<PAGE>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
------------------------------------------------
Washington, D.C. 20549
----------------------
FORM 10-Q/A
(Mark One)
----------
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 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
--------------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
(303) 452-5603
--------------------------------------------------------------------------------
Registrant's telephone number, including area code
No changes
--------------------------------------------------------------------------------
(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 August 1, 2000, there were 32,241,791 shares of the registrant's Common Stock
outstanding.
This Form 10-Q/A for the quarterly period ended June 30, 2000 is being filed to
correct the omission of Item 4, Submission of Matters to a Vote of Security
Holders. The Annual Meeting of Stockholders was held on May 19, 2000 and the
results of matters submitted for vote to the stockholders are included under
this item.
1
<PAGE>
Western Gas Resources, Inc.
Form 10-Q/A
Table of Contents
<TABLE>
<CAPTION>
PART I - Financial Information Page
------------------------------ ----
<S> <C> <C>
Item 1. Financial Statements
Consolidated Balance Sheet - June 30, 2000 and December 31, 1999........................... 3
Consolidated Statement of Cash Flows - Three and Six Months Ended
June 30, 2000 and 1999..................................................................... 4
Consolidated Statement of Operations - Three and Six Months Ended
June 30, 2000 and 1999..................................................................... 5
Consolidated Statement of Changes in Stockholders' Equity - Six Months Ended
June 30, 2000.............................................................................. 6
Notes to Consolidated Financial Statements................................................. 7
Item 2. Management's Discussion and Analysis of Financial Condition and Results of
Operations................................................................................. 11
PART II - Other Information
---------------------------
Item 1. Legal Proceedings.......................................................................... 22
Item 4. Submission of matters to a vote of security holders........................................ 23
Item 6. Exhibits and Reports on Form 8-K........................................................... 23
Signatures............................................................................................. 24
</TABLE>
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>
June 30, December 31,
2000 1999
---------- ----------
ASSETS (unaudited)
------
<S> <C> <C>
Current assets:
Cash and cash equivalents..................................................... $ 10,572 $ 14,062
Trade accounts receivable, net................................................ 335,538 196,739
Product inventory............................................................. 32,202 35,228
Parts inventory............................................................... 9,059 10,318
Assets held for sale.......................................................... - 7,237
Other......................................................................... 2,796 9,571
---------- ----------
Total current assets........................................................ 390,167 273,155
---------- ----------
Property and equipment:
Gas gathering, processing, storage and transmission........................... 863,725 808,274
Oil and gas properties and equipment.......................................... 125,798 104,137
Construction in progress...................................................... 42,474 39,987
---------- ----------
1,031,997 952,398
Accumulated depreciation, depletion and amortization........................... (285,119) (260,081)
---------- ----------
Total property and equipment, net........................................... 746,878 692,317
---------- ----------
Other assets:
Gas purchase contracts (net of accumulated amortization of $32,315 and
$31,273, respectively)...................................................... 35,840 36,883
Other......................................................................... 14,846 47,131
---------- ----------
Total other assets.......................................................... 50,686 84,014
---------- ----------
Total assets................................................................... $1,187,731 $1,049,486
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable.............................................................. $ 342,175 $ 240,235
Accrued expenses.............................................................. 24,519 41,075
Dividends payable............................................................. 4,221 4,218
---------- ----------
Total current liabilities................................................... 370,915 285,528
Long-term debt................................................................. 402,500 378,250
Deferred income taxes payable.................................................. 49,228 35,965
---------- ----------
Total liabilities........................................................... 822,643 699,743
---------- ----------
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; 32,218,588 and
32,173,009 shares issued, respectively...................................... 3,255 3,220
Treasury stock, at cost, 25,016 shares in treasury............................ (788) (788)
Additional paid-in capital.................................................... 397,802 397,522
Accumulated deficit........................................................... (35,917) (51,064)
Accumulated other comprehensive income........................................ 1,204 1,321
