Our operating expenses for the third quarter of 1999 were higher than the third
quarter of 1998, primarily resulting from additional operating costs associated
with our interests in 23 Gulf of Mexico shelf fields that we acquired in late
1998.

Our exploration expenses for the third quarter of 1999 were higher than the
third quarter of 1998, primarily as a result of higher dry hole expenses. Dry
hole expenses in the third quarter of 1999 were $12.4 million, as compared to
$8.2 million in the third quarter of 1998. Of the 11 gross exploration wells
that were decisioned in the third quarter of 1999, eight were decisioned
discoveries. Of the 11 gross exploration wells that were decisioned in the third
quarter of 1998, four were decisioned discoveries. Although the number of wells
decisioned dry was smaller in the third quarter of 1999 as compared to the third
quarter of 1998, dry hole expense was higher because it included the cost of a
higher cost deepwater well.

Our depreciation, depletion and amortization expenses increased for the third
quarter of 1999 as compared to the third quarter of 1998. The increase resulted
primarily from increased production primarily associated with our interests in
23 Gulf of Mexico shelf fields that we acquired in late 1998 and higher average
depletive write-off rates.

Our interest expense for the third quarter of 1999 increased as compared to the
corresponding period last year as a result of higher average outstanding debt
levels during the third quarter of 1999 as compared to the third quarter of
1998. The increase in long-term debt is associated with our acquisition of
interests in 23 Gulf of Mexico shelf fields in late 1998.

Our income tax provision of $4.2 million for the third quarter of 1999 reflects
higher before-tax income when compared to the third quarter of 1998. The income
tax provision for the third quarter of 1999 includes the net benefit of $23.3
million of Internal Revenue Code Section 29 (Section 29) tax credits. The income
tax benefit for the third quarter of 1998 includes $23.9 million of Section 29
tax credits. Section 29 tax credits for the third quarter of 1999 were lower
than the third quarter of 1998 as a result of lower tax credit eligible
production and accounting adjustments.

NINE MONTHS ENDED SEPTEMBER 30, 1999 vs. NINE MONTHS ENDED SEPTEMBER 30, 1998.

Our net income for the first nine months of 1999 was $138.4 million compared to
$118.4 million for the first nine months of 1998. This increase was primarily
due to higher average sales prices and production volumes for all commodities
and lower exploration expenses.

Our natural gas sales revenues increased for the first nine months of 1999 as
compared to the corresponding period last year. The increase in revenues was
primarily due to a nine percent increase in natural gas volumes available for
sale. Our natural gas purchases decreased in the first nine months of 1999 as
compared to the corresponding period last year, primarily due to lower purchased
volumes.

Our average natural gas wellhead prices for the first nine months of 1999
increased approximately $0.03 per Mcf as compared to the corresponding period
last year. The average price for natural gas sold at Henry Hub, Louisiana (a
benchmark from which general natural gas price trends can be analyzed) during
the first nine months of 1999 was $2.19 per Mcf compared to $2.15 per Mcf for
the corresponding period last year. Two offsetting factors are reflected in our
average wellhead price. First, we experienced widening price differentials for
our gas production (effectively lower prices) in the first nine months of 1999
as compared to the same period last year. Offsetting the higher price
differentials was a $12.5 million gain associated with our hedging activity for
the first nine months of 1999. Hedging activity for the first nine months of
1998 resulted in a $0.9 million loss.

Our average natural gas production for the first nine months of 1999 increased
by 162 MMcfd as compared to the corresponding period last year. The higher
production level was a result of (1) natural gas production volumes added from
our interests in 23 Gulf of Mexico shelf fields we acquired late last year and
(2) production increases we achieved from new field startups and operational
improvements at Mississippi Canyon 148, West Cameron 645, Main Pass 199, the San

Juan basin and other fields. These increases more than offset the impact of (1)
natural production declines that normally occur in oil and gas fields and (2)
property sales we completed in the first nine months of 1999.

