<PAGE>
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
------------------------------------------------
Washington, D.C. 20549
----------------------
FORM 10-Q
(Mark One)
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[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000 OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _________________ TO
_________________
Commission file number 1-10389
------------------------------
WESTERN GAS RESOURCES, INC.
---------------------------
(Exact name of registrant as specified in its charter)
Delaware 84-1127613
------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
12200 N. Pecos Street, Denver, Colorado 80234-3439
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(Address of principal executive offices) (Zip Code)
(303) 452-5603
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Registrant's telephone number, including area code
No changes
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(Former name, former address and former fiscal year, if changed since last
report).
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
--- ---
On November 1, 2000, there were 32,332,190 shares of the registrant's Common
Stock outstanding.
1
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<PAGE>
Western Gas Resources, Inc.
Form 10-Q
Table of Contents
PART I - Financial Information Page
------------------------------ ----
Item 1. Financial Statements
Consolidated Balance Sheet - September 30, 2000 and
December 31, 1999................................................ 3
Consolidated Statement of Cash Flows - Three and nine Months
Ended September 30, 2000 and 1999................................ 4
Consolidated Statement of Operations - Three and nine
Months Ended September 30, 2000 and 1999......................... 5
Consolidated Statement of Changes in Stockholders' Equity -
Nine Months Ended September 30, 2000............................. 6
Notes to Consolidated Financial Statements....................... 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................ 12
Item 3. Quantatative and Qualitative Disclosures about Market Risk....... 20
PART II - Other Information
---------------------------
Item 1. Legal Proceedings................................................ 24
Item 4. Submission of matters to a vote of security holders.............. 25
Item 6. Exhibits and Reports on Form 8-K................................. 25
Signatures.................................................................. 26
2
<PAGE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
--------------------
WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(Dollars in thousands, except share data)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
---------- ----------
<S> <C> <C>
ASSETS (unaudited)
------
Current assets:
Cash and cash equivalents..................................................... $ 13,842 $ 14,062
Trade accounts receivable, net................................................ 391,875 196,739
Product inventory............................................................. 49,996 35,228
Parts inventory............................................................... 8,869 10,318
Assets held for sale.......................................................... - 7,237
Other......................................................................... 5,384 9,571
---------- ----------
Total current assets........................................................ 469,966 273,155
---------- ----------
Property and equipment:
Gas gathering, processing and transmission.................................... 862,677 808,274
Oil and gas properties and equipment.......................................... 134,281 104,137
Construction in progress...................................................... 45,485 39,987
---------- ----------
1,042,443 952,398
Accumulated depreciation, depletion and amortization........................... (296,366) (260,081)
---------- ----------
Total property and equipment, net........................................... 746,077 692,317
Other assets:
Gas purchase contracts (net of accumulated amortization of $32,836 and
$31,273, respectively)...................................................... 35,319 36,883
Other......................................................................... 13,511 47,131
---------- ----------
Total other assets.......................................................... 48,830 84,014
---------- ----------
Total Assets................................................................... $1,264,873 $1,049,486
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable.............................................................. $ 413,877 $ 240,235
Accrued expenses.............................................................. 33,992 41,075
Dividends payable............................................................. 4,221 4,218
---------- ----------
Total current liabilities................................................... 452,090 285,528
Long-term debt................................................................. 378,800 378,250
Deferred income taxes payable.................................................. 57,288 35,965
---------- ----------
Total liabilities............................................................. 888,178 699,743
---------- ----------
Stockholders' equity:
Preferred stock, par value $.10; 10,000,000 shares authorized:
$2.28 cumulative preferred stock; 1,400,000 shares issued and outstanding
($35,000,000 aggregate liquidation preference)............................. 140 140
$2.625 cumulative convertible preferred stock; 2,760,000 shares issued and
outstanding ($138,000,000 aggregate liquidation preference)................ 276 276
Common stock, par value $.10; 100,000,000 shares authorized; 32,323,974 and
32,186,747 shares issued, respectively...................................... 3,258 3,220
Treasury stock, at cost, 25,016 shares in treasury............................ (788) (788)
Additional paid-in capital.................................................... 399,523 397,522
Accumulated deficit........................................................... (25,681) (51,064)
Accumulated other comprehensive income........................................ 851 1,321
Notes receivable from key employees secured by common stock................... (884) (884)
---------- ----------
Total stockholders' equity.................................................. 376,695 349,743
---------- ----------
Total liabilities and stockholders' equity..................................... $1,264,873 $1,049,486
========== ==========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
3
<PAGE>
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
(Dollars in thousands)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-----------------------
2000 1999
--------- -----------
<S> <C> <C>
Reconciliation of net income (loss) to net cash provided by (used in) operating activities:
Net income (loss)............................................................................ $ 38,043 $ (15,882)
Add income items that do not affect cash:
Depreciation, depletion and amortization.................................................... 41,733 37,850
(Gain) loss on the sale of property and equipment........................................... (9,436) 21,406
Distributions (less than) in excess of equity income, net................................... (858) (354)
Foreign currency translation adjustments.................................................... (470) (1,864)
Deferred income taxes....................................................................... 22,320 (9,204)
Other non-cash items, net................................................................... 2,611 493
--------- -----------
93,943 32,445
Adjustments to working capital to arrive at net cash provided by (used in)
operating activities:
(Increase) decrease in trade accounts receivable............................................ (192,511) 4,910
(Increase) decrease in product inventory.................................................... (14,768) 16,176
Decrease in parts inventory................................................................. 1,449 201
Decrease in other current assets............................................................ 7,005 11,546
Decrease in other assets and liabilities, net............................................... - 444
Increase (decrease) in accounts payable..................................................... 169,955 (1,062)
Decrease in accrued expenses................................................................ (8,720) (5,085)
--------- -----------
Net cash provided by (used in) operating activities.......................................... 56,353 59,575
--------- -----------
Cash flows from investing activities:
Purchases of property and equipment......................................................... (72,970) (49,043)
Proceeds from the dispositions of property and equipment.................................... 26,462 148,100
Contributions to equity investees........................................................... 13 (100)
--------- -----------
Net cash used in investing activities........................................................ (46,495) 98,957
--------- -----------
Cash flows from financing activities:
Net proceeds from exercise of common stock options.......................................... 2,039 54
Proceeds from issuance of long-term debt.................................................... - 155,000
Debt issue costs paid....................................................................... (7) (9,319)
Payments on revolving credit facility....................................................... (922,286) (2,022,000)
Borrowings under revolving credit facility.................................................. 949,836 1,815,500
Prepayment of 1995 Senior Notes............................................................. (27,000) -
Payments on notes........................................................................... - (84,047)
Dividends paid.............................................................................. (12,660) (12,648)
--------- -----------
Net cash provided by financing activities.................................................... (10,078) (157,460)
--------- -----------
Net increase (decrease) in cash and cash equivalents......................................... (220) 1,072
Cash and cash equivalents at beginning of period............................................. 14,062 4,400
--------- -----------
Cash and cash equivalents at end of period................................................... $ 13,842 $ 5,472
========= ===========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
4
<PAGE>
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
(Dollars in thousands, except share and per share amounts)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2000 1999 2000 1999
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Revenues:
Sale of residue gas....................................... $ 739,431 $ 392,679 $ 1,659,104 $ 1,107,734
Sale of natural gas liquids............................... 155,136 97,660 412,743 237,514
Processing, transportation and storage revenue............ 12,956 11,799 36,251 36,118
Other, net................................................ 2,313 3,412 8,706 9,846
----------- ----------- ----------- -----------
Total revenues.......................................... 909,836 505,550 2,116,804 1,391,212
----------- ----------- ----------- -----------
Costs and expenses:
Product purchases......................................... 833,266 456,246 1,911,136 1,251,424
Plant operating expense................................... 18,515 17,096 50,877 50,615
Oil and gas exploration and production expense............ 5,038 2,346 10,975 6,029
Depreciation, depletion and amortization.................. 14,201 13,095 41,733 37,850
(Gain)/loss on fixed assets............................... (3,802) (27) (9,436) 21,690
Selling and administrative expense........................ 8,500 5,759 23,989 21,711
Interest expense.......................................... 8,889 9,365 24,916 25,118
