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 JUNE 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
JUNE 30, 1999: 97,484,948.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

VASTAR RESOURCES, INC.
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

CONSOLIDATED STATEMENT OF INCOME

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

REVENUES
Net sales and other operating
revenues............................. $257.6 $219.2 $478.8 $436.6
Earnings from equity affiliate........ 4.4 5.3 9.4 10.6
Other revenues........................ 19.7 4.2 32.9 24.9
------ ------ ------ ------
Net revenues....................... 281.7 228.7 521.1 472.1
------ ------ ------ ------
EXPENSES
Operating expenses.................... 47.0 39.1 97.5 73.6
Exploration expenses.................. 46.3 64.2 85.3 132.4
Selling, general and administrative
expenses............................. 12.4 14.2 25.1 26.2
Taxes other than income taxes......... 11.9 13.1 20.7 26.1
Depreciation, depletion and
amortization......................... 103.6 72.8 216.9 143.3
Interest.............................. 20.5 13.7 41.0 26.3
------ ------ ------ ------
Total expenses..................... 241.7 217.1 486.5 427.9
------ ------ ------ ------
Income before income taxes............ 40.0 11.6 34.6 44.2
Income tax benefit.................... (8.3) (21.2) (32.7) (36.6)
------ ------ ------ ------
Net income.......................... $ 48.3 $ 32.8 $ 67.3 $ 80.8
====== ====== ====== ======

Basic earnings per share.............. $ 0.49 $ 0.34 $ 0.69 $ 0.83
====== ====== ====== ======
Diluted earnings per share............ $ 0.49 $ 0.34 $ 0.68 $ 0.83
====== ====== ====== ======

Cash dividends paid per share
of common stock....................... $0.075 $0.075 $0.150 $0.150
====== ====== ====== ======

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

VASTAR RESOURCES, INC.
CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

CONSOLIDATED BALANCE SHEET

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

ASSETS
Current assets:
Cash and cash equivalents...................... $ 20.6 $ 4.3
Accounts receivable:
Trade......................................... 135.2 110.0
Related parties............................... 100.5 130.9
Inventories.................................... 7.2 10.2
Prepaid expenses and other assets.............. 16.6 37.5
-------- --------
Total current assets.......................... 280.1 292.9

Oil and gas properties and equipment, net....... 2,205.3 2,220.8
Other long-term assets.......................... 75.4 60.3
-------- --------
Total assets.................................. $2,560.8 $2,574.0
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade......................................... $ 180.8 $ 179.2
Related parties............................... 8.3 9.8
Accrued liabilities............................ 39.3 61.5
-------- --------
Total current liabilities.................... 228.4 250.5

Long-term debt.................................. 1,248.0 1,288.6
Deferred liabilities and credits................ 210.6 205.4
Deferred income taxes........................... 203.6 214.3
-------- --------
Total liabilities............................. 1,890.6 1,958.8

COMMITMENTS AND CONTINGENCIES

STOCKHOLDERS' EQUITY
Common stock, $.01 par value; authorized,
110,000,000 shares; issued and outstanding,
97,484,948 shares as of June 30, 1999 and
97,403,340 shares as of December 31, 1998...... 1.0 1.0
Capital in excess of par value of stock......... 459.7 457.4
Accumulated earnings............................ 209.5 156.8
-------- --------
Total stockholders' equity.................... 670.2 615.2
-------- --------
Total liabilities and stockholders' equity...... $2,560.8 $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 Six Months Ended
June 30,
------------------------
1999 1998
(Millions of dollars) ------- -------