Notes receivable from key employees secured by common stock................... (884) (884)
---------- ----------
Total stockholders' equity.................................................. 365,088 349,743
---------- ----------
Total liabilities and stockholders' equity..................................... $1,187,731 $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>
Six Months Ended
June 30,
-----------------------
2000 1999
--------- -----------
<S> <C> <C>
Reconciliation of net income (loss) to net cash provided by (used in) operating activities:
Net income (loss)............................................................................ $ 23,586 $ (16,940)
Add income items that do not affect cash:
Depreciation, depletion and amortization.................................................... 27,532 24,755
(Gain) loss on the sale of property and equipment........................................... (5,634) 21,717
Deferred income taxes....................................................................... 13,262 (10,344)
Other non-cash items, net................................................................... 880 (1,371)
--------- -----------
59,626 17,817
Adjustments to working capital to arrive at net cash provided by (used in)
operating activities:
(Increase) decrease in trade accounts receivable............................................ (136,174) 38,301
Decrease in product inventory............................................................... 3,026 28,828
Decrease in parts inventory................................................................. 1,259 236
Decrease in other current assets............................................................ 6,305 2,893
Decrease in other assets and liabilities, net............................................... 6 1,000
Increase (decrease) in accounts payable..................................................... 98,253 (35,595)
Decrease in accrued expenses................................................................ (16,556) (9,732)
--------- -----------
Net cash provided by (used in) operating activities.......................................... 15,745 43,748
--------- -----------
Cash flows from investing activities:
Purchases of property and equipment......................................................... (51,216) (34,247)
Proceeds from the dispositions of property and equipment.................................... 15,916 148,100
Contributions to equity investees........................................................... - (100)
--------- -----------
Net cash used in investing activities........................................................ (35,300) 113,753
--------- -----------
Cash flows from financing activities:
Net proceeds from exercise of common stock options.......................................... 259 -
Proceeds from issuance of long-term debt.................................................... - 155,000
Debt issue costs paid....................................................................... (5) (9,124)
Payments on revolving credit facility....................................................... (608,136) (1,815,300)
Borrowings under revolving credit facility.................................................. 632,386 1,611,300
Payments on notes........................................................................... - (84,047)
Dividends paid.............................................................................. (8,439) (8,432)
--------- -----------
Net cash provided by financing activities.................................................... 16,065 (150,603)
--------- -----------
Net increase (decrease) in cash and cash equivalents......................................... (3,490) 6,898
Cash and cash equivalents at beginning of period............................................. 14,062 4,400
--------- -----------
Cash and cash equivalents at end of period................................................... $ 10,572 $ 11,298
========= ===========
</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 Six Months Ended
June 30, June 30,
------------------------- -------------------------
2000 1999 2000 1999
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Revenues:
Sale of residue gas.................................... $ 506,793 $ 364,371 $ 919,673 $ 715,055
Sale of natural gas liquids............................ 122,219 76,206 257,607 139,854
Processing, transportation and storage revenue......... 9,410 13,246 23,295 24,319
Other, net............................................. 3,394 2,479 6,393 6,434
----------- ----------- ----------- -----------
Total revenues....................................... 641,816 456,302 1,206,968 885,662
----------- ----------- ----------- -----------
Costs and expenses:
Product purchases...................................... 576,727 413,813 1,077,870 795,178
Plant operating expense................................ 17,100 14,054 32,362 33,519
Oil and gas exploration and production expense......... 1,791 1,825 5,937 3,683
Depreciation, depletion and amortization............... 14,223 11,197 27,532 24,755
(Gain)/loss on fixed assets............................ (335) 21,862 (5,634) 21,717
Selling and administrative expense..................... 8,100 8,137 15,489 15,952
Interest expense....................................... 7,809 7,010 16,027 15,753
----------- ----------- ----------- -----------
Total costs and expenses............................. 625,415 477,898 1169,583 910,557
----------- ----------- ----------- -----------
Income (loss) before income taxes....................... 16,401 (21,596) 37,385 (24,895)
Provision (benefit) for income taxes:
Current................................................ - 1,032 537 1,282
Deferred............................................... 5,821 (8,971) 13,262 (10,344)