----------- ----------- ----------- -----------
Total costs and expenses................................ 884,607 503,880 2,054,190 1,414,437
----------- ----------- ----------- -----------
Income (loss) before income taxes.......................... 25,229 1,670 62,614 (23,225)
Provision (benefit) for income taxes:
Current................................................... - (528) 537 754
Deferred.................................................. 9,058 1,140 22,320 (9,204)
----------- ----------- ----------- -----------
Total provision (benefit) for income taxes.............. 9,058 612 22,857 (8,450)
----------- ----------- ----------- -----------
Income (loss) before extraordinary items................... 16,171 1,058 39,757 (14,775)
Extraordinary charge for early extinguishment of debt,
net of tax benefit of $997,000 and $700,000, respectively.. (1,714) - (1,714) (1,107)
----------- ----------- ----------- -----------
Net income (loss).......................................... 14,457 1,058 38,043 (15,882)
Preferred stock requirements............................... (2,610) (2,610) (7,829) (7,829)
----------- ----------- ----------- -----------
Income (loss) attributable to common stock................. $ 11,847 $ (1,552) $ 30,214 $ (23,711)
=========== =========== =========== ===========
Income (loss) per share of common stock.................... $ .37 $ (.05) $ .94 $ (.74)
=========== =========== =========== ===========
Weighted average shares of common stock outstanding........ 32,263,430 32,150,111 32,208,697 32,148,699
=========== =========== =========== ===========
Income (loss) per share of common stock -
assuming dilution......................................... $ .36 $ (.05) $ .92 $ (.74)
=========== =========== =========== ===========
Weighted average shares of common stock outstanding -
assuming dilution......................................... 32,945,023 32,150,111 32,745,413 32,148,699
=========== =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
5
<PAGE>
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(Unaudited)
(Dollars in thousands, except share amounts)
<TABLE>
<CAPTION>
Shares of
Shares of $2.625 $2.625
$2.28 Cumulative Shares $2.28 Cumulative
Cumulative Convertible Shares Of Common Cumulative Convertible
Preferred Preferred of Common Stock Preferred Preferred
Stock Stock Stock in Treasury Stock Stock
------------ ------------- ------------ ------------- ------------ -------------
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1999............................. 1,400,000 2,760,000 32,161,731 25,016 $ 140 $ 276
Comprehensive Income:
Net income ....................... - - - - - -
Foreign Currency
Translation...................... - - - - - -
Comprehensive Income
Dividends:
Dividends declared on common
stock............................ - - - - - -
Dividends declared on $2.28
cumulative preferred stock....... - - - - - -
Dividends declared on $2.625
cumulative convertible preferred
stock............................ - - - - - -
Stock options exercised........... - - 162,243 - - -
------------ ------------- ------------ ------------- ------------ -------------
Balance at September 30, 2000..... 1,400,000 2,760,000 32,323,974 25,016 $ 140 $ 276
============ ============= ============ ============= ============ =============
</TABLE>
<TABLE>
<CAPTION>
Accumulated
Other Notes Total
Additional Compre- Receivable Stock-
Common Treasury Paid-in Accumulated hensive from Key holders'
Stock Stock Capital Deficit Income Employees Equity
---------- ---------- ------------- ------------- -------------- ------------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1999............................. $3,220 $(788) $397,522 $(51,064) $1,321 $(884) $349,743
Comprehensive Income:
Net income ....................... - - - 38,043 - - 38,043
Foreign Currency
Translation...................... - - - - (470) - (470)
------------
Comprehensive Income 37,573
------------
Dividends:
Dividends declared on common
stock............................ - - - (4,830) - - (4,830)
Dividends declared on $2.28
cumulative preferred stock....... - - - (2,397) - - (2,397)
Dividends declared on $2.625
cumulative convertible preferred
stock............................ - - - (5,433) - - (5,433)
Stock options exercised........... 38 - 2,001 - - - 2,039
---------- ---------- ------------- ------------- -------------- ------------- ------------
Balance at September 30, 2000.....$ 3,258 $ (788) $ 399,523 $ (25,681) $ 851 $ (884) $ 376,695
========== ========== ============= ============= ============== ============= ============
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
6
<PAGE>
WESTERN GAS RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
GENERAL
The interim consolidated financial statements presented herein should be
read in conjunction with the Consolidated Financial Statements and Notes thereto
included in our Annual Report on Form 10-K for the year ended December 31, 1999.
The interim consolidated financial statements as of September 30, 2000 and for
the three and nine month periods ended September 30, 2000 and 1999 included
herein are unaudited but reflect, in the opinion of management, all adjustments
(which include only normal recurring adjustments) necessary to fairly present
the results for such periods. The results of operations for the three and nine
months ended September 30, 2000 are not necessarily indicative of the results of
operations expected for the year ended December 31, 2000.
Prior year's amounts in the interim consolidated financial statements and
notes have been reclassified as appropriate to conform to the presentation used
in 2000.
STOCK BASED COMPENSATION
In March 2000, the FASB issued Interpretation No. 144, an interpretation of
APB Opinion No. 25, "Accounting for Certain Transactions Involving Stock
Compensation," regarding the accounting treatment of repriced stock options.
This interpretation became effective July 1, 2000. Under this interpretation, we
will be required to record compensation expense (if not previously accrued)
equal to the number of unexercised repriced options multiplied by the amount by
which our stock price at the end of any quarter exceeds $21 per share. We have
options covering 148,133 common shares outstanding at September 30, 2000 which
were treated as repriced options. Based on our stock price at September 30,
2000 of $25.06 per share, we have recorded additional compensation expense of
$600,000 in the third quarter of 2000.
Extraordinary Item - Early Extinguishment of Debt
In September 2000, we prepaid $27.0 million of outstanding indebtedness to
insurance companies, originally due to be paid in November 2005, with funds
available under our Revolving Credit Facility. In connection with this
prepayment, we made a pre-tax make-whole payment of approximately $2.0 million
and expensed capitalized fees of approximately $752,000. The combined costs of
approximately $2.7 million, net of a tax benefit of $997,000, are reflected as
an extraordinary loss on early extinguishment of debt in the third quarter of
2000. The net extraordinary loss of $1.7 million decreased earnings per share
of common stock - assuming dilution by $.05.
EARNINGS PER SHARE OF COMMON STOCK
Earnings per share of common stock is computed by dividing income
attributable to common stock by the weighted average number of shares of common
stock outstanding. In addition, earnings per share of common stock - assuming
dilution is computed by dividing income attributable to common stock by the
weighted average number of shares of common stock outstanding as adjusted for
potential common shares. Income attributable to common stock is income less
preferred stock dividends. We declared preferred stock dividends of $2.6
million and $7.8 million, respectively, for each of the three and nine month
periods ended September 30, 2000 and 1999. Common stock options, which are
potential common shares, had a dilutive effect on earnings and increased the
weighted average number of shares of common stock outstanding by 681,593 and
536,716 for the three and nine month periods ended September 30, 2000. Common
stock options, which are potential common shares, were anti-dilutive for the
period ended September 30, 1999 and were not included in the calculation of
earnings per share for that period. The numerators and the denominators for the
three month periods ended September 30, 2000 and 1999 are not adjusted to
reflect our $2.625 Cumulative Convertible Preferred Stock outstanding. These
shares are antidilutive as the incremental shares result in an increase in
earnings per share after giving effect to the dividend requirements.
OTHER INFORMATION
Black Lake. In December 1999, we signed an agreement for the sale of our
Black Lake facility and related reserves for gross proceeds of $7.8 million,
subject to final accounting adjustment. This sale closed in January 2000. This
transaction resulted in an approximate pre-tax loss of $7.3 million, which was
accrued in the fourth quarter of 1999.
7
<PAGE>
Western Gas Resources-California, Inc. In January 2000, we sold all the
outstanding stock of our wholly-owned subsidiary, Western Gas Resources-
California, Inc. ("WGR-California") for $14.9 million. The only asset of this
subsidiary was a 162 mile pipeline in the Sacramento basin of California. The
pipeline was acquired through the exercise of an option by us in a transaction
which closed simultaneously with the sale of WGR-California. We recognized a
pre-tax gain on the sale of approximately $5.4 million in the first quarter of
2000.
Arkoma. In August 2000, we sold our Arkoma gathering system for gross
proceeds of $10.5 million. This sale resulted in an approximate pre-tax gain of
$3.9 million, subject to final accounting adjustment.
The proceeds from these sales were used to reduce borrowings outstanding
under the Revolving Credit Facility.
Westana. In February 2000, we acquired the remaining 50% interest in the
Westana Gathering Company for a net purchase price of $9.8 million. The results
from our ownership through February 2000 of a 50% equity interest in the Westana
Gathering Company are reflected in revenues in Other, net on the Consolidated
Statement of Operations. Beginning in March 2000, the results of these
operations are fully consolidated and are included in Revenues and Costs and
expenses. Additionally, in March 2000, our investment in the Westana Gathering
Company has been reclassified from Other assets to Property and equipment.
SUPPLEMENTARY CASH FLOW INFORMATION
Interest paid was $23.3 million and $21.6 million for the nine months ended
September 30, 2000 and 1999, respectively.
No income taxes were paid during the nine months ended September 30, 2000 or
1999.
SUBSEQUENT EVENTS
In November 2000, we purchased in open market transactions a total of 33,690
shares of our $2.28 cumulative preferred stock for total cost, including broker
commissions, of approximately $851,000, or an average of $25.25 per share of
preferred stock. These shares will be retired. Our Board of Directors has
authorized the repurchase from time to time of up to an additional $1.2 million
of preferred stock in open market transactions.
SEGMENT REPORTING
We operate in four principal business segments as follows: Gas Gathering and
Processing, Production, Marketing and Transmission. These segments are
separately monitored by management for performance against our internal forecast
and are consistent with our internal financial reporting package. These
segments have been identified based upon the differing products and services,
regulatory environment and the expertise required for these operations.
In our Gas Gathering and Processing segment we connect producers' wells to
our gathering systems for delivery to our processing or treating plants, process
the natural gas to extract NGLs and treat the natural gas in order to meet
pipeline specifications. The results of our Black Lake facility and related
reserves, which were sold in December 1999, are included in this segment for the
1999 periods. The residue gas and NGLs extracted at our processing facilities
are sold by our Marketing segment.