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................... $ 67.3 $ 80.8
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization........... 216.9 143.3
Deferred income taxes.............................. (10.7) 7.2
Dry hole expense and undeveloped leasehold
amortization..................................... 44.4 82.6
Gain on asset sales................................ (23.4) (20.1)
Earnings from equity affiliate..................... (9.4) (10.6)
Net change in accounts receivable, inventories
and accounts payable............................. 8.3 (30.1)
Other.............................................. (18.4) (30.0)
------- -------
Net cash provided by operating activities............ 275.0 223.1
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties and equipment,
including dry hole costs.......................... (251.5) (363.3)
Proceeds from asset sales............................ 48.7 43.9
Other................................................ (3.0) 2.8
------- -------
Net cash used by investing activities................ (205.8) (316.6)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock............................. 2.3 3.7
Proceeds from long-term debt issuance................ 604.7 150.0
Repayments of long-term debt......................... (645.3) (51.2)
Dividends paid....................................... (14.6) (14.6)
------- -------
Net cash provided (used) by financing activities..... (52.9) 87.9
------- -------
Net change in cash and cash equivalents.............. 16.3 (5.6)

Cash and cash equivalents at beginning of period..... 4.3 10.2
------- -------
Cash and cash equivalents at end of period........... $ 20.6 $ 4.6
======= =======

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 (1)
the annual financial statements for the year ended December 31, 1998, and the
related Notes contained in our Form 10-K for the year ended December 31, 1998,
and (2) the quarterly financial statements for the quarter ended March 31, 1999,
and the related notes in our Form 10-Q for the quarter ended March 31, 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 Six
Months Ended Months Ended
June 30, June 30,
------------- ------------------
1999 1998 1999 1998
(Millions of dollars) -------- --------- -------- --------

Sales and other operating revenues:
Unrelated parties.................... $ 267.5 $ 195.7 $ 456.1 $ 412.3
Related parties (1).................. 192.1 216.0 357.3 407.3
------- ------- ------- -------
Total............................... 459.6 411.7 813.4 819.6

Less:
Purchases (2)........................ (194.0) (190.1) (324.3) (378.7)
Delivery expense..................... (8.0) (2.4) (10.3) (4.3)
------- ------- ------- -------
Net sales and
other operating revenues............. $ 257.6 $ 219.2 $ 478.8 $ 436.6
======= ======= ======= =======
- ---------------

(1) The weighted average lifting and purchase cost per thousand cubic feet
equivalent which we incurred in connection with our proprietary production and
volumes purchased from third-parties multiplied by the volumes we sold to
related parties results in average costs of (a) $171.8 million for the three
months ended June 30, 1999, (b) $175.8 million for the three months ended June
30, 1998, (c) $340.0 million for the six months ended June 30, 1999, and (d)
$337.0 million for the six months ended June 30, 1998.

(2) Includes volumes we purchased from related parties at a cost of (a) $17.3
million for the three months ended June 30, 1999, (b) $33.4 million for the
three months ended June 30, 1998, (c) $33.6 million for the six months ended
June 30, 1999, and (d) $57.3 million for the six months ended June 30, 1998.

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 $44.0 million equity investment in Southern
Company Energy Marketing is reflected as a long-term asset in our
consolidated balance sheet. We recorded revenues related to the earnings from
Southern Company Energy Marketing of (1) $4.4 million for the three months ended
June 30, 1999, (2) $5.3 million for the three months ended June 30, 1998, (3)
$9.4 million for the six months ended June 30, 1999, and (4) $10.6 million for
the six months ended June 30, 1998.

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. We are recognizing our accrued share of the 1999 minimum earnings
level within the current period, net of any contractual obligations. For
additional details, 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 Six
Months Ended Months Ended
June 30, June 30,
------------- --------------
(Millions of dollars) 1999 1998 1999 1998
----- ----- ------ -----

Dry hole costs....................... $21.5 $38.1 $26.9 $ 65.1
Geological and geophysical........... 4.1 3.8 18.2 25.1
Undeveloped leasehold amortization... 8.8 8.7 17.5 17.5
Staff................................ 10.0 10.9 19.4 21.0
Lease rentals........................ 1.9 2.7 3.3 3.7
----- ----- ----- ------
Total............................... $46.3 $64.2 $85.3 $132.4
===== ===== ===== ======

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

NOTE 5. EARNINGS PER SHARE.