----------- ----------- ----------- -----------
Total provision (benefit) for income taxes........... 5,821 (7,939) 13,799 (9,062)
----------- ----------- ----------- -----------
Income (loss) before extraordinary items................ 10,580 (13,657) 23,586 (15,833)
Extraordinary charge for early extinguishment of debt,
net of tax benefit of $700,000.......................... - (1,107) - (1,107)
----------- ----------- ----------- -----------
Net income (loss)....................................... 10,580 (14,764) 23,586 (16,940)
Preferred stock requirements............................ (2,610) (2,610) (5,220) (5,220)
----------- ----------- ----------- -----------
Income (loss) attributable to common stock.............. $ 7,970 $ (17,374) $ 18,366 $ (22,160)
=========== =========== =========== ===========
Income (loss) per share of common stock................. $ .25 $ (.54) $ .57 $ (.69)
=========== =========== =========== ===========
Weighted average shares of common stock outstanding..... 32,196,793 32,147,993 32,181,331 32,147,993
=========== =========== =========== ===========
Income (loss) per share of common stock -
assuming dilution...................................... $ .24 $ (.54) $ .56 $ (.69)
=========== =========== =========== ===========
Weighted average shares of common stock outstanding -
assuming dilution...................................... 32,770,736 32,147,993 32,628,146 32,147,993
=========== =========== =========== ===========
</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............. - - 56,857 - - -
------------- ------------- ------------- ------------- ------------- -------------
Balance at June 30, 2000............ 1,400,000 2,760,000 32,218,588 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......................... - - - 23,586 - - 23,586
Foreign Currency
Translation........................ - - - - (117) - (117)
----------
Comprehensive Income............... 23,469
----------
Dividends:
Dividends declared on
common stock....................... - - - (3,219) - - (3,219)
Dividends declared on $2.28
cumulative preferred stock......... - - - (1,598) - - (1,598)
Dividends declared on
$2.625 cumulative
convertible preferred stock........ - - - (3,622) - - (3,622)
Stock options exercised............ 35 - 280 - - - 280
----------- ----------- ------------ -------- ----------- --------- ----------
Balance at June 30, 2000........... $ 3,255 $ (788) $ 397,802 $(35,917) $ 1,029 $ (884) $ 365,008
=========== =========== ============ ======== =========== ========= ==========
</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 June 30, 2000 and for the
three and six month periods ended June 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 six
months ended June 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.
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 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 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 $5.2
million, respectively, for each of the three and six month periods ended June
30, 2000 and 1999. Common stock options, which are potential common shares, had
a dilutive effect on earnings and increased the weighted average shares of
common stock outstanding by 573,493 and 446,815 for the three and six month
periods ended June 30, 2000. Common stock options, which are potential common
shares, were anti-dilutive for the period ended June 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 June 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.
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.
The proceeds from these sales were used to reduce borrowings outstanding on
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. This
transaction is subject to final accounting adjustment. 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 reclassed from Other assets to Property and equipment.
SUPPLEMENTARY CASH FLOW INFORMATION
Interest paid was $17.7 million and $16.7 million for the six months ended
June 30, 2000 and 1999, respectively.
7
<PAGE>
No income taxes were paid during the six months ended June 30, 2000 or 1999.
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 includes the exploration and
development of oil and gas properties primarily in basins where our facilities
are located. The majority of the gas and oil produced 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 facilities. The operations associated with the Katy
Facility, which was sold in April 1999, are included in the Marketing segment
for the three and six months ended June 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 $(6.5) million and $(2.6) million for the
quarters ended June 30, 2000 and June 30, 1999, respectively and of $(9.6)
million and $(2.3) million for the six months ended June 30, 2000 and June 30,
1999, respectively.
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 six month periods ended June 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 June 30, 2000
Revenues from unaffiliated customers...... $ 6,768 $ 1,144 $ 637,393 $ 1,877 $ 35 $ 8 $ 647,225
Interest income........................... 1 - 3 - 6,419 (6,353) 70
Other, net................................ 1,692 41 (6,708) - (504) - (5,479)
Intersegment sales........................ 186,001 17,603 12,948 4,315 13 (220,880) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues............................ 194,462 18,788 643,636 6,192 5,963 (227,225) 641,816
-------- -------- ---------- ------- ------- --------- ----------
Product purchases......................... 143,245 1,028 647,271 - (65) (214,752) 576,727
Plant operating expense................... 15,416 291 - 1,996 (328) (275) 17,100
Oil and gas exploration
and production expense................... 31 8,456 - - - (6,696) 1,791
-------- -------- ---------- ------- ------- --------- ----------