The activities of our Production segment include the exploration and
development of gas properties primarily in basins where our gathering and
processing facilities are located. The majority of the production from these
properties is sold by our Marketing segment.
Our Marketing segment buys and sells gas and NGLs nationwide and in Canada
from or to a variety of customers. In addition, this segment also markets gas
and NGLs produced by our gathering, processing and production assets. The
operations associated with the Katy Facility, which was sold in April 1999, are
included in the Marketing segment for the three and nine months ended September
30, 1999. Also included in this segment are our Canadian marketing operations
(which are immaterial for separate presentation). The Marketing segment also
includes losses associated with our equity gas and NGL hedging program of $10.6
million and $4.4 million for the quarters ended September 30, 2000 and September
30, 1999, respectively and of $20.2 million and $6.7 million for the nine months
ended September 30, 2000 and September 30, 1999, respectively.
8
<PAGE>
The Transmission segment reflects the operations of the MIGC and MGTC
pipelines. The majority of the revenue presented in this segment is derived
from the transportation of residue gas for our Gas Gathering and Processing,
Production and Marketing segments.
The following table sets forth our segment information as of and for the
three and nine month periods ended September 30, 2000 and 1999 (dollars in
thousands). Due to our integrated operations, the use of allocations in the
determination of business segment information is necessary. Intersegment
revenues are valued at prices comparable to those of unaffiliated customers.
<TABLE>
<CAPTION>
Gas
Gathering Elim-
and Trans- inating
Processing Production Marketing mission Corporate Entries Total
---------- ----------- ----------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Quarter ended September 30, 2000
Revenues from unaffiliated customers...... $ 26,338 $ 783 $ 903,127 $ 1,844 $ 28 $ - $ 932,120
Interest income........................... 34 - - - 7,340 (7,158) 216
Other, net................................ 3 (38) (23,845) - 1,341 39 (22,500)
Intersegment sales........................ 200,016 21,440 43,823 3,775 14 (269,068) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues............................ 226,391 22,185 923,105 5,619 8,723 (276,187) 909,836
-------- -------- ---------- ------- ------- --------- ----------
Product purchases......................... 174,832 1,217 922,802 (236) 25 (265,374) 833,266
Plant operating expense................... 16,145 104 28 2,356 278 (396) 18,515
Oil and gas exploration
and production expense................... - 7,466 - - - (2,428) 5,038
-------- -------- ---------- ------- ------- --------- ----------
Operating profit.......................... $ 35,414 $ 13,398 $ 275 $ 3,499 $ 8,420 $ (7,989) $ 53,017
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and amortization.. 9,682 2,709 41 397 1,372 - 14,201
Interest expense.......................... 8,889
Gain on sale of assets.................... (3,802)
Selling and administrative expense........ 8,500
----------
Income (loss) before income taxes......... $ 25,229
==========
Identifiable assets....................... $542,703 $116,432 $ 62 $46,909 $39,971 $ - $ 746,077
======== ======== ========== ======= ======= ========= ==========
</TABLE>
<TABLE>
<CAPTION>
Gas
Gathering Elim-
and Trans- inating
Processing Production Marketing mission Corporate Entries Total
---------- ----------- ----------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Quarter ended September 30, 1999
Revenues from unaffiliated customers...... $ 9,990 $ 744 $ 496,311 $ 1,706 $ 216 $ - $ 508,967
Interest income........................... - 105 23 - 6,095 (5,975) 248
Other, net................................ 44 - (4,702) 46 947 - (3,665)
Intersegment sales........................ 109,340 7,093 24,783 4,012 14 (145,242) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues............................ 119,374 7,942 516,415 5,764 7,272 (151,217) 505,550
-------- -------- ---------- ------- ------- --------- ----------
Product purchases......................... 81,253 551 520,594 - (722) (145,430) 456,246
Plant operating expense................... 15,590 25 (1,659) 2,988 373 (221) 17,096
Oil and gas exploration
and production expense................... 147 2,199 - - - - 2,346
-------- -------- ---------- ------- ------- --------- ----------
Operating profit.......................... $ 22,384 $ 5,167 $ (2,520) $ 2,776 $ 7,621 $ (5,566) $ 29,862
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and amortization.. 9,271 2,280 40 324 1,180 - 13,095
Interest expense.......................... 9,365
Loss on sale of assets.................... (27)
Selling and administrative expense........ 5,759
----------
Income (loss) before income taxes......... $ 1,670
==========
Identifiable assets....................... $523,168 $ 83,834 $ 88 $47,984 $37,243 $ - $ 692,317
======== ======== ========== ======= ======= ========= ==========
</TABLE>
9
<PAGE>
<TABLE>
<CAPTION>
Gas
Gathering Elim-
and Trans- inating
Processing Production Marketing mission Corporate Entries Total
---------- ----------- ----------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Nine months ended September 30, 2000
Revenues from unaffiliated customers...... $ 44,512 $ 2,913 $2,091,842 $ 6,099 $ 89 $ - $2,145,455
Interest income........................... 68 2 27 - 19,597 (19,179) 515
Other, net................................ 1,675 3 (32,756) - 1,873 39 (29,166)
Intersegment sales........................ 520,359 49,347 83,104 12,494 31 (665,335) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues............................ 566,614 52,265 2,124,217 18,593 21,590 (684,475) 2,116,804
-------- -------- ---------- ------- ------- --------- ----------
Product purchases......................... 421,085 2,749 2,142,760 (236) (65) (655,157) 1,911,136
Plant operating expense................... 44,623 412 28 6,620 206 (1,012) 50,877
Oil and gas exploration
and production expense................... 31 20,068 - - - (9,124) 10,975
-------- -------- ---------- ------- ------- --------- ----------
Operating profit.......................... $100,875 $ 29,036 $ (571) $12,209 $21,449 $ (19,182) $ 143,816
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and amortization.. 27,244 9,091 121 1,230 4,047 - 41,733
Interest expense.......................... 24,916
Gain on sale of assets.................... (9,436)
Selling and administrative expense........ 23,989
----------
Income (loss) before income taxes......... $ 62,614
==========
Identifiable assets....................... $542,703 $116,432 $ 62 $46,909 $39,971 $ - $ 746,077
======== ======== ========== ======= ======= ========= ==========
</TABLE>
<TABLE>
<CAPTION>
Gas
Gathering Elim-
and Trans- inating
Processing Production Marketing mission Corporate Entries Total
---------- ----------- ----------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Nine months ended September 30, 1999
Revenues from unaffiliated customers...... $ 33,204 $ 1,688 $1,349,574 $ 5,402 $ 754 $ - $1,390,622
Interest income........................... 1 256 84 - 19,366 (19,165) 542
Other, net................................ 158 - (3,439) 487 2,842 - 48
Intersegment sales........................ 274,835 17,823 63,723 12,194 42 (368,617) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues............................ 308,198 19,767 1,409,942 18,083 23,004 (387,782) 1,391,212
-------- -------- ---------- ------- ------- --------- ----------
Product purchases......................... 209,072 1,456 1,409,452 - (722) (367,834) 1,251,424
Plant operating expense................... 41,693 132 13 8,817 856 (896) 50,615
Oil and gas exploration
and production expense................... 354 5,719 (44) - - - 6,029
-------- -------- ---------- ------- ------- --------- ----------
Operating profit.......................... $ 57,079 $ 12,460 $ 521 $ 9,266 $22,870 $ (19,052) $ 83,144
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and amortization.. 26,868 5,516 1,186 844 3,436 - 37,850
Interest expense.......................... 25,118
Loss on sale of assets.................... 21,690
Selling and administrative expense........ 21,711
----------
Income (loss) before income taxes......... $ (23,225)
==========
Identifiable assets....................... $523,168 $ 83,834 $ 88 $47,984 $37,243 $ - $ 692,317
======== ======== ========== ======= ======= ========= ==========
</TABLE>
10
<PAGE>
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In June 1998, the Financial Accounting Standards Board, the FASB, issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
("SFAS No. 133"), effective for fiscal years beginning after June 15, 2000.
Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we will be
required to recognize the change in the market value of all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. Changes in the fair value of derivatives are
recorded each period in current earnings or other comprehensive income depending
upon the nature of the underlying transaction. We do not believe the adoption
of SFAS No. 133 will have a material impact on our earnings or financial
position as it relates to our equity hedging program. We currently anticipate
adopting mark to market accounting in the first quarter of 2001 for the
remainder of our marketing activities. We cannot at this time determine the
impact of adopting mark-to-market on our earnings or financial position.
LEGAL PROCEEDINGS
Reference is made to "Part II - Other Information - Item 1. Legal
Proceedings," of this Form 10-Q.