For the For the
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
----- ----- ----- -----

(In millions, except per share amounts)

Basic earnings per share:
Income available to common shareholders.... $48.3 $32.8 $67.3 $80.8
Average shares of stock outstanding........ 97.5 97.3 97.4 97.3
Basic earnings per share.................... $0.49 $0.34 $0.69 $0.83

Diluted earnings per share:
Income available to common shareholders.... $48.3 $32.8 $67.3 $80.8
Incremental shares assuming the exercise
of stock options.......................... 0.9 0.7 0.9 0.6
Average shares of stock outstanding plus
effect of dilutive securities............. 98.4 98.0 98.3 97.9
Diluted earnings per share.................. $0.49 $0.34 $0.68 $0.83

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 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. The exercise prices of
the stock options reflected in the table below range from $14.00 to $46.66 per
share. Stock options outstanding as of June 30, 1999 consisted of the following:

Vested and exercisable(1)......... 1.4 million
Vested and unexercisable.......... 0.6 million
Non-vested........................ 0.5 million
-------------
Total............................. 2.5 million
-------------
(1) Stock options generally vest one year after the date of grant, and 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.

In March 1999, ARCO (Atlantic Richfield Company), which owns 82.1 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 Long-Term
Incentive Plan. For additional information on the change of control
arrangements, refer to our 1999 Proxy Statement filed with the SEC on March 23,
1999. We filed a copy of the Amended and Restated Long-Term Incentive Plan
as Appendix A to our 1998 Proxy Statement, 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 and our subsidiaries are involved in a number of lawsuits, all of which have
arisen in the ordinary course of our business. We believe that any ultimate
liability resulting from these suits 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 that 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 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 June 30, 1999 of 1.7 years. Remaining costs for this
contract and other contracts for related support boats are approximately $102.0
million. This amount does not take into consideration any reimbursements we
might receive from partners or potential partners.

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.

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
other 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 June 30, 1999 and 1998, were insignificant.

In March 1999, ARCO entered into a merger agreement with BP Amoco, p.l.c. The
merger is subject to the approval of ARCO's shareholders, BP Amoco's
shareholders and various regulatory authorities. ARCO and Vastar have entered
into a number of agreements, including technology assignments and licenses,
services agreements, insurance agreements and a building lease. These agreements
are more fully described in our 1999 Proxy Statement 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 benefit for taxes on income is comprised of the following:

For the Three For the Six
Months Ended Months Ended
June 30, June 30,
----------------- -----------------
(Millions of dollars) 1999 1998 1999 1998
------- ------- ------- -------

Federal:
Current................... $(15.4) $(23.2) $(22.1) $(44.5)
Deferred.................. 6.1 1.8 (11.5) 7.0
------ ------ ------ ------
Total federal............ (9.3) (21.4) (33.6) (37.5)
------ ------ ------ ------
State:
Current................... 0.1 0.3 0.1 0.7
Deferred.................. 0.9 (0.1) 0.8 0.2
------ ------ ------ ------
Total state.............. 1.0 0.2 0.9 0.9
------ ------ ------ ------
Total income tax benefit... $ (8.3) $(21.2) $(32.7) $(36.6)
====== ====== ====== ======

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

For the Three For the Six
Months Ended Months Ended
June 30, June 30,
----------------- -----------------
(Millions of dollars) 1999 1998 1999 1998
------- ------- ------- -------

Income before taxes............. $ 40.0 $ 11.6 $ 34.6 $ 44.2
====== ====== ====== ======
Tax at the statutory rate....... $ 14.0 $ 4.1 $ 12.1 $ 15.5
Increase (reduction) in taxes
resulting from:
State income taxes (net
of federal effect)........... 0.7 0.2 0.6 0.6
Tax credits and other......... (23.0) (25.5) (45.4) (52.7)
------ ------ ------ ------
Income tax benefit.............. $ (8.3) $(21.2) $(32.7) $(36.6)
====== ====== ====== ======

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 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, 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. The likelihood of deferral of the Section 29 tax credits increases in a
low commodity price environment. Given the range of commodity prices during the
first six months of this year, it is difficult to predict the timing of cash
receipts from tax credits.