Operating profit.......................... $ 35,770 $ 9,013 $ (3,635) $ 4,196 $ 6,356 $ (5,502) $ 46,198
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and amortization.. 8,991 3,493 40 409 1,290 - 14,223
Interest expense.......................... 7,809
Gain on sale of assets.................... (335)
Selling and administrative expense........ 8,100
----------
</TABLE>
8
<PAGE>
<TABLE>
<CAPTION>
Gas
Gathering Elim-
and Trans- inating
Processing Production Marketing mission Corporate Entries Total
---------- ---------- ---------- ---------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Income (loss) before income taxes......... $ 16,401
==========
Identifiable assets....................... $552,073 $109,068 $ 68 $46,856 $38,907 $ - $ 746,972
======== ======== ========== ======= ======= ========= ==========
</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 June 30, 1999
Revenues from unaffiliated customers...... $ 11,934 $ 540 $ 444,641 $ 1,897 $ - $ - $ 459,012
Interest income........................... - - 39 - 6,238 (6,197) 80
Other, net................................ 27 - (4,028) 87 1,123 - (2,791)
Intersegment sales........................ 88,907 5,731 20,951 4,083 14 (119,686) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues............................ 100,868 6,271 461,603 6,067 7,375 (125,883) 456,301
-------- -------- ---------- ------- ------- --------- ----------
Product purchases......................... 68,743 450 472,246 - - (127,626) 413,813
Plant operating expense................... 11,736 95 (10,027) 3,198 - (9,052) 14,054
Oil and gas exploration
and production expense................... 72 1,752 1 - - - 1,825
-------- -------- ---------- ------- ------- --------- ----------
Operating profit.......................... $ 20,317 $ 3,974 $ (617) $ 2,869 $ 7,375 $ (7,309) $ 26,609
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and amortization.. 7,360 2,135 297 261 1,144 - 11,197
Interest expense.......................... 7,010
Loss on sale of assets.................... 21,862
Selling and administrative expense........ 8,137
----------
Income (loss) before income taxes......... $ (21,597)
==========
Identifiable assets....................... $524,081 $ 81,086 $ 94 $48,085 $36,744 $ - $ 690,090
======== ======== ========== ======= ======= ========= ==========
</TABLE>
<TABLE>
<CAPTION>
Gas
Gathering Elim-
and Trans- inating
Processing Production Marketing mission Corporate Entries Total
---------- ---------- ---------- ---------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Six months ended June 30, 2000
Revenues from unaffiliated customers...... $ 18,174 $ 2,130 $1,188,715 $ 4,255 $ 61 $ - $1,213,335
Interest income........................... 34 2 27 - 12,257 (12,021) 299
Other, net................................ 1,672 41 (8,911) - 532 - (6,666)
Intersegment sales........................ 320,343 27,907 39,281 8,719 17 (396,267) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues............................ 340,223 30,080 1,219,112 12,974 12,867 (408,288) 1,206,968
-------- -------- ---------- ------- ------- --------- ----------
Product purchases......................... 246,253 1,532 1,219,958 - (90) (389,783) 1,077,870
Plant operating expense................... 28,478 308 - 4,264 (72) (616) 32,362
Oil and gas exploration
and production expense................... 31 12,602 - - - (6,696) 5,937
-------- -------- ---------- ------- ------- --------- ----------
Operating profit.......................... $ 65,461 $ 15,638 $ (846) $ 8,710 $13,029 $ (11,193) $ 90,799
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and amortization.. 17,562 6,382 80 833 2,675 - 27,532
Interest expense.......................... 16,027
Gain on sale of assets.................... (5,634)
Selling and administrative expense........ 15,489
----------
Income (loss) before income taxes......... $ 37,385
==========
Identifiable assets....................... $552,073 $109,068 $ 68 $46,856 $38,907 $ - $ 746,972
======== ======== ========== ======= ======= ========= ==========
</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>
Six months ended June 30, 1999
Revenues from unaffiliated customers...... $ 23,214 $ 944 $ 853,262 $ 3,696 $ 538 $ - $ 881,654
Interest income........................... 1 151 61 - 13,271 (13,190) 294
Other, net................................ 114 - 1,263 441 1,895 - 3,713
Intersegment sales........................ 165,495 10,730 38,940 8,182 28 (223,375) -
-------- -------- ---------- ------- ------- --------- ----------
Total revenues............................ 188,824 11,825 893,526 12,319 15,732 (236,565) 885,661
-------- -------- ---------- ------- ------- --------- ----------
Product purchases......................... 127,819 905 888,858 - - (222,404) 795,178
Plant operating expense................... 26,103 107 1,672 5,829 483 (675) 33,519
Oil and gas exploration
and production expense................... 207 3,520 (44) - - - 3,683
-------- -------- ---------- ------- ------- --------- ----------
Operating profit.......................... $ 34,695 $ 7,293 $ 3,040 $ 6,490 $15,249 $ (13,486) $ 53,281
======== ======== ========== ======= ======= ========= ==========
Depreciation, depletion and amortization.. 17,597 3,236 1,146 520 2,256 - 24,755
Interest expense.......................... 15,753
Loss on sale of assets.................... 21,717
Selling and administrative expense........ 15,952
----------
Income (loss) before income taxes......... $ (24,896)
==========
Identifiable assets....................... $524,381 $ 81,086 $ 94 $48,085 $36,744 $ - $ 690,390
======== ======== ========== ======= ======= ========= ==========
</TABLE>
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 have not yet determined the
impact that the adoption of SFAS No. 133 will have on our earnings or financial
position.
