<PAGE>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
------------------------------------------------
Washington, D.C. 20549
----------------------
FORM 10-Q
(Mark One)
- ----------
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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
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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 May 1, 2000, there were 32,179,110 shares of the registrant's Common Stock
outstanding.
1
<PAGE>
Western Gas Resources, Inc.
Form 10-Q
Table of Contents
PART I - Financial Information Page
- ------------------------------ ----
Item 1. Financial Statements
Consolidated Balance Sheet - March 31, 2000 and
December 31, 1999............................................. 3
Consolidated Statement of Cash Flows - Three Months
Ended March 31, 2000 and 1999................................. 4
Consolidated Statement of Operations - Three Months
Ended March 31, 2000 and 1999................................. 5
Consolidated Statement of Changes in Stockholders'
Equity - Three Months Ended March 31, 2000.................... 6
Notes to Consolidated Financial Statements.................... 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................... 10
PART II - Other Information
- ---------------------------
Item 1. Legal Proceedings............................................. 20
Item 4. Submission of matters to a vote
of security holders........................................... 21
Item 6. Exhibits and Reports on Form 8-K.............................. 21
Signatures............................................................... 22
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>
March 31, December 31,
2000 1999
---------- ----------
ASSETS (unaudited)
------
<S> <C> <C>
Current assets:
Cash and cash equivalents..................................................... $ 3,904 $ 14,062
Trade accounts receivable, net................................................ 230,598 196,739
Product inventory............................................................. 12,466 35,228
Parts inventory............................................................... 9,252 10,318
Assets held for sale.......................................................... - 7,237
Other......................................................................... 1,164 9,571
---------- ----------
Total current assets........................................................ 257,384 273,155
---------- ----------
Property and equipment:
Gas gathering, processing, storage and transmission........................... 853,854 808,274
Oil and gas properties and equipment.......................................... 114,499 104,137
Construction in progress...................................................... 38,069 39,987
---------- ----------
1,006,422 952,398
Accumulated depreciation, depletion and amortization........................... (272,011) (260,081)
---------- ----------
Total property and equipment, net........................................... 734,411 692,317
---------- ----------
Other assets:
Gas purchase contracts (net of accumulated amortization of $31,795 and
$31,273, respectively)...................................................... 36,361 36,883
Other......................................................................... 18,081 47,131
---------- ----------
Total other assets.......................................................... 54,442 84,014
---------- ----------
Total assets................................................................... $1,046,237 $1,049,486
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
Current liabilities:
Accounts payable.............................................................. $ 238,306 $ 240,235
Accrued expenses.............................................................. 26,100 41,075
Dividends payable............................................................. 4,219 4,218
---------- ----------
Total current liabilities................................................... 268,625 285,528
Long-term debt................................................................. 376,314 378,250
Deferred income taxes payable.................................................. 43,406 35,965
---------- ----------
Total liabilities........................................................... 688,345 699,743
---------- ----------
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; 32,177,277 and
32,186,747 shares issued, respectively...................................... 3,221 3,220
Treasury stock, at cost, 25,016 shares in treasury............................ (788) (788)
Additional paid-in capital.................................................... 397,592 397,522
Accumulated deficit........................................................... (42,277) (51,064)
Accumulated other comprehensive income........................................ 612 1,321
Notes receivable from key employees secured by common stock................... (884) (884)
---------- ----------
Total stockholders' equity.................................................. 357,892 349,743
---------- ----------
Total liabilities and stockholders' equity..................................... $1,046,237 $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>
Three Months Ended
March 31,
---------------------
2000 1999
--------- ---------
<S> <C> <C>
Reconciliation of net income (loss) to net cash provided by (used in) operating activities:
Net income (loss)............................................................................ $ 13,006 $ (2,176)
Add income items that do not affect cash:
Depreciation, depletion and amortization.................................................... 13,309 13,558
Gain on the sale of property and equipment.................................................. (5,299) (145)
Deferred income taxes....................................................................... 7,441 (1,373)
Other non-cash items, net................................................................... 929 (371)