NOTE 8. LONG-TERM DEBT.

Long-term debt is comprised of the following:

June 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............................... 499.3 219.0
-------- --------
Total.......................................... $1,248.0 $1,288.6
======== ========

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

We had one interest rate swap for $100.0 million outstanding at June 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 immaterial.

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

NOTE 9. NEW ACCOUNTING STANDARDS.

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 (SFAS 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 Statement of Financial Accounting Standards No. 137 (SFAS 137), applies to
quarterly and annual financial statements. SFAS 133, as revised by SFAS 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 July 21, 1999, we declared a quarterly dividend of $0.075 per share of common
stock, payable on September 1, 1999, to our stockholders of record
on August 6, 1999.

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
with a certain cogeneration facility. The long-term gas sales contract has a
remaining life of approximately 11 years and has an expected average price of
approximately $3.00 per Mcf for 1999. Pursuant to the agreements we received an
immediate payment of $88.0 million (net of transaction costs) that will be
recorded as a deferred liability and amortized as the underlying contract
volumes are delivered.

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:

Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
1999 1998 1999 1998
-------- ------- ------- ------

NATURAL GAS
Sales (MMcfd)*................................. 1,472 1,394 1,519 1,347
Production (MMcfd)............................. 1,095 940 1,132 921
Average sales price (per Mcf)*................. $ 1.98 $ 2.00 $ 1.79 $ 1.95
Average wellhead price (per Mcf)............... $ 1.89 $ 1.94 $ 1.75 $ 1.93

CRUDE OIL
Sales (MBbld)*................................. 123.9 116.9 120.9 118.5
Production (MBbld)............................. 43.1 35.0 44.9 35.5
Average realized price (per Bbl)*.............. $15.20 $14.36 $13.11 $15.74

NATURAL GAS LIQUIDS ("NGLs")
Production (MBbld)............................. 16.6 14.4 12.9 15.0
Average realized price (per Bbl)............... $11.02 $ 9.35 $ 9.99 $10.19

Total production (MMcfed)*...................... 1,453 1,236 1,479 1,224

- ---------------------
* 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:

Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
(Millions of dollars) 1999 1998 1999 1998
------ ------ ------- -------

REVENUES
Natural gas:
Sales.................................. $265.6 $253.4 $ 492.7 $ 475.4
Purchases.............................. (78.0) (91.5) (136.9) (166.8)
Delivery expense....................... (6.2) (0.5) (6.8) (0.6)
------ ------ ------- -------
Net sales - natural gas.............. 181.4 161.4 349.0 308.0
------ ------ ------- -------
Crude oil:
Sales.................................. 173.5 142.0 291.0 308.9
Purchases.............................. (112.6) (95.2) (181.8) (205.2)
Delivery expense....................... (1.4) (1.1) (2.8) (2.5)
------ ------ ------- -------
Net sales - crude oil................. 59.5 45.7 106.4 101.2
------ ------ ------- -------
NGLs and other:
Sales.................................. 20.5 16.3 29.7 35.3
Purchases and other costs.............. (3.8) (4.2) (6.3) (7.9)
------ ------ ------- -------
Net sales - NGLs and other............ 16.7 12.1 23.4 27.4
------ ------ ------- -------
Net sales and other operating
revenues............................ 257.6 219.2 478.8 436.6
Earnings from equity affiliate.......... 4.4 5.3 9.4 10.6
Other revenues.......................... 19.7 4.2 32.9 24.9
------ ------ ------- -------
Net revenues.......................... 281.7 228.7 521.1 472.1
------ ------ ------- -------
EXPENSES
Operating expenses...................... 47.0 39.1 97.5 73.6
Exploration expenses.................... 46.3 64.2 85.3 132.4
Selling, general and administrative
expenses............................... 12.4 14.2 25.1 26.2
Taxes other than income taxes........... 11.9 13.1 20.7 26.1
Depreciation, depletion and
amortization........................... 103.6 72.8 216.9 143.3
Interest................................ 20.5 13.7 41.0 26.3
------ ------ ------- -------
Total expenses........................ 241.7 217.1 486.5 427.9
------ ------ ------- -------
Income before income taxes.............. 40.0 11.6 34.6 44.2
Income tax benefit...................... (8.3) (21.2) (32.7) (36.6)
------ ------ ------- -------
Net income............................ $ 48.3 $ 32.8 $ 67.3 $ 80.8
====== ====== ======= =======