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.
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 outstanding at June 30, 2000 approximately
160,000 options which will be treated as repriced options. This interpretation
is effective July 1, 2000.
LEGAL PROCEEDINGS
Reference is made to "Part II - Other Information - Item 1. Legal
Proceedings," of this Form 10-Q/A.
10
<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 six months ended June 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/A, 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 six months ended June 30, 2000 compared to the three and six months
ended June 30, 1999
(Dollars in thousands, except per share amounts and operating data).
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------ Percent -------------------- Percent
2000 1999 Change 2000 1999 Change
-------- -------- ------- ---------- -------- -------
<S> <C> <C> <C> <C> <C> <C>
Financial results:
Revenues................................... $641,816 $434,440 48 $1,206,968 $863,945 40
Gross profit............................... 32,310 (6,449) -- 68,901 6,810 912
Net income (loss).......................... 10,580 (14,764) -- 23,586 (16,940) --
Income (loss) per share of common stock.... .25 (.54) -- .57 (.69) --
Income (loss) per share of common stock -
assuming dilution........................ .24 (.54) -- .56 (.69) --
Net cash provided by
operating activities...................... $ 5,925 $ 31,087 (81) $ 15,745 $ 43,748 (64)
Operating data:
Average gas sales (MMcf/D)................. 1,670 1,965 (15) 1,735 2,050 (15)
Average NGL sales (MGal/D)................. 2,815 2,785 1 2,970 2,905 2
Average gas prices ($/Mcf)................. $ 3.34 $ 2.04 64 $ 2.91 $ 1.93 51
Average NGL prices ($/Gal)................. $ .48 $ .30 60 $ .48 $ .27 78
</TABLE>
Net income increased $25.3 million and $40.6 million for the three and six
months ended June 30, 2000 compared to 1999. The increase in net income for the
second quarter of 2000 was primarily attributable to significantly higher gas
and NGL prices in 2000 compared to the prior year. The increase for the six
month period in 2000 was due to the higher gas and NGL prices and an after-tax
gain of $3.4 million recognized on the sale of the stock of our wholly-owned
subsidiary, Western Gas Resources-California in the first quarter of 2000.
Revenues from the sale of gas increased $142.4 million to $506.8 million in
the second quarter of 2000 compared to the same period in 1999. This increase
was due to an improvement in product prices which more than offset a reduction
in sales volume. Average gas prices realized by us increased $1.30 per Mcf to
$3.34 per Mcf in the second quarter of 2000 compared to the same period in 1999.
Included in the realized gas price were approximately $5.3 million of losses
recognized in the second 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 limited extent in 2001. See
further discussion in " - Liquidity and Capital Resources - Risk Management
Activities." Average gas sales volumes decreased 295 MMcf per day to 1,670 MMcf
per day for the three months ended June 30, 2000 compared to the same period in
1999. This decrease was primarily due to the sale in 1999 of our Katy facility
and a related reduction in the sale of gas purchased from third parties.
11
<PAGE>
Revenues from the sale of gas increased $204.6 million to $919.7 million in
the six months ended June 30, 2000 compared to the same period in 1999. This
increase was due to an improvement in product prices which more than offset a
reduction in sales volume. Average gas prices realized by us increased $.98 per
Mcf to $2.91 per Mcf in the six months ended June 30, 2000 compared to the same
period in 1999. Included in the realized gas price were approximately $6.5
million of losses recognized in the six months ended June 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 limited extent in 2001. See further discussion in " - Liquidity and
Capital Resources - Risk Management Activities." Average gas sales volumes
decreased 315 MMcf per day to 1,735 MMcf per day in the six months ended June
30, 2000 compared to the same period in 1999. This decrease was primarily due
to the sale in 1999 of our Katy facility and a related reduction in the sale of
gas purchased from third parties.