11
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
-----------------------------------------------------------------------
OF OPERATIONS
-------------
The following discussion and analysis relates to factors which have affected
our consolidated financial condition and results of operations for the three and
nine months ended September 30, 2000 and 1999. Prior year amounts have been
reclassified as appropriate to conform to the presentation used in 2000. You
should also refer to our interim consolidated financial statements and notes
thereto included elsewhere in this document. This section, as well as other
sections in this Form 10-Q, contain "forward-looking statements" within the
meaning of the Private Securities Litigation Reform Act of 1995, which can be
identified by the use of forward-looking terminology, such as "may," "intend,"
"will," "expect," "anticipate," "estimate," or "continue" or the negative
thereof or other variations thereon or comparable terminology. In addition to
the important factors referred to herein, numerous factors affecting the gas
processing industry generally and in the specific markets for gas and NGLs in
which we operate could cause actual results to differ materially from those in
such forward-looking statements.
Results of Operations
Three and nine months ended September 30, 2000 compared to the three and nine
months ended September 30, 1999
(Dollars in thousands, except per share amounts and operating data).
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ Percent ---------------------- Percent
2000 1999 Change 2000 1999 Change
-------- -------- ------- ---------- ---------- -------
<S> <C> <C> <C> <C> <C> <C>
Financial results:
Revenues................................... $909,836 $505,550 80 $2,116,804 $1,391,212 52
Gross profit............................... 42,618 16,794 154 111,519 23,604 372
Net income (loss).......................... 14,457 1,058 1,266 38,043 (15,882) --
Income (loss) per share of common stock.... .37 (.05) -- .94 (.74) --
Income (loss) per share of common stock -
assuming dilution........................ .36 (.05) -- .92 (.73) --
Net cash provided by
operating activities...................... $ 34,317 $ 15,827 117 $ 56,353 $ 59,575 (5)
Operating data:
Average gas sales (MMcf/D)................. 1,970 1,775 11 1,810 1,960 (8)
Average NGL sales (MGal/D)................. 3,170 2,815 13 3,040 2,875 6
Average gas prices ($/Mcf)................. $ 4.08 $ 2.41 70 $ 3.34 $ 2.07 61
Average NGL prices ($/Gal)................. $ .53 $ .38 40 $ .50 $ .30 66
</TABLE>
Net income increased $13.4 million for the three months ended September 30,
2000 compared to 1999. The increase in net income was primarily attributable to
significantly higher gas and NGL prices in 2000 compared to the prior year,
increased production from the Powder River coal bed methane development,
improved marketing margins and an after-tax gain of $2.4 million on the sale of
our Arkoma gathering system in August 2000 which was partially offset by a $1.7
million after-tax extraordinary loss on the early extinguishment of long-term
debt.
Net income increased $53.9 million for the nine months ended September 30,
2000 compared to 1999. The increase in net income was primarily attributable to
significantly higher gas and NGL prices in 2000 compared to the prior year,
increased production from the Powder River coal bed methane development,
improved marketing margins and an after-tax gain of $3.1 million recognized on
the sale of the stock of our wholly-owned subsidiary, Western Gas Resources-
California, in the first quarter of 2000 and an after-tax gain of $2.4 million
recognized on the sale of the Arkoma gathering system in the third quarter of
2000 which was partially offset by a $1.7 million after-tax extraordinary loss
on the early extinguishment of long-term debt. The results for the nine months
ended September 30, 1999 include a combined after-tax loss of $14.8 million from
the sale of the Giddings, Katy storage and MiVida facilities and related
severance charges and an after-tax extraordinary loss of $1.1 million for the
early extinguishment of long-term debt.
Revenues from the sale of gas increased $346.8 million to $739.4 million in
the third quarter of 2000 compared to the same period in 1999. This increase
was primarily due to an improvement in product prices and an increase in the
sale of product
12
<PAGE>
purchased from third parties. Average gas prices realized by us increased $1.68
per Mcf to $4.08 per Mcf in the third quarter of 2000 compared to the same
period in 1999. Included in the realized gas price were approximately $9.2
million of losses recognized in the third quarter of 2000 related to futures
positions on equity gas volumes. We have entered into additional futures
positions for the majority of our equity gas for the remainder of 2000 and to a
lesser extent in 2001. See further discussion in " -Liquidity and Capital
Resources - Risk Management Activities." Average gas sales volumes increased 196
MMcf per day to 1,969 MMcf per day for the three months ended September 30, 2000
compared to the same period in 1999. This increase is due to an increase in both
product purchased from third parties and in production from our facilities,
primarily our Powder River coal bed methane development.
Revenues from the sale of gas increased $551.4 million to $1,659.1 million
in the nine months ended September 30, 2000 compared to the same period in 1999.
This increase was due to an improvement in product prices in 2000 which more
than offset a reduction in sales volume. Average gas prices realized by us
increased $1.27 per Mcf to $3.34 per Mcf in the nine months ended September 30,
2000 compared to the same period in 1999. Included in the realized gas price
were approximately $15.8 million of losses recognized in the nine months ended
September 30, 2000 related to futures positions on equity gas volumes. We have
entered into additional futures positions for the majority of our equity gas for
the remainder of 2000 and to a lesser extent in 2001. See further discussion in
" - Liquidity and Capital Resources - Risk Management Activities." Average gas
sales volumes decreased 137 MMcf per day to 1,813 MMcf per day in the nine
months ended September 30, 2000 compared to the same period in 1999. This
decrease was due to a reduction in the sale of gas purchased from third parties
resulting from the sale in 1999 of our Katy gas storage facility.
Revenues from the sale of NGLs increased $57.5 million in the third quarter
of 2000 compared to the same period in 1999. This increase is due to an
improvement in product prices and an increase in sales volume. Average NGL
prices realized by us increased $.15 per gallon to $.53 per gallon in the third
quarter of 2000 compared to the same period in 1999. Included in the realized
NGL price were approximately $1.4 million of losses recognized in the third
quarter of 2000 related to futures positions on equity NGL volumes. We have
additional futures positions in place for a portion of our equity NGL production
for the remainder of 2000. See further discussion in " - Liquidity and Capital
Resources - Risk Management Activities." Average NGL sales volumes increased 357
MGal per day to 3,172 MGal per day in the third quarter of 2000 compared to the
same period in 1999. This increase in NGL volume is primarily due to an increase
in the sale of NGLs purchased from third parties.
Revenues from the sale of NGLs increased approximately $175.2 million in the
nine months ended September 30, 2000 compared to the same period in 1999. This
increase is due to an improvement in product prices and an increase in sales
volume. Average NGL prices realized by us increased $.20 per gallon to $.50 per
gallon in the nine months ended September 30, 2000 compared to the same period
in 1999. Included in the realized NGL price were approximately $4.5 million of
losses recognized in the nine months ended September 30, 2000 related to futures
positions on equity NGL volumes. We have additional futures positions in place
for a portion of our equity NGL production for the remainder of 2000. See
further discussion in " - Liquidity and Capital Resources - Risk Management
Activities." Average NGL sales volumes increased 173 MGal per day to 3,039 MGal
per day in the nine months ended September 30, 2000 compared to the same period
in 1999. This increase in NGL volume is due to an increase in the sale of NGLs
purchased from third parties.
Product purchases increased by $377.0 million and $659.7 million in the
third quarter and nine months ended September 30, 2000, respectively, compared
to the same period in 1999 primarily due to an increase in commodity prices in
both periods and an increase in residue gas and NGLs purchased from third
parties in the third quarter of 2000. Overall, combined product purchases as a
percentage of sales of all products remained constant at 93% for the quarters
ended September 30, 2000 and 1999, and decreased 1% to 92% for the nine months
ended September 30, 2000 compared to the same period in 1999. The reduction in
this percentage was primarily due to increased sales of gas produced from our
coal bed methane wells in the Powder River basin. These sales have no
corresponding product purchases. This percentage is also affected by the volume
of sales of third-party product and the margin earned on those sales.
Marketing margins on residue gas averaged $.024 per Mcf in the third quarter
of 2000 and $.019 per Mcf in the nine months ended September 30, 2000. These
represent significant increases from the margins realized during the comparable
periods in 1999 of $.001 per Mcf and $.011 per Mcf, respectively. The margins
realized in 2000 are reflective of the current volatile market conditions and
our ability to benefit from these conditions through our transportation
arrangements. Marketing margins on NGLs averaged $.008 per gallon in the
third quarter and nine months ended September 30, 2000 compared to approximately
$.006 per gallon and $.004 per gallon in the same periods in 1999, respectively.
There is no assurance, however, that these market conditions for our gas and NGL
products and related margins will continue in the future or that we will be in a
similar position to benefit from them.
13
<PAGE>
Oil and gas exploration and production expenses increased $2.7 million and
$4.9 million in the third quarter and nine months ended September 30, 2000
compared to the same periods in 1999, respectively. These increases are due to
increased production taxes and lease operating expense resulting from our
increased drilling and production activities in the Powder River coal bed
methane development.
Selling and administrative expenses increased $2.7 million and $2.3 million
in the third quarter and the nine months ended September 30, 2000 as compared to
the same periods in 1999, respectively. These increases are due to higher
insurance costs, increased compensation and severance costs, increased accruals
for doubtful accounts and compensation recorded for repriced stock options.
Depreciation, depletion and amortization increased by $1.1 million and $3.9
million in the third quarter and the nine months ended September 30, 2000 as
compared to the same periods in 1999 primarily as a result of our increasing
operations in the Powder River basin coal bed methane development.