Our crude oil sales revenues for the first nine months of 1999 increased as
compared to the corresponding period last year. This increase was due to a
higher average sales price. Average sales price was $15.02 for the first nine
months of 1999. During the first nine months of 1999 crude oil prices were
volatile, as reflected in the range of crude oil prices for NYMEX-WTI-at-Cushing
from a low of $11.38 per Bbl during February 1999 to a high of $25.48 per Bbl
received in late September 1999.

The average price for the first nine months of 1999 for NYMEX-WTI-at-Cushing was
$15.90 per Bbl compared to the average price in the first nine months of 1998 of
$15.40 per Bbl. As a result of an agreement by OPEC countries to limit
production, crude oil prices began to improve late in the first quarter of 1999.
Our realized price for crude oil did not recognize the full extent of the
general market price increase because of a widening of the basis differential
(effectively lowering the price we received) between the Gulf Coast crude
markets and the WTI-at-Cushing benchmark.

Our average crude oil production for the first nine months of 1999 increased 29
percent as compared to the corresponding period last year. Our crude oil
production increased primarily as a result of volumes from our interests in 23
Gulf of Mexico shelf fields that we acquired late last year. In addition,
the third quarter of 1998 production levels were reduced due to the shut-in of
production at selected fields related to storms experienced during this time
period. Production increases more than offset the impact of natural field
declines. The majority of our production is located in the Gulf Coast markets.

Net sales revenues for NGLs and other for the first nine months of 1999 were
higher as compared to the corresponding period last year. Our net NGL and other
sales revenues for the first nine months of 1999 reflect both an increase in
commodity prices and an increase in NGL production when compared to the
corresponding period last year. NGL prices often fluctuate with the price of
crude oil, and as crude oil prices increased in 1999, NGL prices generally
followed the same trend. Our higher NGL production was due primarily to
selective decisions during the second quarter of 1999 to re-start the extraction
of NGLs from certain wet gas streams because of favorable NGL processing
economics which continued through the third quarter of 1999.

Other revenues for the first nine months of 1999 were higher as compared to the
same period of 1998. The first nine months of 1999 included net gains of $25.5
million associated with the sale of our interests in selected fields. The first
nine months of 1998 included net gains of $21.0 million of which $17.7 million
was associated with the formation of Southern Company Energy Marketing.

Our operating expenses for the first nine months of 1999 were higher than the
corresponding period last year, primarily as a result of additional operating
costs associated with our interests in 23 Gulf of Mexico shelf fields that we
acquired in late 1998.

Exploration expenses for the first nine months of 1999 were lower than the
corresponding period last year, primarily as a result of lower dry hole
expenses. Dry hole expenses in the first nine months of 1999 were $39.3 million,
as compared to $73.3 million for the corresponding period last year. This
reduction in dry hole expense is due to 13 dry holes (26 discoveries of 39 gross
wells decisioned) in the first nine months of 1999 compared to 18 dry holes (22
discoveries of 40 gross wells decisioned) in the first nine months of 1998,
along with reduced drilling rig costs during the first nine months of 1999.

Our depreciation, depletion and amortization expenses increased for the first
nine months of 1999 as compared to the corresponding period last year. The
increase resulted primarily from increased production and higher average
depletive write-off rates.

Our interest expense for the first nine months of 1999 increased as compared to
the corresponding period last year. The increase was the result of higher
average outstanding long-term debt levels during the first nine months of 1999
as compared to the first nine months of 1998. The increase in average
outstanding long-term debt is associated with our acquisition of interests in 23
Gulf of Mexico shelf fields in late 1998.

The income tax benefit for the first nine months of 1999 decreased as compared
to the same period last year. The income tax benefit of $28.5 million for the
first nine months of 1999 reflects higher pre-tax income and lower Section 29
tax credits when compared to the corresponding period last year. The income tax
benefit for the first nine months of 1999 includes the net benefit of $68.7
million of Section 29 tax credits. The income tax benefit for the first nine
months of 1998 includes $76.7 million for Section 29 tax credits. Section 29 tax
credits for the first nine months of 1999 were lower than the same period last
year as a result of lower tax credit eligible production and accounting
adjustments.