--------- ---------
29,386 9,493
--------- ---------
Adjustments to working capital to arrive at net cash provided by (used in)
operating activities:
Increase (decrease) in trade accounts receivable............................................ (31,234) 48,405
Decrease in product inventory.............................................................. 22,762 24,093
Decrease in parts inventory................................................................ 1,066 240
Decrease in other current assets........................................................... 7,937 712
Decrease in other assets and liabilities, net............................................... 37 67
Decrease in accounts payable................................................................ (5,614) (64,465)
Decrease in accrued expenses................................................................ (14,975) (5,884)
--------- ---------
Net cash provided by (used in) operating activities.......................................... 9,365 12,661
--------- ---------
Cash flows from investing activities:
Purchases of property and equipment......................................................... (28,498) (20,843)
Proceeds from the dispositions of property and equipment.................................... 15,057 100
Contributions to equity investees........................................................... - (891)
--------- ---------
Net cash used in investing activities........................................................ (13,441) (21,634)
--------- ---------
Cash flows from financing activities:
Proceeds from exercise of common stock options.............................................. 71 -
Debt issue costs paid....................................................................... - (243)
Payments on revolving credit facility....................................................... (293,286) (794,650)
Borrowings under revolving credit facility.................................................. 291,350 864,951
Payments on notes........................................................................... - (48,571)
Dividends paid.............................................................................. (4,217) (4,217)
--------- ---------
Net cash provided by financing activities.................................................... (6,082) 17,270
--------- ---------
Net increase (decrease) in cash and cash equivalents......................................... (10,158) 8,297
Cash and cash equivalents at beginning of period............................................. 14,062 4,400
--------- ---------
Cash and cash equivalents at end of period................................................... $ 3,904 $ 12,697
========= =========
</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
March 31,
-------------------------
2000 1999
----------- -----------
Revenues:
<S> <C> <C>
Sale of gas........................................................... $ 413,816 $ 350,841
Sale of natural gas liquids........................................... 135,388 63,648
Processing, transportation and storage revenue........................ 13,885 11,073
Other, net............................................................ 2,063 3,798
----------- -----------
Total revenues....................................................... 565,152 429,360
----------- -----------
Costs and expenses:
Product purchases..................................................... 501,143 382,825
Plant operating expense............................................... 15,262 18,005
Oil and gas exploration and production expense........................ 4,146 1,858
Depreciation, depletion and amortization.............................. 13,309 13,558
Gain on sale of assets................................................ (5,299) (145)
Selling and administrative expense.................................... 7,389 7,815
Interest expense...................................................... 8,218 8,743
----------- -----------
Total costs and expenses............................................. 544,168 432,659
----------- -----------
Income (loss) before taxes............................................. 20,984 (3,299)
Provision for (benefit from) income taxes:
Current............................................................... 537 250
Deferred.............................................................. 7,441 (1,373)
----------- -----------
7,978 (1,123)
----------- -----------
Net income (loss)...................................................... 13,006 (2,176)
Preferred stock requirements........................................... (2,610) (2,610)
----------- -----------
Income (loss) attributable to common stock............................. $ 10,396 $ (4,786)
=========== ===========
Earnings (loss) per share of common stock.............................. $ .32 $ (.15)
=========== ===========
Weighted average shares of common stock outstanding.................... 32,165,868 32,147,993
=========== ===========
Earnings (loss) per share of common stock-assuming dilution............ $ .32 $ (.15)
=========== ===========
Weighted average shares of common stock outstanding-assuming dilution.. 32,459,209 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 Common
Stock Stock Stock in Treasury Stock Stock Stock
------------ ------------- ------------ ------------- ------------ ------------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1999............................. 1,400,000 2,760,000 32,161,731 25,016 $ 140 $ 276 $3,220
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...... - - 15,546 - - - 1
Loans forgiven.................... - - - - - - -
------------ ------------- ------------ ------------- ------------ ------------- ---------
Balance at March 31, 2000......... 1,400,000 2,760,000 32,177,277 25,016 $ 140 $ 276 $3,221
============ ============= ============ ============= ============ ============= =========
Accumulated
Other Notes Total