Extraordinary charge for early extinguishment of debt increased by an after-
tax charge of $1.7 million in the third quarter of 2000 and by $600,000 in the
nine months ended September 30, 2000 as compared to the same periods in 1999. In
September 2000, we prepaid $27.0 million of outstanding indebtedness to
insurance companies, originally due to be paid in November 2005, with funds
available under our Revolving Credit Facility. In connection with this
prepayment, we paid a pre-tax make-whole payment of approximately $2.0 million
and expensed capitalized fees of approximately $752,000.
Other Information
Black Lake. In December 1999, we signed an agreement for the sale of our
Black Lake facility and related reserves for gross proceeds of $7.8 million,
subject to final accounting adjustment. This sale closed in January 2000. This
transaction resulted in an approximate pre-tax loss of $7.3 million which was
accrued in the fourth quarter of 1999.
Western Gas Resources-California, Inc. In January 2000, we sold all of the
outstanding stock of our wholly-owned subsidiary, Western Gas Resources-
California, Inc., ("WGR-California"), for $14.9 million. The only asset of this
subsidiary was a 162 mile pipeline in the Sacramento basin of California. The
pipeline was acquired through the exercise of an option by us in a transaction
which closed simultaneously with the sale of WGR-California. We recognized a
pre-tax gain on the sale of approximately $5.4 million in the first quarter of
2000.
Arkoma. In August 2000, we sold our Arkoma gathering system for gross
proceeds of $10.5 million. This sale resulted in an approximate pre-tax gain of
$3.9 million, subject to final accounting adjustment.
The proceeds from these sales were used to reduce borrowings outstanding
under the Revolving Credit Facility.
Westana. In February 2000, we acquired the remaining 50% interest in the
Westana Gathering Company for a net purchase price of $9.8 million. The results
from our ownership through February 2000 of a 50% equity interest in the Westana
Gathering Company are reflected in revenues in Other, net on the Consolidated
Statement of Operations. Beginning in March 2000, the results of these
operations are fully consolidated and are included in Revenues and Costs and
expenses. Additionally, in March 2000, our investment in the Westana Gathering
Company has been reclassified from Other assets to Property and equipment.
Business Strategy
Our long-term business plan is to increase our profitability by: (i)
optimizing the efficiency of existing operations; (ii) entering into additional
agreements with third-party producers who dedicate acreage to our gathering and
processing operations; and (iii) investing in projects or acquiring assets that
complement and extend our core natural gas gathering, processing, production and
marketing businesses.
We constantly seek to improve the profitability of our existing operations
by increasing natural gas throughput levels through new well connections and
expansion of gathering systems, increasing our efficiency through the
consolidation of existing gathering and processing facilities, evaluating the
economic performance of each of our operating facilities to ensure that a
targeted rate of return is achieved and controlling operating and overhead
expenses.
14
<PAGE>
We continually seek to increase reserves dedicated to our facilities. Our
operations are located in some of the most actively drilled oil and gas
producing basins in the United States. We enter into agreements under which we
gather and process natural gas produced on acreage dedicated to us by third
parties. We contract for production from new wells and newly dedicated acreage
in order to replace declines in existing reserves that are dedicated for
gathering and processing at our facilities. We also seek to increase reserves
supplying our facilities by developing our own production, such as in the Powder
River basin. We have increased our dedicated estimated reserves from 2.3 Tcf at
December 31, 1994 to 2.8 Tcf at December 31, 1999. In 1999, including the
reserves developed by us and associated with our joint ventures and partnerships
and excluding the reserves associated with the facilities sold during this
period, we connected new reserves to our facilities to replace approximately
142% of throughput. In order to obtain additional dedicated acreage and to
secure contracts on favorable terms, we may participate to a limited extent with
third party producers in exploration and production activities that supply our
facilities. For the same reason, we may also offer to sell ownership interests
in our facilities to selected producers.
We will continue to invest in projects that complement and extend our core
natural gas gathering, processing, production and marketing businesses including
the consideration of expansion into additional geographic areas in the
continental United States and Canada.
In the third quarter of 2000, our Board of Directors retained an executive
search firm to identify and evaluate both internal and external candidates to
replace our current Chief Executive Officer and President, Lanny Outlaw who has
informed the Board of his intention to retire May 31, 2001.
Liquidity and Capital Resources
Our sources of liquidity and capital resources historically have been net
cash provided by operating activities, funds available under our financing
facilities and proceeds from offerings of debt and equity securities. In the
past, these sources have been sufficient to meet our needs and finance the
growth of our business. We can give no assurance that the historical sources of
liquidity and capital resources will be available for future development and
acquisition projects, and we may be required to seek alternative financing
sources. In 1999, we completed the sales of our Giddings, Katy and MiVida
facilities. In connection with the sale of Katy, we sold gas held in storage at
this facility. In December 1999, we contracted for the sale of the Black Lake
facility and related reserves. This sale closed in January 2000. In 2000, we
sold the stock of our subsidiary, Western Gas Resources-California, Inc. and our
Arkoma gathering system for a combined pre-tax gain of approximately $9.3
million. We used the proceeds from these sales of approximately $183 million to
reduce debt. Product prices, sales of inventory, the volumes of natural gas
processed by our facilities, the margin on third-party product purchased for
resale, as well as the timely collection of our receivables will affect all
future net cash provided by operating activities. Additionally, our future
growth will be dependent upon obtaining additions to dedicated plant reserves,
acquisitions, new project development, marketing, efficient operation of our
facilities and our ability to obtain financing at favorable terms.
We believe that the amounts available to be borrowed under the Revolving
Credit Facility, together with net cash provided by operating activities and the
sale of non-strategic assets, will provide us with sufficient funds to connect
new reserves, maintain our existing facilities, complete our current capital
expenditure program and make any scheduled debt principal payments. Depending
on the timing and the amount of our future projects, we may be required to seek
additional sources of capital. Our ability to secure additional capital is in
some cases restricted by our financing facilities, although we may request
additional borrowing capacity from our lenders, seek waivers from our lenders to
permit us to borrow funds from third parties, seek replacement financing
facilities from other lenders, use stock as a currency for acquisitions, sell
existing assets or a combination of alternatives. While we believe that we
would be able to secure additional financing, if required, we can provide no
assurance that we will be able to do so or as to the terms of any additional
financing. We also believe that cash provided by operating activities and
amounts available under our Revolving Credit Facility will be sufficient to meet
our debt service and preferred stock dividend requirements for 2000 and 2001.
While several of our plants have experienced declines in dedicated reserves,
overall we have been successful in connecting additional reserves to more than
offset the natural declines. Higher gas prices, improved technology, e.g., 3-D
seismic and horizontal drilling, and increased pipeline capacity from the Rocky
Mountain region have stimulated drilling in many of our operating areas. The
overall level of drilling will depend upon, among other factors, the prices for
oil and gas, the drilling budgets of third-party producers, the energy policy
and regulation by governmental agencies and the availability of foreign oil and
gas, none of which is within our control. There is no assurance that we will
continue to be successful in replacing the dedicated reserves processed at our
facilities.
15
<PAGE>
We have effective shelf registration statements filed with the Securities
and Exchange Commission for an aggregate of $200 million of debt securities and
preferred stock, along with the shares of common stock, if any, into which those
securities are convertible, and $62 million of debt securities, preferred stock
or common stock.
Our sources and uses of funds for the nine months ended September 30, 2000
are summarized as follows (dollars in thousands):
<TABLE>
<CAPTION>
Sources of funds:
<S> <C>
Borrowings under revolving credit facility....................... $ 949,836
Proceeds from the dispositions of property and equipment......... 26,462
Net cash provided by operating activities........................ 56,353
Proceeds from exercise of common stock options................... 2,039
Other............................................................ 13
----------
Total sources of funds......................................... $1,034,703
==========
Uses of funds:
Payments related to long-term debt (including debt issue costs).. $ 922,293
Capital expenditures............................................. 72,970
Dividends paid................................................... 12,660
Early extinguishment of 1995 Senior debt......................... 27,000
----------
Total uses of funds............................................ $1,034,923
==========
</TABLE>
Additional sources of liquidity available to us are our inventories of gas
and NGLs in storage facilities. We store gas and NGLs primarily to ensure an
adequate supply for long-term sales contracts and for resale during periods when
prices are favorable. We held gas in storage and in imbalances of approximately
13.9 Bcf at an average cost of $3.31 per Mcf at September 30, 2000 compared to
10.9 Bcf at an average cost of $2.18 per Mcf at September 30, 1999 under storage
contracts at various third-party facilities. At September 30, 2000, we had
hedging contracts in place for anticipated sales of approximately 13.8 Bcf of
stored gas at a weighted average price of $3.84 per Mcf for the stored
inventory.
We held NGLs in storage of 14,213 MGal, consisting primarily of propane and
normal butane, at an average cost of $.41 per gallon and 15,700 MGal at an
average cost of $.28 per gallon at September 30, 2000 and 1999, respectively, at
various third-party storage facilities. At September 30, 2000, we had no
significant hedging contracts in place for anticipated sales of stored NGLs.
Preferred Stock Repurchase Program
In November 2000, we purchased in open market transactions a total of 33,690
shares of our $2.28 cumulative preferred stock for total cost, including broker
commissions, of approximately $851,000, or an average of $25.25 per share of
preferred stock. These shares will be retired. Our Board of Directors has
authorized the repurchase from time to time of up to an additional $1.2 million
of preferred stock in open market transactions.