SECOND QUARTER 1999 vs. SECOND QUARTER 1998.

Our net income for the second quarter of 1999 was $48.3 million compared to
$32.8 million for the second quarter of 1998. This 47 percent increase was
primarily due to (1) higher production volumes available for sale, (2) lower dry
hole expenses and (3) gains from property sales, partially offset by higher
operating, depreciation, depletion and amortization and interest expenses.

Natural gas sales revenues increased in the second quarter of 1999 as compared
to the second quarter of 1998. The increase was due to a 6 percent increase in
natural gas volumes available for sale, partially offset by a small decrease in
average sales prices. Natural gas purchases decreased in the second quarter of
1999 as compared to the second quarter of 1998, due to lower commodity prices
and lower purchased volumes.

Our average natural gas wellhead prices for the second quarter of 1999 decreased
five cents per Mcf from second quarter 1998 levels. The average price for
natural gas sold at Henry Hub, Louisiana (a benchmark from which general natural
gas price trends can be analyzed) was $2.17 per Mcf for the second quarter of
1999 compared to $2.23 per Mcf for the corresponding period last year. When
compared to the second quarter of 1998, our average wellhead price decline in
the second quarter of 1999 was slightly less than the general market decline at
Henry Hub because of the favorable benefit from our natural gas hedging activity
in the second quarter of 1999.

Our average natural gas production in the second quarter of 1999 increased by
155 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 and
(2) natural gas production increases we achieved from West Cameron 645,
Mississippi Canyon 148, Main Pass 199, High Island 169, Santa Ana field in South
Texas and the San Juan basin and other fields. These production increases more
than offset the impact of natural production declines that normally occur in oil
and gas fields and the impact of a mid-continent property sale we completed in
the second quarter of 1999.

Crude oil sales revenues for the second quarter of 1999 increased as compared to
the second quarter of 1998 due to higher commodity prices and volumes available
for sale. 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 second quarter of 1999 was higher as compared to the
corresponding period last year. This difference is reflected in the second
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 $16.35 per Bbl
compared to the average price in the second quarter of 1998 of $15.13 per Bbl.
Our realized price for crude oil recognized the same price increase as the
general market but was impacted by the widening of the price differential
between the Gulf Coast crude markets and the WTI-at-Cushing benchmark.

Our average crude oil production in the second quarter of 1999 increased 23
percent as compared to the second quarter of 1998. 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. These increases more
than offset the impact of natural production declines that normally occur in oil
and gas fields.

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

Other revenues for the second quarter of 1999 were higher as compared to the
second quarter of 1998. The second quarter of 1999 included a $14.8 million pre-
tax gain associated with the sale of our interests in selected oil and gas
fields.