The likelihood of deferral of the Section 29 tax credits increases in a low
commodity price environment.

LIQUIDITY AND CAPITAL RESOURCES.

In the first nine months of 1999, our cash flow provided by operating activities
was $584.8 million as compared to $313.3 million for the first nine months of
1998. This increase was primarily due to (1) higher volumes and prices, (2) the
effect of monetizing the value of one of our long-term gas sales (described
below) and (3) a smaller increase in our working capital position in the first
nine months of 1999 compared to the first nine months of last year.

In July 1999, we entered into agreements with an unrelated third party that have
the effect of monetizing the value of one of our long-term gas sales contracts.
This particular contract is associated with gas sales to a certain cogeneration
facility, has a remaining life of approximately 11 years and has an expected
average price of approximately $3.00 per Mcf for 1999. Pursuant to these
agreements, we received an immediate payment of $88.0 million (net of
transaction costs) that has been recorded as a deferred liability and will be
amortized as the underlying contract volumes are delivered.

Our net cash used in investing activities in the first nine months of 1999 was
$342.7 million, which was lower compared to the first nine months of 1998. Our
capital spending was down during the first nine months of 1999 as a result of
the low commodity price environment during the early part of this year, which
led to our decision to defer some capital projects. Lower rig costs in 1999 also
contributed to our reduced spending levels.

Our proceeds from asset sales were $52.1 million in the first nine months of
1999, compared to $47.0 million received in the first nine months of 1998.

The following table summarizes our capital investments for the comparative
periods.

For the Nine Months Ended
September 30,
--------------------------------
1999 1998
(Millions of dollars) ------------ -----------

Exploratory drilling.................. $133.2 $138.8
Development drilling.................. 157.9 247.1
Property acquisitions................. 32.2 70.1
Other additions....................... 68.4 72.4
------ ------
Total additions to property,
plant and equipment.................. 391.7 528.4
Geological and geophysical............ 21.8 29.7
------ ------
Total capital program............... $413.5 $558.1
====== ======

Our cash flows used by financing activities were $235.9 million in the first
nine months of 1999, which included a $220.9 million net decrease in long-term
debt.

Vastar's ratio of earnings to fixed charges was 2.7 for the nine months ended
September 30, 1999 and 2.5 for the nine months ended September 30, 1998. We
computed these ratios by dividing earnings by fixed charges. For this
calculation, earnings include income before income taxes and fixed charges.
Fixed charges include interest, amortization of debt expenses and the estimated
interest component of rental expense.

RISK MANAGEMENT AND MARKET-SENSITIVE INSTRUMENTS.

The following discussion of our risk-management activities includes "forward-
looking statements" that involve various uncertainties. Actual results could
differ materially from those projected in the forward-looking statements. For
further information on these risks and uncertainties refer to the "Cautionary
Statement for the Purpose of the Private Litigation Reform Act of 1995" in Items
1 and 2 in our annual report on Form 10-K for the year ended December 31, 1998.

We use various financial instruments for non-trading purposes in the normal
course of our business to manage and reduce price volatility and other market
risks associated with our natural gas and petroleum liquids production. This
activity is referred to as hedging. The hedging instruments which we had in
place as of September 30, 1999, have the effect of providing a market price
within the collar not to exceed the ceiling price of the collar or a market
price plus a premium when the market price is less than the floor price of the
collar. We structure these arrangements to reduce our exposure to commodity
price decreases, but they can also limit the benefit we might otherwise receive
from commodity price increases. Our risk management activity is generally
accomplished by purchasing and/or selling exchange-traded futures and over-the-
counter options.

As a result of all of our hedging transactions for natural gas and crude oil, we
realized a pre-tax gain of approximately $12.5 million in the first nine months
of 1999 compared to a $0.1 million pre-tax loss in the first nine months of
1998.