Capital Investment Program
Primarily as a result of additional drilling behind our systems and in the
Powder River basin, we have increased our capital budget for the year ending
December 31, 2000 by approximately $15.8 million. We now expect capital
expenditures related to existing operations to be approximately $105.5 million
during 2000, consisting of the following: (i) approximately $60.9 million
related to gathering, processing and pipeline assets, of which $7.8 million is
for maintaining existing facilities and $9.8 million for acquisition of the
remaining 50% interest in the Westana Gathering Company; (ii) approximately
$39.6 million related to exploration and production activities; and (iii)
approximately $5.0 million for miscellaneous items. Overall, capital
expenditures in the Powder River basin coal bed methane development and in
southwest Wyoming operations represent 47% and 12%, respectively, of the total
2000 budget.
As of September 30, 2000, we have expended $73.0 million, consisting of the
following: (i) $37.2 million related to gathering, processing and pipeline
assets, of which $4.6 million is for maintaining existing facilities and $9.8
million for acquisition of the remaining 50% interest in the Westana Gathering
Company; (ii) $30.0 million related to exploration and production activities;
and (iii) $5.8 million for miscellaneous items.
16
<PAGE>
Coal Bed Methane - We continue to develop our Powder River basin coal bed
methane gathering system and our coal seam gas reserves in Wyoming. We have
acquired drilling rights on approximately 1,075,000 gross acres, or 520,000 net
acres, in the basin. On approximately 18% of this acreage position, we have
established proven developed and undeveloped reserves. Production of coal bed
methane from the Powder River basin has been expanding, and approximately 225
MMcf/D of gas volumes in the month of September 2000 were being produced by
several operators in the area, including 174 MMcf/D gross production by our
partners and us, or 69 MMcf/D net to our interest. We transport most of the coal
bed methane gas under firm transportation or gathering agreements through our
MIGC interstate pipeline or the Fort Union gathering system. In addition we have
108 MMcf/D firm transportation capacity on other interstate pipelines with
access to gas markets in the Rocky Mountain and Midwest regions of the United
States. We currently project gross production rates of approximately 200 MMcf/D,
or 78 MMcf/D net, at December 31, 2000 and approximately 300 MMcf/D, or 117
MMcf/D net, at December 31, 2001. Given the uncertainties associated with
obtaining drilling and water discharge permits and of drilling in unproven
areas, there is no assurance, however, that we will reach these projected
volumes.
Our production is derived primarily from wells drilled to depths of 400 to
1,200 feet in the Wyodak coal formation. In 2000, we expect to drill
approximately 1070 gross wells, or 535 net wells, to the Wyodak coal, the
majority of which are on locations with proven, undeveloped reserves. During
the first nine months of 2000, we have drilled 777 gross wells, or 389 net
wells, to this formation. At October 31, 2000, a total of 713 gross wells are
awaiting connection, including 611 gross wells with pending water discharge
permits from the Wyoming Department of Environmental Quality, the DEQ, as
discussed below. As part of our drilling plans for 2000, we expect to drill
approximately 150 gross wells in pilot areas including the Big George coal. The
Big George formation is deeper and under higher pressure and if successful could
result in higher reserves per well than the Wyodak coal formation.
The average drilling, completion and gathering cost for our Wyodak coal bed
methane wells is approximately $80,000 with reserves per well of approximately
320 MMcf. As deeper wells are drilled and other coal formations are explored,
particularly the Big George formation, the average drilling cost is expected to
increase.
Future drilling on federal acreage will be delayed until the completion of
an Environmental Impact Statement for the majority of the Powder River basin.
This study is currently expected to be completed in the first quarter of 2002.
Our drilling plans for 2000 and 2001 are not expected to be substantially
affected by this study due to our large inventory of non-federal drilling
locations. In addition, the DEQ has approved changes in the standards for
surface water discharge on some components of the water being discharged from
coal bed wells and continues to evaluate changes in other standards and
policies, particularly its anti-degradation policy as it pertains to barium
content and the sodium absorption ratio, SAR. The DEQ has requested the
Environmental Quality Council to hold a public hearing on these standards and
policies. The DEQ may cease granting water discharge permits until the hearing
is conducted. As we have throughout the development of this play, we will
continue to work with the DEQ and other regulatory agencies to address any
concerns with the quality of the water discharged. We currently anticipate that
the hearing will be held in January 2001 and should result in the DEQ's decision
to resume issuance of water discharge permits. However, we can make no assurance
as to the timing of the January 2001 hearing or the DEQ's decision regarding the
issuance of new water discharge permits or the conditions under which new water
discharge permits will be granted. The timing of our drilling schedule and
related capital expenditures for Powder River coal bed methane development may
be negatively affected if the DEQ's decision is not reached in January 2001 or
if the terms of the water discharge permits are unfavorable.
Our capital budget in this area provides for expenditures of approximately
$50.0 million during 2000 of which $36.0 million was spent during the first nine
months of 2000. This capital budget includes approximately $35.5 million for
drilling costs for our interest in approximately 1,000 wells, production
equipment and undeveloped acreage and $14.5 million for compression. In March
2000, we entered into a ten-year operating lease agreement for compression
equipment of which $7.5 million was available at September 30, 2000. Depending
upon future drilling success, we may need to make additional capital
expenditures to continue expansion in this basin. However, because of drilling
and other uncertainties beyond our control, we can make no assurance that we
will incur this level of capital expenditure or that we will make future capital
expenditures.
We own an approximate 13% equity interest in Fort Union Gas Gathering
L.L.C., the only asset of which is a 106-mile long, 24-inch gathering pipeline
and treater to gather and treat natural gas in the Powder River basin in
northeast Wyoming. We are the construction manager and field operator of Fort
Union. This system has a capacity of approximately 450 MMcf/D of natural gas
with expansion capability and averaged 183 MMcf/D of throughput in the third
quarter of 2000. In the third quarter of 2000, the operating committee of Fort
Union approved preliminary plans to increase the capacity of the gathering
system and header to 635 MMcf/D. The header delivers coal bed methane gas to a
treating facility near Glenrock, Wyoming and accesses interstate pipelines
serving gas markets in the Rocky Mountain and Midwest regions of the United
States. We
17
<PAGE>
currently have a long-term agreement for firm gathering services on 60 MMcf/D of
capacity at $.14 per Mcf on Fort Union and a right to contract for additional
capacity as the system expands.
Southwest Wyoming - Our facilities in southwest Wyoming are comprised of the
Granger facility and a 72% ownership interest in the Lincoln Road facility, or
collectively the Granger Complex. These facilities have a combined operational
capacity of 285 MMcf/D and processed an average of 163 MMcf/D in the third
quarter of 2000.
We also own the rights to drill on 360,000 gross acres, or 40,000 net acres,
in the Jonah field and Hoback basin which includes the Pinedale anticline area.
We are currently participating in the development of a portion of this acreage.
We have an approximate 11.25% working interest in 1,920 gross acres in the Jonah
field and have agreed to participate in the drilling of 15 gross wells in 2000.
Eight of these wells have been completed and are currently producing a combined
gross volume of 26 MMcf/D for processing at our Granger facility. We also have
an approximate 10% working interest in 22,000 gross acres along the Pinedale
anticline section of the Hoback basin and have agreed to participate in the
drilling of 13 gross wells in 2000. None of these wells have been completed.
Our total capital budget in this area provides for expenditures of
approximately $12.2 million during 2000, of which $4.2 million was spent in the
first nine months of 2000. This capital budget includes approximately $3.7
million for drilling costs and production equipment and approximately $8.5
million related to the gathering systems and plant facilities. Because of
drilling and other uncertainties beyond our control, we can provide no assurance
that we will incur this level of capital expenditure or that we will make future
capital expenditures.
Financing Facilities
Revolving Credit Facility. The Revolving Credit Facility is with a syndicate
of banks and provides for a maximum borrowing commitment of $250 million
consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A,
and a five-year $167 million Revolving Credit Facility, or Tranche B. At
September 30, 2000, $73.8 million in total was outstanding under this facility.
The Revolving Credit Facility bears interest at various spreads over the
Eurodollar rate, or the greater of the Federal Funds rate or the agent bank's
prime rate. We have the option to determine which rate will be used. We also pay
a facility fee on the commitment. The interest rate spreads and facility fee are
adjusted based on our debt to capitalization ratio and range from .75% to 2.00%.
At September 30, 2000, the interest rate payable on the facility was 8.1% per
annum. We are required to maintain a total debt to capitalization ratio of not
more than 60% through December 31, 2000 and not more than 55% thereafter, and a
senior debt to capitalization ratio of not more than 40% through December 31,
2001 and not more than 35% thereafter. The agreement also requires a quarterly
test of the ratio of EBITDA (excluding some non-recurring items) for the last
four quarters, to interest and dividends on preferred stock for the same period.
The ratio must exceed 1.50 to 1.0 through September 30, 2000 and increases
periodically to 3.25 to 1.0 by December 31, 2002. This facility is guaranteed
and secured via a pledge of the stock of our significant subsidiaries. We
utilize excess daily funds to reduce any outstanding balances on the Revolving
Credit Facility and associated interest expense.