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

Exploration expenses for the second quarter of 1999 were lower than the second
quarter of 1998, primarily as a result of lower dry hole expenses. Dry hole
expenses in the second quarter of 1999 were $21.5 million, as compared to $38.1
million in the second quarter of 1998. Of the 14 exploration wells that were
decisioned in the second quarter of 1999, seven were declared successful. Of
the 13 exploration wells that were decisioned in the second quarter of 1998, six
were declared successful.

Depreciation, depletion and amortization expenses increased for the second
quarter of 1999 as compared to the second quarter of 1998. The increase resulted
primarily from increased production and higher average depletive write-off
rates.

Interest expense for the second quarter of 1999 increased $6.8 million as
compared to the corresponding period last year. The increase was the result of
higher average outstanding debt levels during the second quarter of 1999 as
compared to the second quarter of 1998. The increase in long-term debt is
associated with our acquisition of 23 Gulf of Mexico shelf properties in late
1998.

The income tax benefit of $8.3 million for the second quarter of 1999 reflects
higher before-tax income when compared to the corresponding quarter last year.
The income tax benefit for the second quarter of 1999 included the net benefit
of $23.0 million of Internal Revenue Code Section 29 tax credits for non-
conventional fuels. The income tax benefit for the second quarter of 1998
included $25.5 million for Section 29 tax credits. Section 29 tax credits for
the second quarter of 1999 were lower than the second quarter of 1998 as a
result of accounting adjustments.

SIX MONTHS ENDED JUNE 30, 1999 vs. SIX MONTHS ENDED JUNE 30, 1998.

Our net income for the first six months of 1999 was $67.3 million compared to
$80.8 million for the first six months of 1998. This decrease was primarily due
to (1) lower average commodity prices, (2) higher operating expense, (3) higher
depreciation, depletion and amortization expenses and (4) higher interest
expense. These impacts were partially offset by higher volumes available for
sale and lower dry hole expenses.

Our natural gas sales revenues increased for the first six months of 1999 as
compared to the corresponding period last year. The increase in revenues was
due to a 13 percent increase in natural gas volumes available for sale,
partially offset by a decrease in sales prices. Our natural gas purchases
decreased in the first six months of 1999 as compared to the corresponding
period last year, primarily due to the lower commodity prices.

Our average natural gas wellhead prices for the first six months of 1999
decreased 18 cents per Mcf as compared to the corresponding period last year.
This decrease was primarily due to lower commodity prices experienced during the
first half of 1999 as compared to the first half of 1998. 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 six months of 1999 was $1.97
per Mcf compared to $2.22 per Mcf for the corresponding period last year. When
compared to the first six months of 1998, our wellhead price decline in the
first six months of 1999 was less than the general market decline at Henry Hub
because (1) the prices for our production in the San Juan basin did not decline
as much as at Henry Hub and (2) our natural gas hedging activity for the first
six months of 1999 resulted in a $12.4 million gain as compared to a $4.9
million loss in the first six months of 1998.

Average natural gas production for the first six months of 1999 increased by 211
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 that 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 half of 1999.

Crude oil sales revenues for the first half of 1999 decreased as compared to the
corresponding period last year. This decrease was due to lower commodity prices.
During the first six 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 $19.28 per Bbl at the end of
June 1999. The average market price for the first half of 1999 was lower as
compared to the corresponding period last year. This difference is reflected in
the average price for the first six months of 1999 for NYMEX-WTI-at-Cushing of
$14.10 per Bbl compared to the average price in the first half of 1998 of $16.19
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 1999.

Our average crude oil production for the first six months of 1999 increased 26
percent as compared to the corresponding period last year. 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. These production increases
more than offset the impact of natural field declines.

Net sales revenues for NGLs for the first half of 1999 were lower as compared to
the corresponding period last year. Our net NGL sales revenues for the first
half of 1999 reflect both a decrease in commodity prices and a decrease in NGL
production when compared to the corresponding period last year. NGL prices
often fluctuate with the price of crude oil. Our lower NGL production
was primarily due to selective decisions to bypass the NGL extraction process in
order to capture a higher value in the natural gas price primarily during the
first quarter of 1999.