Additional Compre- Receivable Stock-
Treasury Paid-in Accumulated hensive from Key holders'
Stock Capital Deficit Income Employees Equity
---------- ----------- ----------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1999.............................$ (788) $ 397,522 $ (51,064) $ 1,321 $ (884) $ 349,743
Comprehensive Income:
Net Income....................... - - 13,006 - - 13,006
Foreign Currency
Translation..................... - - - (709) - (709)
----------
Comprehensive Income 12,297
----------
Dividends:
Dividends declared on common
stock............................ - - (1,609) - - (1,609)
Dividends declared on $2.28
cumulative preferred stock....... - - (799) - - (799)
Dividends declared on $2.625
cumulative convertible preferred
stock............................ - - (1,811) - - (1,811)
Stock options exercised...... - 70 - - - 71
Loans forgiven.................... - - - - - -
---------- ----------- ----------- ----------- ----------- ----------
Balance at March 31, 2000.........$ (788) $ 397,592 $ (42,277) $ 612 $ (884) $ 357,892
========== =========== =========== =========== =========== ==========
</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 March 31, 2000 and for the
three month periods ended March 31, 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 months ended March 31, 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 for each of the
three month periods ended March 31, 2000 and 1999. Common stock options, which
are potential common shares, were anti-dilutive for the period ended March 31,
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
March 31, 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 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 Western Gathering
Company has been reclassed from Other assets to Property and equipment.
SUPPLEMENTARY CASH FLOW INFORMATION
Interest paid was $4.7 million and $9.7 million for the three months ended
March 31, 2000 and 1999, respectively.
No income taxes were paid during the three months ended March 31, 2000 or
the three months ended March 31, 1999.
7
<PAGE>
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
quarter ended March 31, 1999. 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 quarter ended March 31, 1999. Also included in this segment are our
Canadian marketing operations (which are immaterial for separate presentation).
The Marketing segment also includes gains and losses associated with our equity
gas and NGL hedging program of $(3.1) million and $274,000 for the quarters
ended March 31, 2000 and March 31, 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
quarters ended March 31, 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 March 31, 2000
Revenues from unaffiliated customers...... $ 11,406 $ 986 $551,322 $ 2,378 $ 26 $ (8) $566,110
Interest income........................... 33 2 24 - 5,838 (5,668) 229
Other, net................................ (20) - (2,203) - 1,036 - (1,187)
Intersegment sales........................ 134,342 10,304 26,333 4,404 4 (175,387) -
-------- -------- -------- ------- ------- --------- --------
Total revenues............................ 145,761 11,292 575,476 6,782 6,904 (181,063) 565,152
-------- -------- -------- ------- ------- --------- --------
Product purchases......................... 103,008 504 572,687 - (25) (175,031) 501,143
Plant operating expense................... 13,062 17 - 2,268 256 (341) 15,262
Oil and gas exploration
and production expense................... - 4,146 - - - - 4,146
-------- -------- -------- ------- ------- --------- --------
Operating profit.......................... $ 29,691 $ 6,625 $ 2,789 $ 4,514 $ 6,673 $ (5,691) $ 44,601
======== ======== ======== ======= ======= ========= ========
Depreciation, depletion and amortization.. 8,571 2,889 40 424 1,385 - 13,309
Interest expense.......................... 8,218
Gain on sale of assets.................... (5,299)
Selling and administrative expense........ 7,389
--------
Income (loss) before income taxes......... $ 20,984
========
Identifiable assets....................... $547,611 $101,802 $ 75 $47,213 $37,710 $ - $734,411
======== ======== ======== ======= ======= ========= ========
</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>
Quarter ended March 31, 1999
Revenues from unaffiliated customers...... $ 11,280 $ 404 $408,621 $ 1,799 $ 538 $- $422,642
Interest income........................... 1 151 22 - 7,033 (6,993) 214
Other, net................................ 87 - 5,291 354 772 - 6,504
Intersegment sales........................ 76,588 4,999 17,989 4,099 14 (103,689) -
-------- -------- -------- ------- ------- --------- --------
Total revenues............................ 87,956 5,554 431,923 6,252 8,357 (110,682) 429,360
-------- -------- -------- ------- ------- --------- --------
Product purchases......................... 59,076 455 416,612 1,460 - (94,778) 382,825
Plant operating expense................... 14,367 12 11,699 1,171 483 (9,727) 18,005
Oil and gas exploration
and production expense................... 135 1,768 (45) - - - 1,858
-------- -------- -------- ------- ------- --------- --------
Operating profit.......................... $ 14,378 $ 3,319 $ 3,657 $ 3,621 $ 7,894 $ (6,177) $ 26,672
======== ======== ======== ======= ======= ========= ========
Depreciation, depletion and amortization.. 10,237 1,101 849 259 1,112 - 13,558
Interest expense.......................... 8,743
Gain on sale of assets.................... (145)
Selling and administrative expense........ 7,815
--------
Income (loss) before income taxes......... $ (3,299)
========
Identifiable assets....................... $572,258 $ 79,878 $111,980 $46,792 $41,269 $ - $852,177
======== ======== ======== ======= ======= ========= ========
</TABLE>
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In June 1998, the Financial Accounting Standards Board 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, we
will be required to recognize 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.