The following table summarizes our open hedging positions as of September 30,
1999:

Average Weighted
Product Financial Instrument Time Period Volume Average Prices
- ------- -------------------- ---------------- ----------- ------------------------

Gas Collars Oct - Dec 1999 250 MMcfd $2.63Mcf - $3.31/Mcf
Gas Puts Sold Oct - Dec 1999 250 MMcfd $2.20/Mcf
Gas Collars Jan - Jun 2000 250 MMcfd $2.51/Mcf - $3.24/Mcf
Gas Puts Sold Jan - Jun 2000 250 MMcfd $2.12/Mcf

Oil Collars Oct - Dec 1999 20 MBbld $18.00/Bbl - $21.51/Bbl
Oil Puts Sold Oct - Dec 1999 20 MBbld $15.00/Bbl
Oil Collars Jan - Dec 2000 16 MBbld $18.11/Bbl - $22.36/Bbl
Oil Puts Sold Jan - Dec 2000 16 MBbld $15.11/Bbl

A "collar" is a financial instrument or a combination of financial instruments
which establishes a range of prices to be received relating to a set commodity
volume. This arrangement, in effect, allows us to receive no less than a stated
floor price per unit of volume and no more than a stated ceiling price per unit
of volume.

A "put" is an option contract that gives the holder the right to sell a stated
volume of the underlying commodity at a specified price for a certain fixed
period of time.

A "call" is an option contract that gives the holder the right to buy a stated
volume of the underlying commodity at a specified price for a certain fixed
period of time.

The fair value (our unrealized pre-tax loss or gain) for the 1999 and 2000
hedged transactions in place as of September 30, 1999 would be a $1.0 million
gain for natural gas and a $5.5 million loss for crude oil. This hypothetical
loss is calculated based on brokers' forward price quotes and NYMEX forward
price quotes as of September 30, 1999, which for the remainder of 1999 averaged
$2.77 per Mcf for natural gas and $23.81 per Bbl for crude oil. The actual gains
or losses we realize from our hedge transactions may vary significantly due to
the fluctuation of prices in the commodity markets. For example, a hypothetical
10 percent increase in the forward price quotes would decrease the unrealized
gain by approximately $1.2 million for natural gas and increase the unrealized
loss by approximately $9.5 million for crude oil. In order to calculate the
hypothetical loss, the relevant variables are (1) the type of commodity, (2) the
delivery price and (3) the delivery location. We do not take into account the
time value of money because of the short-term nature of our hedging instruments.
These calculations may be used to analyze the gains and losses we might realize
on our financial hedging contracts and do not reflect the effects of price
changes on our actual physical commodity sales. Natural gas prices fluctuated
between $1.65 per Mcf and $3.08 per Mcf (Henry Hub) and crude oil prices
fluctuated between $11.38 per Bbl and $25.48 per Bbl (NYMEX-WTI-at-Cushing)
during the first nine months of 1999.

We also have long-term natural gas sales contracts with certain cogeneration
facilities. Approximately 55 MMcfd of the approximately 80 MMcfd of natural
gas volumes related to these contracts are for a fixed price of approximately
$2.40 per Mcf for the remainder of 1999. The remainder of the volume is at
market prices. As of September 30, 1999, these contracts have a remaining life
of approximately 11 years.

During the third quarter of 1999, our long-term sales commitments did not exceed
the total of our proprietary production and the other natural gas production we
control through call rights with third-party producers and marketing agreements
with royalty owners.

Our borrowings under our commercial paper program and $1.1 billion committed
bank line of credit are subject to the risk of interest rate fluctuation.
Assuming the principal amount of our borrowings had remained unchanged, higher
interest rates would have increased our interest expense. For example, a 10
percent increase in the London Interbank Offered Rate (a benchmark pursuant to
which the Company's interest rates may be set) would have increased our third
quarter 1999 interest expense by $1.9 million.

At September 30, 1999, we had an outstanding interest rate swap covering $100
million relating to our putable/callable notes. The swap effectively changed the
fixed-rate debt of 6.0 percent to a floating rate, which averaged 5.1 percent
for the first nine months of 1999.

NEW ACCOUNTING STANDARDS.

IMPACT OF THE YEAR 2000 ISSUE.

Progress in the First Nine Months of 1999.