Other revenues for the first half of 1999 were higher as compared to the first
half of 1998. The first half of 1999 included net gains of $23.4 million
associated with the sale of our interests in selected fields. The first half of
1998 included a $17.7 million gain associated with the formation of Southern
Company Energy Marketing.

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

Exploration expenses for the first half 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 half of 1999 were $26.9 million, as
compared to $65.1 million for the corresponding period last year. Of the 28
exploration wells that were decisioned in the first half of 1999, 18 were
declared successful. Of the 29 exploration wells that were decisioned in the
first half of 1998, 18 were declared successful.

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

Interest expense for the first half of 1999 increased $14.7 million as compared
to the corresponding period last year. The increase was the result of higher
average outstanding long-term debt levels during the first half of 1999 as
compared to the first half of 1998. The increase in debt is associated with our
acquisition of 23 Gulf of Mexico shelf properties in late 1998.

The income tax benefit of $32.7 million for the first half of 1999 reflects
lower before-tax income and lower tax credits when compared to the corresponding
period last year. The income tax benefit for the first half of 1999 included
the net benefit of $45.4 million of Internal Revenue Code Section 29 tax credits
for non-conventional fuels. The income tax benefit for the first half of 1998
included $52.8 million for Section 29 tax credits.

LIQUIDITY AND CAPITAL RESOURCES.

In the first half of 1999, our cash flow provided by operating activities was
$275.0 million as compared to $223.1 million for the first half of 1998. This
increase was primarily due to a draw down in our working capital position in the
first half of 1999 compared to a build in working capital during the first half
of last year.

Our net cash used in investing activities in the first half of 1999 was $205.8
million, which was lower compared to the first half of 1998. Our capital
spending was down during the first six 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 $48.7 million in the first six months of
1999, compared to $43.9 million received in the first six months of 1998.

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

For the Six Months Ended
June 30,
------------------------------
1999 1998
(Millions of dollars) ------------ -----------

Exploratory drilling.................... $ 85.6 $101.3
Development drilling.................... 97.6 159.9
Property acquisitions................... 26.4 54.6
Other additions......................... 41.9 47.5
------ ------
Total additions to property,
plant and equipment.................... 251.5 363.3
Geological and geophysical.............. 18.2 25.1
------ ------
Total capital program................. $269.7 $388.4
====== ======

Our cash flows used by financing activities were $52.9 million in the first
half of 1999, which included a $40.6 million net decrease in long-term debt.

Vastar's ratio of earnings to fixed charges was 1.8 for the six months ended
June 30, 1999 and 2.6 for the six months ended June 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. Refer
to the "Cautionary Statement for Purposes of the Private Litigation Reform Act
of 1995" in Items 1 and 2 of 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 have used
have the effect of providing a market related price plus a premium and/or
minimum price that we will receive for the volumes and the time periods
identified in the instruments. 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 $12.4 million in the first six months
of 1999 compared to a $4.1 million pre-tax loss in the first six months of 1998.

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

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

Gas Collars July - Sept 1999 100 MMcfd $2.35/Mcf - $3.00/Mcf
Gas Puts Sold July - Sept 1999 100 MMcfd $2.05/Mcf

In July 1999, we entered into the following additional positions:

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

Gas Collars Oct - Dec 1999 100 MMcfd $2.50/Mcf - $3.20/Mcf
Gas Puts Sold Oct - Dec 1999 100 MMcfd $2.15/Mcf
Gas Collars Jan - Jun 2000 200 MMcfd $2.44/Mcf - $3.19/Mcf
Gas Puts Sold Jan - Jun 2000 200 MMcfd $2.08/Mcf