LEGAL PROCEEDINGS
Reference is made to "Part II - Other Information - Item 1. Legal
Proceedings," of this Form 10-Q.
9
<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
months ended March 31, 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 months ended March 31, 2000 compared to the three months ended March 31,
1999
(Dollars in thousands, except per share amounts and operating data).
<TABLE>
<CAPTION>
Three Months Ended
March 31,
------------------ Percent
2000 1999 Change
-------- -------- -------
<S> <C> <C> <C>
Financial results:
Revenues............................................. $565,152 $429,360 32
Gross profit......................................... 36,591 13,259 176
Net income (loss).................................... 13,006 (2,176) -
Earnings (loss) per share of common stock............ .32 (.15) -
Earnings (loss) per share of common stock-diluted.... .32 (.15) -
Net cash provided by operating activities............ $ 9,365 $ 12,661 (26)
Operating data:
Average gas sales (MMcf/D)........................... 1,800 2,135 (16)
Average NGL sales (MGal/D)........................... 3,125 3,030 3
Average gas prices ($/Mcf)........................... $ 2.52 $ 1.82 38
Average NGL prices ($/Gal)........................... $ .48 $ .23 109
</TABLE>
Net income increased $15.1 million for the quarter ended March 31, 2000
compared to 1999. The increase in net income for the first quarter was
primarily due to significantly higher prices in 2000 compared to the prior year
and a pre-tax gain of $5.4 million recognized on the sale of the stock of our
wholly-owned subsidiary, Western Gas Resources-California.
Revenues from the sale of gas increased approximately $63.0 million for the
three months ended March 31, 2000 compared to the same period in 1999. This
increase was primarily due to an improvement in product prices. Average gas
prices realized by us increased $.70 per Mcf to $2.52 per Mcf for the three
months ended March 31, 2000 compared to the same period in 1999. Included in
the realized gas price were approximately $1.2 million of losses recognized for
the three months ended March 31, 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 more limited extent in 2001.
See further discussion in " - Liquidity and Capital Resources - Risk Management
Activities." The increase in prices was partially offset by a decrease in
sales volume. Average gas sales volumes decreased 335 MMcf per day to 1,800
MMcf per day for the three months ended March 31, 2000 compared to the same
period in 1999. This reduction was largely due to a decrease in the sale of gas
purchased from third parties.
Revenues from the sale of NGLs increased approximately $71.7 million for the
three months ended March 31, 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 $.25 per gallon to $.48 per gallon
for the three months ended March 31, 2000 compared to the same period in 1999.
Included in the realized NGL price were approximately $1.9 million of losses
recognized for the three months ended March 31, 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 95
10
<PAGE>
MGal per day to 3,125 MGal per day for the three months ended March 31, 2000
compared to the same period in 1999. This increase in NGL volume is primarily
due to favorable ethane extraction economics in 2000. Ethane is extracted by us
from the residue gas when the price for ethane exceeds its value as a gas. As a
result of the ethane price, we extracted and sold 157 MGal per day of ethane at
our Granger facility in the first quarter of 2000. In the first quarter of 1999,
we did not extract any ethane at this facility. Based on current prices, we
expect to continue recovery ethane at this facility at least through the second
quarter of 2000.