Revenues from the sale of NGLs increased $46.0 million in the second quarter
of 2000 compared to the same period in 1999. This increase is due to an
improvement in product prices and additional sales volume. Average NGL prices
realized by us increased $.18 per gallon to $.48 per gallon in the second
quarter of 2000 compared to the same period in 1999. Included in the realized
NGL price were approximately $1.1 million of losses recognized in the second
quarter of 2000 related to futures positions on equity NGL volumes. We have
entered into additional futures positions 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 30 MGal per day to 2,815 MGal per day in the second quarter of 2000
compared to the same period in 1999. This increase in NGL volume is primarily
due to a 76 MGal per day increase in the sale of NGLs purchased from third
parties, offset by a decrease of 46 MGal per day in the sales of NGLs produced
at our facilities resulting from the sale of the Giddings and Black Lake
facilities in 1999.
Revenues from the sale of NGLs increased approximately $117.8 million in the
six months ended June 30, 2000 compared to the same period in 1999. This
increase is due to an improvement in product prices and additional sales volume.
Average NGL prices realized by us increased $.21 per gallon to $.48 per gallon
in the six months ended June 30, 2000 compared to the same period in 1999.
Included in the realized NGL price were approximately $3.1 million of losses
recognized in the six months ended June 30, 2000 related to futures positions on
equity NGL volumes. We have entered into additional futures positions 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 65 MGal per day to 2,970 MGal per day in the
six months ended June 30, 2000 compared to the same period in 1999. This
increase in NGL volume is due to a 49 MGal per day increase in the sale of NGLs
purchased from third parties and a 15 MGal per day increase the sale of NGLs
produced at our facilities. The increase in the sale of NGLs produced at our
facilities in the six months ended June 30, 2000 compared to the same period in
1999 resulted from favorable ethane extraction economics at our Granger facility
in 2000.
Product purchases increased by $162.9 million and $282.7 million in the second
quarter and six months ended June 30, 2000, respectively, compared to the same
period in 1999 primarily due to an increase in commodity prices. Overall,
combined product purchases as a percentage of sales of all products was 92% for
both the quarter and six months ended June 30, 2000 compared to 94% and 93% for
the same periods in 1999, respectively. 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 impacted by the volume of sales of third-party product
and the margin earned on those sales. Marketing margins on residue gas averaged
$.013 per Mcf in the second quarter of 2000 and $.017 per Mcf in the six months
ended June 30, 2000. These are slight increases to the average margin earned in
the 1999 periods. Marketing margins on NGLs averaged $.005 per gallon in the
second quarter of 2000 and $.008 per gallon in the six months ended June 30,
2000 compared to approximately $.004 per gallon in 1999.
Plant operating expense increased $3.0 million in the second quarter of 2000
compared to the same period in 1999 primarily as a result of the acquisition of
the remaining 50% of the Westana Gathering Company in February 2000 and
additional leased compression in the Powder River basin coal bed development.
Plant operating expense decreased by $1.2 million in the six months ended June
30, 2000 compared to the same period in 1999 as the previously discussed items
were offset by operating cost reductions resulting from the sales in 1999 of our
Katy Storage facility, our Giddings gathering system, our MiVida treating
facility and our Black Lake facility.
Depreciation, depletion and amortization increased by $3.0 million and $2.8
million in the second quarter and the six months ended June 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.
12
<PAGE>
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.
The proceeds from these sales were used to reduce borrowings outstanding on
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. This
transaction is subject to final accounting adjustment. 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 reclassed 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.
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 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 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 producers in exploration and production activities. For the
same reason, we may also offer to sell an ownership interest 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.
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 January
2000, we sold the stock of our
13
<PAGE>
subsidiary, Western Gas Resources-California, Inc. for a net pre-tax gain of
approximately $5.4 million. We used the proceeds from these sales of $173
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 such capital is 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.
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.
We have effective shelf registration statements filed with the 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 six months ended June 30, 2000 are
summarized as follows (dollars in thousands):
<TABLE>
<S> <C>
Sources of funds:
Borrowings under revolving credit facility....................... $632,386
Proceeds from the dispositions of property and equipment......... 15,916
Net cash provided by operating activities........................ 15,745
Proceeds from exercise of common stock options................... 259
--------
Total sources of funds......................................... $664,306
========
Uses of funds:
Payments related to long-term debt (including debt issue costs).. $608,136
Capital expenditures............................................. 51,216
Dividends paid................................................... 8,439
Other............................................................ 5
--------
Total uses of funds............................................ $667,796
========
</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
9.5 Bcf at an average cost of $3.06 per Mcf at June 30, 2000 compared to 7.5 Bcf
at an average cost of $1.94 per Mcf at June 30, 1999 under storage contracts at
various third-party facilities. At June 30, 2000, we had hedging contracts in
place for anticipated sales of approximately 9.3 Bcf of stored gas at a weighted
average price of $3.33 per Mcf for the stored inventory.