Master Shelf Agreement. In December 1991, we entered into a Master Shelf
Agreement with The Prudential Insurance Company of America. Amounts outstanding
under the Master Shelf Agreement at September 30, 2000 are as indicated in the
following table (dollars in thousands):
<TABLE>
<CAPTION>
Interest Final
Issue Date Amount Rate Maturity Principal Payments Due
------------------- -------- ------ ------------------ ---------------------------------------------------
<S> <C> <C> <C> <C>
October 27, 1992 $ 25,000 7.99% October 27, 2003 8,333 on each of October 27, 2001 through 2003
December 27, 1993 25,000 7.23% December 27, 2003 single payment at maturity
October 27, 1994 25,000 9.05% October 27, 2001 single payment at maturity
October 27, 1994 25,000 9.24% October 27, 2004 single payment at maturity
July 28, 1995 50,000 7.61% July 28, 2007 10,000 on each of July 28, 2003 through 2007
--------
$150,000
========
</TABLE>
Our agreement with Prudential was amended in 1999 to reflect the following
provisions. We are required to maintain a current ratio of at least .9 to 1.0; a
minimum tangible net worth equal to the sum of $300 million plus 50% of
consolidated net earnings earned from January 1, 1999 plus 75% of the net
proceeds of any equity offerings after January 1, 1999; a total debt to
capitalization ratio of not more than 60% through December 31, 2001 and of not
more than 55% thereafter and a senior debt to capitalization ratio of 40%
through March 2002 and 35% thereafter. This agreement also requires an EBITDA to
interest ratio of not less than 2.0 to 1.0 increasing to a ratio of not less
than 3.75 to 1.0 by March 31, 2002 and an EBITDA to interest on senior debt
ratio of not less than 2.25 to 1.0 increasing to a ratio of not less than 5.50
to 1.0 by March 31, 2002. EBITDA in these calculations excludes some non-
recurring items. In addition, this agreement contains a calculation limiting
18
<PAGE>
dividends under which approximately $47.4 million was available at September 30,
2000. We are currently paying an annual fee of 0.50% on the amounts outstanding
on the Master Shelf Agreement. This fee will continue until we have received an
implied investment grade rating on our senior secured debt. Borrowings under the
Master Shelf Agreement are guaranteed by and secured via a pledge of the stock
of our significant subsidiaries.
1995 Senior Notes. In 1995, we sold $42 million of Senior Notes, the 1995
Senior Notes, to a group of insurance companies with an interest rate of 8.16%
per annum. In March 1999, we prepaid $15 million of the principal amount
outstanding on the 1995 Senior Notes at par. The remaining principal amount
outstanding of $27 million was prepaid in September 2000 with funds available
under our Revolving Credit Facility. In connection with the prepayment in 2000,
we made a pre-tax make-whole payment of approximately $2.0 million and expensed
capitalized fees of approximately $752,000. The combined costs of approximately
$2.7 million, net of a tax benefit of $997,000, are reflected as an
extraordinary loss on early extinguishment of debt in the third quarter of 2000.
Senior Subordinated Notes. In 1999, we sold $155.0 million of Senior
Subordinated Notes in a private placement with a final maturity of 2009 due in a
single payment. The Subordinated Notes bear interest at 10% per annum and were
priced at 99.225% to yield 10.125%. These notes contain maintenance covenants
which include limitations on debt incurrence, restricted payments, liens and
sales of assets. The Subordinated Notes are unsecured and are guaranteed on a
subordinated basis by our significant subsidiaries. In November 1999, we
exchanged the privately placed notes for registered publicly tradeable notes
under the same terms and conditions. We incurred approximately $5.0 million in
offering commissions and expenses which have been capitalized and will be
amortized over the term of the notes.
Covenant Compliance. We were in compliance with all covenants in our debt
agreements at September 30, 2000. Taking into account all the covenants
contained in these agreements, we had approximately $130 million of available
borrowing capacity at September 30, 2000. To increase our borrowing capacity,
strengthen our credit ratings and to reduce our overall debt outstanding, we may
continue to dispose of non-strategic assets and investigate alternative
financing sources including the issuance of public debt, project-financing,
joint ventures and operating leases.
19
<PAGE>
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
----------------------------------------------------------
Risk Management Activities
Our commodity price risk management program has two primary objectives. The
first goal is to preserve and enhance the value of our equity volumes of gas and
NGLs with regard to the impact of commodity price movements on cash flow, net
income and earnings per share in relation to those anticipated by our operating
budget. The second goal is to manage price risk related to our gas, crude oil
and NGL marketing activities to protect profit margins. This risk relates to
hedging fixed price purchase and sale commitments, preserving the value of
storage inventories, reducing exposure to physical market price volatility and
providing risk management services to a variety of customers.
We utilize a combination of fixed price forward contracts, exchange-traded
futures and options, as well as fixed index swaps, basis swaps and options
traded in the over-the-counter, or OTC, market to accomplish these objectives.
These instruments allow us to preserve value and protect margins because
corresponding losses or gains in the value of the financial instruments offset
gains or losses in the physical market.
We use futures, swaps and options to reduce price risk and basis risk. Basis
is the difference in price between the physical commodity being hedged and the
price of the futures contract used for hedging. Basis risk is the risk that an
adverse change in the futures market will not be completely offset by an equal
and opposite change in the cash price of the commodity being hedged. Basis risk
exists in natural gas primarily due to the geographic price differentials
between cash market locations and futures contract delivery locations.
We enter into futures transactions on the New York Mercantile Exchange, or
NYMEX, and the Kansas City Board of Trade and through OTC swaps and options with
various counterparties, consisting primarily of financial institutions and other
natural gas companies. We conduct our standard credit review of OTC
counterparties and have agreements with these parties that contain collateral
requirements. We generally use standardized swap agreements that allow for
offset of positive and negative exposures. OTC exposure is marked-to-market
daily for the credit review process. Our OTC credit risk exposure is partially
limited by our ability to require a margin deposit from our major counterparties
based upon the mark-to-market value of their net exposure. We are subject to
margin deposit requirements under these same agreements. In addition, we are
subject to similar margin deposit requirements for our NYMEX counterparties
related to our net exposures.
The use of financial instruments may expose us to the risk of financial loss
in certain circumstances, including instances when (i) equity volumes are less
than expected, (ii) our customers fail to purchase or deliver the contracted
quantities of natural gas or NGLs, or (iii) our OTC counterparties fail to
perform. To the extent that we engage in hedging activities, we may be
prevented from realizing the benefits of favorable price changes in the physical
market. However, we are similarly insulated against decreases in these prices.
We hedged a portion of our estimated equity volumes of gas and NGLs in 2000
at pricing levels approximating our 2000 operating budget. Our equity gas and
NGL hedging strategy for 2000 establishes a minimum price while allowing varying
levels of market participation above the minimum. As of September 30, 2000, we
had hedged approximately 38%, or 35,000 MMBtu/day, of our anticipated equity gas
for the balance of 2000 at a weighted average NYMEX equivalent minimum price of
$2.33 per MMBtu and an additional 24%, or 22,000 MMBtu/day, with collars with a
minimum price of $2.10 per MMBtu and a maximum price of $2.44 per MMBtu NYMEX
equivalent price. We also hedged an incremental 10,000 MMBtu/day of anticipated
equity production for October 2000 through March 2001 with collars at a weighted
average NYMEX equivalent minimum price of $2.75 per MMBtu and a maximum price of
$3.50 per MMBtu.
We have also hedged a portion of our estimated equity volumes of gas in
2001. As of September 30, 2000, we had hedged approximately 36%, or 36,000
MMBtu/day, of our anticipated equity gas for the first quarter of 2001 at a
weighted average NYMEX equivalent price of $4.14 per MMBtu and an additional
10%, or 10,000 MMBtu/day in the first quarter, with collars with a minimum price
of $2.75 per MMBtu and a maximum price of $3.50 per MMBtu NYMEX equivalent
price. For the remainder of 2001, we have hedged 40%, or 41,000 MMBtu/day, of
our anticipated equity gas for the second, third and fourth quarters of 2001 at
a weighted average NYMEX equivalent price of $4.14 per MMBtu.
Additionally, we have hedged approximately 26%, or 25,000 Bbl per month of
our anticipated equity natural gasoline, condensate and crude oil for 2000 using
a collar with a minimum price of $15.00 per Bbl and maximum price of $17.00 per
Bbl NYMEX crude oil monthly average price. We have also hedged approximately
46%, or 195,000 Bbl per month, of our anticipated equity production of NGLs for
2000 with a minimum weighted average Mt. Belvieu composite price of $0.27 per
gallon. We do not have any hedges in place for crude oil or NGLs in 2001.
20
<PAGE>
At September 30, 2000, we had $1.2 million of unrecognized gains in
inventory that will be recognized primarily during the fourth quarter of 2000.
At September 30, 2000, we had unrecognized net losses of $10.0 million related
to financial instruments that may be offset by corresponding unrecognized net
gains from our obligations to sell physical quantities of gas and NGLs.