Other net revenue decreased approximately $1.7 million for the three months
ended March 31, 2000 compared to the same period in 1999. This decrease was in
part due to operating fees received by us in the first quarter of 1999 for our
contract operation of the Edgewood facility following the sale of the plant.
The increase in product purchases in the first quarter of 2000 compared to
the same period in 1999 of $118.3 million to $501.1 million was primarily due to
an increase in commodity prices. Overall, combined product purchases as a
percentage of sales of all products was 91% for the three months ended March 31,
2000 compared to 92% for the same period in 1999. The reduction in percentage
was primarily due to sales of gas produced from our coal bed methane wells in
the Powder River Basin located in NE Wyoming. These sales have no corresponding
product purchases. Margins on third-party sales of natural gas remained constant
at $.02 per Mcf in both the first quarter of 2000 and 1999, and margins on
third-party sales of NGLs increased to $.009 per gallon in the first quarter of
2000 compared to $.001 per gallon in the first quarter of 1999. We expect the
margin on third party sales of NGLs to decrease somewhat in the second quarter
of 2000.
Plant operating expense and Selling and administrative expense decreased a
total of $4.7 million primarily as a result of the sale in 1999 of our Katy
Storage facility, our Giddings gathering system, our MiVida treating facility
and our Black Lake facility.
Oil and gas exploration and production expense increased $2.2 million as a
result of our increasing operations in the Powder River basin coal bed methane
developments.
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 Western 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 profitability 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 continually 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
11
<PAGE>
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 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 and complete our current capital
expenditure program. 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.
Historically, 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. In recent years, the
industry experienced a reduction in drilling activity, primarily in basins that
produce oil and casinghead gas, from levels that existed in prior years.
However, 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 the Powder River basin and southwest Wyoming.
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.
12
<PAGE>
Our sources and uses of funds for the quarter ended March 31, 2000 are
summarized as follows (dollars in thousands):
<TABLE>
<CAPTION>
Sources of funds:
<S> <C>
Borrowings under revolving credit facility....................... $291,350
Proceeds from the dispositions of property and equipment......... 15,057
Net cash provided by operating activities........................ 9,365
Proceeds from exercise of common stock options................... 71
Other............................................................ -
--------
Total sources of funds......................................... $315,843
========
Uses of funds:
Payments related to long-term debt (including debt issue costs).. $293,286
Capital expenditures............................................. 28,498
Dividends paid................................................... 4,217
--------
Total uses of funds............................................ $326,001
========
</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
4.7 Bcf at an average cost of $2.21 per Mcf at March 31, 2000 compared to 11.4
Bcf at an average cost of $1.70 per Mcf at March 31, 1999 under storage
contracts at various third-party facilities. At March 31, 2000, we had hedging
contracts in place for anticipated sales of approximately 4.7 Bcf of stored gas
at a weighted average price of $2.62 per Mcf for the stored inventory.
We held NGLs in storage of 4,700 MGal, consisting primarily of propane and
normal butane, at an average cost of $.30 per gallon and 6,900 MGal at an
average cost of $.24 per gallon at March 31, 2000 and 1999, respectively, at
various third-party storage facilities. At March 31, 2000, we had no significant
hedging contracts in place for anticipated sales of stored NGLs.
Capital Investment Program
We expect capital expenditures related to existing operations to be
approximately $89.7 million during 2000, consisting of the following: (i)
approximately $49.7 million related to gathering, processing and pipeline
assets, of which $8.0 million is for maintaining existing facilities and $9.8
million for acquisition of the remaining 50% interest in the Westana Gathering
Company; (ii) approximately $38.0 million related to exploration and production
activities; and (iii) approximately $2.0 million for miscellaneous items.
Overall, capital expenditures in the Powder River basin coal bed methane
development and in southwest Wyoming operations represent 50% and 11%,
respectively, of the total 2000 budget.