We held NGLs in storage of 8,670 MGal, consisting primarily of propane and
normal butane, at an average cost of $.34 per gallon and 8,000 MGal at an
average cost of $.28 per gallon at June 30, 2000 and 1999, respectively, at
various third-
14
<PAGE>
party storage facilities. At June 30, 2000, we had no significant hedging
contracts in place for anticipated sales of stored NGLs.
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 June 30, 2000, we have expended $51.2 million, consisting of the
following: (i) $27.3 million related to gathering, processing and pipeline
assets, of which $3.4 million is for maintaining existing facilities and $9.8
million for acquisition of the remaining 50% in the Westana Gathering Company;
(ii) $20.0 million related to exploration and production activities; and (iii)
$3.9 million for miscellaneous items.
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 492,000 net
acres, in the basin. On approximately 18% of this acreage position, we have
established proven developed and undeveloped reserves. Our production is derived
primarily from wells drilled to depths of 400 to 1,200 feet. In 2000, we expect
to increase our drilling schedule to approximately 1,000 gross wells, or 470 net
wells, the majority of which are on locations with proven, undeveloped reserves.
During the first six months of 2000, we have drilled 478 gross wells or 225 net
wells. The average drilling, completion and gathering cost for our coal bed
methane wells is approximately $50,000 to $90,000 with reserves per well of
approximately 320 MMcf. As deeper wells are drilled, the average cost and
reserves per well are expected to increase. Production of coal bed methane from
the Powder River basin has been expanding, and approximately 214 MMcf/D of gas
volumes in the month of June 2000 were being produced by several operators in
the area, including 167 MMcf/D produced by our partner and us. We transport most
of the coal bed methane gas through our MIGC interstate pipeline or the Fort
Union gathering system for redelivery to gas markets in the Rocky Mountain and
Midwest regions of the United States.
Future drilling on federal acreage will be delayed until the completion of
an Environmental Impact Statement. This study is currently scheduled for
completion in February 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 Wyoming Department of
Environmental Quality has approved changes in the standards for surface water
discharge on some components of the water being discharged and continues to
evaluate changes in other standards. These additional modifications may be
approved within the third quarter of 2000. However, we can make no assurance
that the conditions under which permits are granted will not affect the level of
drilling or the timing of production.
Our capital budget in this area provides for expenditures of approximately
$50.0 million during 2000 of which $23.1 million was spent during the first six
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 $14.2 million for compression. In March
2000, we entered into a ten-year operating lease agreement for compression
equipment of which $10.3 million was available at June 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 in June 2000 it had throughput of approximately 174 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 also entered into a ten
year agreement for
15
<PAGE>
firm gathering services on 60 MMcf/D of capacity at $.14 per Mcf on Fort Union
beginning in December 1999.
Southwest Wyoming. The United States Geologic Survey estimates that the
Greater Green River basin contains over 120 Tcf of unrecovered natural gas
reserves. 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 166 MMcf/D in the second
quarter of 2000. Our capital budget in this area provides for expenditures of
approximately $12.3 million during 2000, of which $1.9 million was spent in the
first six months of 2000. This capital budget includes approximately $3.7
million for drilling costs and production equipment primarily in the Jonah Field
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 June
30, 2000, $70.5 million in total was outstanding on 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 June 30, 2000,
the interest rate payable on the facility was 8.2% 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 June 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
dividends under which approximately $37.1 million was available at June 30,
2000. Borrowings under the Master Shelf Agreement are guaranteed 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 is due in a single payment in December 2005. The 1995
Senior Notes are guaranteed and secured via a pledge of the stock of our
significant
16
<PAGE>
subsidiaries. This facility contains covenants similar to the Master Shelf
Agreement. In 1999 and in January 2000, we posted letters of credit for a total
of approximately $11.8 million for the benefit of the holders of the 1995 Senior
Notes.
We are currently paying an annual fee of not more than .65% on the amounts
outstanding on the Master Shelf Agreement and the 1995 Senior Notes. This fee
will continue until we have received an implied investment grade rating on our
senior secured debt. This fee is not assessed on the portion of the 1995 Senior
Notes for which letters of credit are posted.
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 June 30, 2000. Taking into account all the covenants contained in
these agreements, we had approximately $100 million of available borrowing
capacity at June 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.