Oil Collars July - Dec 1999 12 MBbld $18.00/Bbl - $21.49/Bbl
Oil Puts Sold July - Dec 1999 12 MBbld $15.00/Bbl
Oil Collars Jan - Dec 2000 15 MBbld $17.87/Bbl - $22.13/Bbl
Oil Puts Sold Jan - Dec 2000 15 MBbld $14.87/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 hedged
transactions in place as of June 30, 1999 would be a $0.5 million loss. This
hypothetical loss is calculated based on broker's forward price quotes and NYMEX
forward price quotes as of June 30, 1999, which averaged $2.47 per Mcf for the
remainder of 1999. We had no oil hedges outstanding as of June 30, 1999. 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
result in an immaterial change to our unrealized loss position. 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 $2.42 per Mcf (Henry Hub) and crude
oil prices fluctuated between $11.38 per Bbl and $19.28 per Bbl (NYMEX-WTI-at-
Cushing) during the first six months of 1999.

We also have long-term contracts with certain cogeneration facilities. As of
June 30, 1999, these contracts cover an average of approximately 77 MMcfd of our
natural gas production for the remainder of 1999 at approximately $2.58 per Mcf
and have a remaining life of approximately 11 years.

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

During the second 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 interest rate risk. Assuming the principal
amount of our borrowings had remained unchanged, higher interest rates would
have increased 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 second quarter 1999 interest
expense by $2.6 million.

At June 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 5.0 percent for the
first six months of 1999.

NEW ACCOUNTING STANDARDS.

IMPACT OF THE YEAR 2000 ISSUE.

Progress in the First Six 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 report on Form 10-Q for the
quarter ended March 31, 1999, except as follows.

Since the start of the project, we have incurred and expensed approximately $2.7
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 that will be incurred 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 94 percent of the high priority items are
complete with an expected completion date before the end of 1999. Similarly, we
estimate that 96 percent of the medium-priority items and 89 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.

In addition to assessing our own systems that may be affected by the Year 2000
issue, we continued our efforts in the first six 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
failure of key components or widespread outages of key services. Our enterprise-
wide contingency planning continues and we expect it to be completed during
August 1999.

IMPACT OF THE YEAR 2000 ISSUE - (continued).

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. Please 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 for further information on these risks and uncertainties. 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 Report on Form 10-K for the period
ending December 31, 1998 and our Report on Form 10-Q for the period ending March
31, 1999.

Item 4. Submission of Matters to a Vote of Security Holders.

Vastar's Annual Meeting of Stockholders was held on May 19, 1999, in Houston,
Texas. Stockholders voted on the election of nine directors for a one-year term
expiring in 2000 and the appointment of independent accountants for the year
1999. The voting results on these matters were as follows.

(a) Election of Directors:

Votes Received Votes Broker
Nominee For Withheld Non-Votes
- ---------------------------- ------------------------- -------------------- -------------------

Jimmie D. Callison 92,713,517 587,538 -0-
Terry G. Dallas 92,641,093 659,962 -0-
Charles D. Davidson 92,723,929 577,126 -0-
Marie L. Knowles 92,509,288 791,767 -0-
Robert C. LeVine 92,717,895 583,160 -0-
William D. Schulte 92,888,843 412,212 -0-
Steven J. Shapiro 92,723,820 577,235 -0-
Donald R. Voelte 92,659,226 641,829 -0-
Michael E. Wiley 92,716,872 584,183 -0-

(b) Approval of Appointment of PricewaterhouseCoopers LLP as independent
accountants of the Company:

For: 93,261,934
Against: 34,007
Abstaining: 5,114
Broker Non-Vote: -0-

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

(a) Exhibits.

4.1 $200,000,000 6.50% Notes Due April 1, 2009

4.2 $100,000,000 6.50% Notes Due April 1, 2009

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 June 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: August 4, 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 $200,000,000 6.50% Notes Due April 1, 2009
4.2 $100,000,000 6.50% Notes Due April 1, 2009
12 Computation of Ratio of Earnings to Fixed Charges
27 Financial Data Schedule