As of March 31, 2000, we have expended $28.5 million, consisting of the
following: (i) $17.6 million related to gathering, processing and pipeline
assets, of which $1.7 million is for maintaining existing facilities and $9.8
million for acquisition of the remaining 50% in the Westana Gathering Company;
(ii) $8.8 million related to exploration and production activities; and (iii)
$2.0 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 487,000 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 800 gross wells, or
376 net wells, the majority of which are on locations with proven, undeveloped
reserves. During the first quarter of 2000, we have drilled 196 gross wells or
92 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 187MMcf/D of gas
volumes in the first quarter of 2000 were being produced by several operators in
the area, including 140 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.
13
<PAGE>
Future drilling on federal acreage will be delayed until the completion of
an Environmental Impact Statement. This study is expected to take approximately
two years after its commencement. 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 discharge and continues to evaluate
changes in other standards. These additional modifications may be approved
within the second 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
$45.0 million during 2000 of which $10.0 million was spent during the first
quarter. This capital budget includes approximately $34.3 million for drilling
costs for our interest in approximately 800 wells, production equipment and
undeveloped acreage and $10.7 million for compression. In March 2000, we entered
into a ten-year operating lease agreement with credit capacity of $15 million of
which $10.3 million was available at March 31, 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.
In December 1998, we joined with other industry partners to form Fort Union
Gas Gathering, L.L.C., to build 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 own an approximate 13% equity interest in Fort Union and are the
construction manager and field operator. The new gathering header has a capacity
of approximately 450 MMcf/D of natural gas with expansion capability and in
March 2000 it had throughput of approximately 117 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. The gathering header and treating system went into
service in September 1999 and was project-financed, requiring a cash investment
by us of approximately $900,000. In conjunction with the project financing, we
also entered into a ten year agreement for 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 155 MMcf/D in the first
quarter of 2000. Our capital budget in this area provides for expenditures of
approximately $9.7 million during 2000, of which $1.1 million was spent in the
first quarter. This capital budget includes approximately $3.4 million for
drilling costs and production equipment and approximately $6.3 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 March
31, 2000, $44.4 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 March 31,
2000, the interest rate payable on the facility was 7.5% 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 March 31, 2000 are as indicated in the
following table (dollars in thousands):
14
<PAGE>
<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 $31.2 million was available at March
31, 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 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 March 31,2000. Taking into account all the covenants contained in
these agreements, we had approximately $117 million of available borrowing
capacity at March 31, 2000. In 1999, we amended our various financing
facilities providing for financial flexibility and covenant modifications and
issued the Subordinated Notes. These amendments were needed given the depressed
commodity pricing experienced in the industry in general at that time and the
disappointing results at our Bethel Treating facility. We can provide no
assurance that further amendments or waivers can be obtained in the future, if
necessary, or that the terms would be favorable to us. To 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.
15
<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 establishes a minimum price while allowing varying levels
of market participation above the minimum. As of March 31, 2000, we had hedged
approximately 40%, or 30,000 MMBtu/day, of our anticipated equity gas for 2000
at a weighted average NYMEX equivalent minimum price of $2.22 per MMBtu and an
additional 29%, 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.
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. Finally, we have hedged approximately 27%, or 345,000 Bbls of our
estimated first quarter production of equity NGLs at a weighted average Mt.
Belvieu price of $0.52 per gallon.
At March 31, 2000, we had $1.2 million of unrecognized gains in inventory
that will be recognized primarily during the third quarter of 2000. At March 31,
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.
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
16
<PAGE>
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 ended March 31, 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 March 31, 2000, the net notional value of such contracts was approximately
$3.8 million in Canadian dollars, which approximates its fair market value.
Year 2000
Overall, we did not experience any significant disruption of our operations
or computer systems as a result of the Year 2000 issue. Prior to December 31,
1999, we completed a comprehensive review of our computer systems to identify
the systems that could be affected by the Year 2000 issue and developed and
implemented a plan to mitigate the risk of any problems. Our remediation plan
included: (i) creating a Year 2000 awareness program to educate employees; (ii)
compiling an inventory of all systems; (iii) developing system test plans as
appropriate; (iv) completing the testing and remediation as required for both
information and non-information technology systems; and (v) developing
contingency plans to minimize the impact of a Year 2000 related failure caused
either internally or externally. Additionally, we surveyed our business
counterparties periodically regarding their Year 2000 conversion and contingency
plans. In total, we spent approximately $1.1 million for remediation purposes,
which primarily consisted of purchasing hardware and software upgrades. We also
incurred internal staff costs and other expenses, which were immaterial.