17
<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 June 30, 2000, we had
hedged approximately 40%, 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 25%, 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.
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.
At June 30, 2000, we had $1.7 million of unrecognized gains in inventory that
will be recognized primarily during the third quarter of 2000. At June 30,
2000, we had unrecognized net losses of $925,000 related to financial
instruments that may be offset by corresponding unrecognized net gains from our
obligations to sell physical quantities of gas and NGLs.
18
<PAGE>
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 six months ended June 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 June 30, 2000, the net notional value of such contracts was approximately
$15.0 million in Canadian dollars, which approximates its fair market value.
19
<PAGE>
Principal Facilities
The following tables provide information concerning our principal facilities
at June 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 Six Months Ended
June 30, 2000
Gas Gas --------------------------------------------
Gathering Throughput Gas Gas NGL
Year Placed System Capacity Throughput Production Production
Plant Facilities (1) In 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 86 300 147 143 -
Gomez Treating........... 1971 385 280 111 101 -
Midkiff/Benedum.......... 1949 2,161 165 148 95 914
Mitchell Puckett
Gathering............... 1972 90 120 102 66 1
Louisiana
Toca (7)(8).............. 1958 - 160 129 123 105
Wyoming
Coal Bed Methane
Gathering............... 1990 444 223 198 183 -
Fort Union Gas Gathering
(15).................... 1999 106 450 75 75 -
Granger (7)(9)(10)....... 1987 478 235 140 117 373
Hilight Complex (7)...... 1969 626 80 19 14 58
Kitty/Amos Draw (7)...... 1969 314 17 13 8 48
Lincoln Road (10)........ 1988 149 50 20 19 23
Newcastle (7)............ 1981 146 5 3 2 17
Red Desert (7)........... 1979 111 42 15 13 26
Reno Junction (9)........ 1991 - - - - 92
Oklahoma
Arkoma................... 1985 74 12 11 10 -
Chaney Dell.............. 1966 2,051 130 52 42 183
Westana (14)............. 1981 864 45 68 56 121
New Mexico
San Juan River (6)....... 1955 140 60 25 19 37
Utah
Four Corners Gathering... 1988 104 15 2 3 13
----- ----- ----- ----- -----
Total................... 8,329 2,389 1,278 1,089 2,011
===== ===== ===== ===== ======
<CAPTION>
Average for the Six Months Ended
June 30, 2000
---------------------------
Pipeline Gas
Year Placed Transmission Capacity Throughput
Plant Facilities (1) In Service Miles(2) (MMcf/D)(2) (MMcf/D)(4)
-------------------------- ---------- ------------ ----------- -----------
<S> <C> <C> <C> <C>
MIGC (11)(13).............. 1970 245 130 182
MGTC (12).................. 1963 252 18 13
--- --- ---
Total.................... 497 148 195
=== === ===
</TABLE>
Footnotes on following page.
20
<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 June 30, 2000.
(3) Gas throughput capacity is as of June 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.
21
<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.
22
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
The following matters were voted on at our Annual Meeting of Stockholders held
on May 19, 2000:
Ward Sauvage, Joseph Reid and Lanny Outlaw were elected as Class Two
Directors to serve until their terms expire in 2003 and until their
successors have been elected. A total of 29,767,987, 29,357,694 and
29,788,008 shares, respectively, were voted for and 177,109, 587,402 and
157,088 shares, respectively, were withheld for Ward Sauvage, Joseph Reid and
Lanny Outlaw.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
27 Financial Data Schedule.
(b) Reports on Form 8-K:
None
23
<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: August 17, 2000 By: /s/ JOHN C. WALTER
-----------------------------
John C. Walter
Executive Vice-President
Date: August 17, 2000 By: /s/WILLIAM J. KRYSIAK
-----------------------------
William J. Krysiak
Vice President - Finance
(Principal Financial and Accounting Officer)
24
<PAGE>
August 17, 2000
Securities and Exchange Commission
450 5th Street, N.W.
Judiciary Plaza
Washington, D.C. 20549
Ladies and Gentlemen:
On behalf of Western Gas Resources, Inc. (the "Company"), please find enclosed
within this electronic submission via the EDGAR System, the Company's Form 10-
Q/A for the quarterly period ended June 30, 2000. The appropriate copies have
also been filed with the New York Stock Exchange.
Very truly yours,
/S/ CHARLES D. KING
-------------------
Charles D. King
Accounting Manager
Enclosures
25