There have been no material developments with respect to our approach on the
Year 2000 issue as previously reported in our annual report on Form 10-K for the
year ended December 31, 1998 and our quarterly reports on Form 10-Q for the
quarters ended June 30, 1999 and March 31, 1999, except as follows.

Since the start of the project, we have incurred and expensed approximately $3.4
million related to our assessment of Year 2000 issues and the development and
implementation of our remediation plan. The total cost of the Year 2000 project,
including expenses we will incur in 2000, is currently estimated at
approximately $5.0 million. The analysis process continues, and we have made
significant additional progress. Using an average phase completion method of
estimation, we estimate approximately 98 percent of the high-priority items are
complete, with an expected completion date before the end of 1999. Similarly, we
estimate that 99 percent of the medium-priority items and 98 percent of the low-
priority items are complete. The activities relating to the medium- and low-
priority items may not be completed by January 1, 2000, but we continue to
believe that the failure of those items to be Year 2000 ready will not have a
material adverse effect on our financial condition, cash flows or results of
operations.

Systems we obtained as part of property acquisitions since September 30, 1999
are not included in the above estimates. Year 2000 items will be addressed as
part of consolidating these properties into Vastar.

In addition to assessing our own systems that may be affected by the Year 2000
issue, we continued our efforts in the first nine months of 1999 to determine if
we will be affected by Year 2000 issues affecting third parties with which we
have material relationships. The complexity of our analysis is increased because
of our dependence on the representations of these third parties and the
correctness of their assessments of their Year 2000 issues, including their
exposures to third-party risks. This analysis is substantially complete and all
high-priority items which we have identified are being addressed and are
expected to be resolved before the end of 1999.

Further, we are continuing our process of developing contingency plans to handle
the most reasonably likely worst case scenarios caused by an interrelated

IMPACT OF THE YEAR 2000 ISSUE - (continued).

failure of key components or widespread outages of key services. Our enterprise-
wide contingency planning is complete. Implementation and refinement of the
enterprise-wide plan will continue until year-end.

Conclusion.

The most significant difficulty associated with predicting the impact of Year
2000 failures stems from the interdependence of the various third parties on
which we rely. As a result of the general uncertainty inherent in the Year 2000
problem, we are unable to determine at this time whether the consequences of
Year 2000 failures would have a material impact on our results of operations,
cash flows or financial condition. Completion of our Year 2000 readiness program
as scheduled is expected to reduce the possibility of significant interruptions
of normal operations.

The preceding discussion of our Year 2000 readiness includes forward-looking
statements that involve risks and uncertainties. Actual results could differ
materially from those projected in the forward-looking statements. For further
information on these risks and uncertainties refer to the "Cautionary Statement
for the Purpose of the Private Litigation Reform Act of 1995" in Items 1 and 2
in our Form 10-K for the year ended December 31, 1998. This disclosure is also
subject to protection under the Year 2000 Information and Readiness Disclosure
Act of 1998, Public Law 105-271, as a "Year 2000 Statement" and "Year 2000
Readiness Disclosure" as defined therein.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

See Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations--Risk Management and Market-Sensitive Instruments.

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

We caution against projecting any future results based on present earnings
levels because of economic uncertainties, the extent and form of existing or
future governmental regulations and other possible actions by governments.

The foregoing financial information is unaudited and has been prepared from the
books and records of Vastar. In the opinion of our management, the financial
information reflects all adjustments, consisting only of normal recurring
adjustments, necessary for the fair presentation of the financial position,
results of operations and cash flows in conformity with generally accepted
accounting principles.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

There have been no material developments with respect to Vastar's legal
proceedings as previously reported in our annual report on Form 10-K for the
period ending December 31, 1998 and our quarterly reports on Form 10-Q for the
quarterly periods ending June 30 and March 31, 1999.

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits.