We enter into speculative futures, swap and option trades on a very limited
basis for purposes that include testing of hedging techniques. Our policies
contain strict guidelines for these trades including predetermined stop-loss
requirements and net open position limits. Speculative futures, swap and option
positions are marked-to-market at the end of each accounting period and any gain
or loss is recognized in income for that period. Net gains or losses from these
speculative activities for the quarters and nine months ended September 30, 2000
and 1999 were not material.
Foreign Currency Derivative Market Risk
As a normal part of our business, we enter into physical gas transactions
which are payable in Canadian dollars. We enter into forward purchases and sales
of Canadian dollars from time to time to fix the cost of our future Canadian
dollar denominated natural gas purchase, sale, storage and transportation
obligations. This is done to protect marketing margins from adverse changes in
the U.S. and Canadian dollar exchange rate between the time the commitment for
the payment obligation is made and the actual payment date of such obligation.
As of September 30, 2000, the net notional value of such contracts was
approximately $11.4 million in Canadian dollars, which approximates its fair
market value.
Accounting for Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board, the FASB, issued
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities"
("SFAS No. 133"), effective for fiscal years beginning after June 15, 2000.
Under SFAS No. 133, which was subsequently amended by SFAS No. 138, we will be
required to recognize the change in the market value of all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. Changes in the fair value of derivatives are
recorded each period in current earnings or other comprehensive income depending
upon the nature of the underlying transaction. We do not believe the adoption of
SFAS No. 133 will have a material impact on our earnings or financial position
as it relates to our equity hedging program. We currently anticipate adopting
mark to market accounting in the first quarter of 2001 for the remainder of our
marketing activities. We cannot at this time determine the impact of adopting
mark-to-market on our earnings or financial position.
21
<PAGE>
Principal Facilities
The following tables provide information concerning our principal facilities
at September 30, 2000. We also own and operate several smaller treating,
processing and transmission facilities located in the same areas as our other
facilities.
<TABLE>
<CAPTION>
Average for the Nine Months Ended
September 30, 2000
Gas Gas -----------------------------------------------
Year Placed Gathering Throughput Gas Gas NGL
In System Capacity Throughput Production Production
Plant Facilities (1) Service Miles(2) (MMcf/D)(3) (MMcf/D)(4) (MMcf/D)(5) (MGal/D)(5)
--------------------------- --------- ----------------- ------------ -------------- -------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Texas
Bethel Treating (6)...... 1997 86 300 170 167 -
Gomez Treating........... 1971 385 280 109 100 -
Midkiff/Benedum.......... 1949 2,173 165 149 94 921
Mitchell Puckett
Gathering............... 1972 90 120 100 64 1
Louisiana
Toca (7)(8).............. 1958 - 160 126 121 103
Wyoming
Coal Bed Methane
Gathering............... 1990 444 223 204 190 -
Fort Union Gas Gathering
(15).................... 1999 106 450 75 75 -
Granger(7)(9)(10)........ 1987 482 235 141 117 368
Hilight Complex (7)...... 1969 626 80 18 14 60
Kitty/Amos Draw (7)...... 1969 314 17 12 8 47
Lincoln Road (10)........ 1988 149 50 20 19 22
Newcastle (7)............ 1981 146 5 3 2 18
Red Desert (7)........... 1979 111 42 15 13 26
Reno Junction (9)........ 1991 - - - - 92
Oklahoma
Arkoma (16).............. 1985 76 12 10 9 -
Chaney Dell.............. 1966 2,054 130 52 42 170
Westana (14)............. 1981 871 45 67 48 114
New Mexico
San Juan River (6)....... 1955 140 60 26 20 37
Utah
Four Corners Gathering... 1988 104 15 2 2 13
----------------- ------------ -------------- -------------- ---------------
Total................... 8,357 2,389 1,299 1,105 1,992
================= ============ ============== ============== ===============
</TABLE>
<TABLE>
<CAPTION>
Average for the Nine Months
Ended September 30, 2000
----------------------------
Year Pipeline Gas
Placed In Transmission Capacity Throughput
Transmission Facilities (1) Service Miles(2) (MMcf/D)(2) (MMcf/D)(4)
--------------------------- --------- ----------------- ------------ --------------
<S> <C> <C> <C> <C>
MIGC (11)(13).............. 1970 245 130 175
MGTC (12).................. 1963 252 18 13
----------------- ------------ --------------
Total.................... 497 148 188
================= ============ ==============
</TABLE>
Footnotes on following page.
22
<PAGE>
(1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%);
Lincoln Road (72%); Newcastle (50%) and Fort Union gathering system (13%).
We operate all facilities and all data includes our interests and the
interests of other joint interest owners and producers of gas volumes
dedicated to the facility. Unless otherwise indicated, all facilities shown
in the table are gathering and processing facilities.
(2) Gas gathering system miles, interconnect and transmission miles and
pipeline capacity are as of September 30, 2000.
(3) Gas throughput capacity is as of September 30, 2000 and represents capacity
in accordance with design specifications unless other constraints exist,
including permitting or field compression limits.
(4) Aggregate wellhead natural gas volumes collected by a gathering system or
volumes transported by a pipeline.
(5) Volumes of gas and NGLs are allocated to a facility when a well is
connected to that facility; volumes exclude NGLs fractionated for third
parties.
(6) Sour gas facility (capable of processing or treating gas containing
hydrogen sulfide and/or carbon dioxide).
(7) Fractionation facility (capable of fractionating raw NGLs into end-use
products).
(8) Straddle plant, or a plant located near a transmission pipeline that
processes gas dedicated to or gathered by a pipeline company or another
third party.
(9) NGL production includes conversion of third-party feedstock to iso-butane.
(10) We and our joint venture partner at the Lincoln Road facility have agreed
to process all gas at our Granger facility so long as there is available
capacity at the Granger facility. Accordingly, operations at the Lincoln
Road facility have been temporarily suspended since January 1999.
(11) MIGC is an interstate pipeline located in Wyoming and is regulated by the
Federal Energy Regulatory Commission.
(12) MGTC is a public utility located in Wyoming and is regulated by the Wyoming
Public Service Commission.
(13) Pipeline capacity represents capacity at the Powder River junction only and
does not include northern delivery points.
(14) We acquired the remaining 50% interest in Westana Gathering Company in
February 2000.
(15) A portion of the Gas Throughput and Gas Production for this gathering
system is also included in the volumes reported under Coal Bed Methane
Gathering.
(16) This facility was sold in August 2000.
23
<PAGE>
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
-----------------
Western Gas Resources, Inc., Mountain Gas Resources, Inc., v. R.I.S.
Resources International Corporation, a British Columbia , Canada
corporation; RIS Resources (USA) Inc., a Texas Corporation, United States
District Court, Colorado, Civil Action No. 00-S-599
As previously disclosed, our subsidiary Mountain Gas was a defendant in
prior litigation, styled as McMurry Oil Company, et al. v. TBI Exploration,
Inc., Mountain Gas Resources, Inc. and Wildhorse Energy Partners, LLC, District
Court, Ninth Judicial District, Sublette County, Wyoming, Civil Action No. 5882,
which was settled on all issues for substantially less than the amount claimed.
Western and Mountain Gas are seeking reimbursement from RIS Resources, (USA),
Inc., Mountain Gas' joint venture partner, for 50% of the settlement amount
which was paid in full by Mountain Gas. The parties are proceeding with
discovery.
Western Gas Resources, Inc., v. Amerada Hess Corporation, District Court,
Denver County, Colorado, Civil Action No. 00-CV-1433.
As previously disclosed, we were a defendant in prior litigation, styled as
Berco Resources, Inc. v. Amerada Hess Corporation and Western Gas Resources,
Inc., United States District Court, District of Colorado, Civil Action No. 97-
WM-1332, which has been settled for an amount which did not have a material
impact on our results of operations or financial position. We are seeking
reimbursement from Amerada Hess under a contractual indemnity. Amerada Hess
sought a motion to dismiss, which was denied. We have amended our original
complaint and requested a jury trial in this case. The parties are proceeding
with discovery.
Other
We are involved in various other litigation and administrative proceedings
arising in the normal course of our business. In the opinion of management, any
liabilities that may result from these claims will not, individually or in the
aggregate, have a material adverse effect on our financial position or results
of operations.
24
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
None
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
10.24 Limited Waiver, Consent, Release and Amendment No. 4 to the Second
Amended and Restated Master Shelf Agreement effective January 31, 1996
by and among Western Gas Resources, Inc. and The Prudential Insurance
Company of America and Pruco Life Insurance Company.
10.25 Fourth Amendment to Loan Agreement by and among Western Gas Resources,
Inc. and NationsBank, as Agent, and the Lenders thereto dated April
29, 1999.
27 Financial Data Schedule.
(b) Reports on Form 8-K:
None
25
<PAGE>
SIGNATURES
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.
WESTERN GAS RESOURCES, INC.
---------------------------
(Registrant)
Date: November 13, 2000 By: /s/LANNY F. OUTLAW
--------------------------------------
Lanny F. Outlaw
Chief Executive Officer and President
Date: November 13, 2000 By: /s/WILLIAM J. KRYSIAK
--------------------------------------
William J. Krysiak
Vice President - Finance
(Principal Financial and Accounting
Officer)
26