. 4.1 Vastar Resources, Inc. $50,000,000 Medium-Term Notes Series A due
January 15, 2008--form of Note

4.2 Vastar Resources, Inc. $75,000,000 Medium-Term Notes Series A due
November 8, 2006--form of Note

4.3 Vastar Resources, Inc. $75,000,000 Medium-Term Notes Series A due
February 26, 2007--form of Note

4.4 Vastar Resources, Inc. $150,000,000 8.75% Notes due February 1,
2005--form of Note

4.5 Vastar Resources, Inc. $100,000,000 6.50% Notes due April 1,
2009--form of Note

4.6 Vastar Resources, Inc. $200,000,000 6.50% Notes due April 1,
2009--form of Note

4.7 Vastar Resources, Inc. $100,000,000 Putable/Callable Notes, due
April 20, 2010, Putable/Callable April 20, 2000--form of Note

10.1 Third Amendment to Tax Sharing Agreement, effective as of October
30, 1998, between Vastar and its subsidiaries that are signatories
thereto and ARCO

10.2 Second Amendment to Vastar Annual Incentive Plan, effective as
of July 21, 1999

10.3 First Amendment to Vastar Executive Deferral Plan, effective as
of July 21, 1999

10.4 First Amendment to Vastar Comprehensive Management Medical Plan,
effective as of July 21, 1999

10.5 First Amendment to Vastar Executive Medical Plan, effective as of
July 21, 1999

10.6 Second Amendment to Vastar Executive Life Insurance Plan, effective
as of July 21, 1999

10.7 First Amendment to Amended and Restated Executive Long-Term Incentive
Plan, effective as of July 21, 1999

10.8 First Amendment to Vastar Amended and Restated Supplementary
Executive Retirement Plan, effective as of July 21, 1999

10.9 Third Amendment to Special Termination Allowance Plan, effective as
of July 21, 1999

12 Computation of Ratio of Earnings to Fixed Charges

27 Financial Data Schedule

(b) Reports on Form 8-K.

Vastar did not file any reports on Form 8-K during the quarter ended September
30, 1999.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

VASTAR RESOURCES, INC.
(Registrant)

Dated: October 28, 1999 /s/ Joseph P. McCoy
------------------------------
Joseph P. McCoy
Vice President and Controller
(Duly Authorized Officer and
Principal Accounting Officer)

EXHIBIT INDEX

Exhibit
No. Description
- ---------- -----------

4.1 Vastar Resources, Inc. $50,000,000 Medium-Term Notes Series A due
January 15, 2008--form of Note

4.2 Vastar Resources, Inc. $75,000,000 Medium-Term Notes Series A due
November 8, 2006--form of Note

4.3 Vastar Resources, Inc. $75,000,000 Medium-Term Notes Series A due
February 26, 2007--form of Note

4.4 Vastar Resources, Inc. $150,000,000 8.75% Notes due February 1,
2005--form of Note

4.5 Vastar Resources, Inc. $100,000,000 6.50% Notes due April 1,
2009--form of Note

4.6 Vastar Resources, Inc. $200,000,000 6.50% Notes due April 1,
2009--form of Note

4.7 Vastar Resources, Inc. $100,000,000 Putable/Callable Notes, due
April 20, 2010, Putable/Callable April 20, 2000--form of Note

10.1 Third Amendment to Tax Sharing Agreement, effective as of October
30, 1998, between Vastar and its subsidiaries that are
signatories thereto and ARCO

10.2 Second Amendment to Vastar Annual Incentive Plan, effective as
of July 21, 1999

10.3 First Amendment to Vastar Executive Deferral Plan, effective as
of July 21, 1999

10.4 First Amendment to Vastar Comprehensive Management Medical Plan,
effective as of July 21, 1999

10.5 First Amendment to Vastar Executive Medical Plan, effective as of
July 21, 1999

10.6 Second Amendment to Vastar Executive Life Insurance Plan,
effective as of July 21, 1999

10.7 First Amendment to Amended and Restated Executive Long-Term
Incentive Plan, effective as of July 21, 1999

10.8 First Amendment to Vastar Amended and Restated Supplementary
Executive Retirement Plan, effective as of July 21, 1999

10.9 Third Amendment to Special Termination Allowance Plan, effective
as of July 21, 1999

12 Computation of Ratio of Earnings to Fixed Charges

27 Financial Data Schedule