17
<PAGE>
Principal Facilities
The following tables provide information concerning our principal facilities
at March 31, 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 Quarter Ended
Gas Gas March 31, 2000
-----------------------------------------------
Gathering Throughput Gas Gas NGL
Year System Capacity Throughput Production Production
Placed
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 86 350 136 131 -
Gomez Treating........... 1971 385 280 113 103 -
Midkiff/Benedum.......... 1955 2,159 165 144 94 895
Mitchell Puckett
Gathering............... 1972 90 120 109 70 1
Louisiana
Toca (7)(8).............. 1958 - 160 130 124 105
Wyoming
Coal Bed Methane
Gathering............... 1990 444 223 187 165 -
Fort Union Gas
Gathering(14)........... 1999 106 450 14 14
Granger (7)(9)(10)....... 1987 476 235 134 113 366
113 366
Hilight Complex (7)...... 1969 626 80 20 14 58
Kitty/Amos Draw (7)...... 1969 313 17 12 8 47
Lincoln Road (10)........ 1988 149 50 21 20 23
Newcastle (7)............ 1981 146 5 2 2 16
Red Desert (7)........... 1979 111 42 15 13 27
Reno Junction (9)........ 1991 - - - - 51
Oklahoma
Arkoma................... 1985 72 8 8 10 -
Chaney Dell.............. 1966 2,050 180 53 43 184
Westana (15)............. 1986 859 45 69 58 123
New Mexico
San Juan River (6)....... 1955 140 60 23 17 35
Utah
Four Corners Gathering... 1988 104 15 3 4 14
--------------- ------------ --------------- -------------- --------------
Total................... 8,316 2,485 1,193 1,003 1,945
=============== ============ =============== ============== ==============
Average for the Quarter Ended
March 31, 2000
-----------------------------
Pipeline Gas
Year Placed Transmission Capacity Throughput
Transmission Facilities (1) In Service Miles(2) (MMcf/D)(2) (MMcf/D)(4)
- --------------------------- ----------- --------------- ------------- --------------
<S> <C> <C> <C> <C>
MIGC (11)(13).............. 1970 245 130 185
MGTC (12).................. 1963 252 18 16
--------------- ------------- --------------
Total.................... 497 148 201
=============== ============= ==============
</TABLE>
Footnotes on following page.
18
<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 March 31, 2000.
(3) Gas throughput capacity is as of March 31, 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) This gathering pipeline and treater became operational during September
1999.
(15) We acquired the remaining 50% interest in Westana Gathering Company in
February 2000.
19
<PAGE>
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
-----------------
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.
McMurry Oil Company and certain other producers (collectively, "McMurry")
filed suit against TBI Exploration, Inc. ("TBI"), Mountain Gas Resources, Inc.,
our wholly-owned subsidiary ("Mountain Gas"), and Wildhorse Energy Partners, LLC
("Wildhorse"). The central dispute in this case concerned the ownership, nature
and extent of a call on certain gas and the rights to match offers for gathering
and/or purchasing gas (collectively the "Preferential Rights"). In early 1999,
McMurry, TBI and Wildhorse settled their claims and crossclaims and as a result
TBI and Wildhorse were dismissed from the case. In February 2000, the remaining
parties reached a confidential settlement on all issues for substantially less
than the amount claimed. Mountain Gas' share of the settlement is reflected in
our year-end 1999 results of operations. Mountain Gas has not admitted any
liability or fault in the settlement. Mountain Gas is seeking reimbursement from
its joint venture partner for their 50% of the settlement amount which was paid
in full by Mountain Gas.
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.
Berco Resources, Inc. is a producer in the Temple/Tioga Area in North Dakota.
Berco alleged that Amerada Hess engaged in unlawful monopolization under Section
2 of the Sherman Act and Section 7 of the Clayton Act by acquiring natural gas
gathering and producing facilities owned by us. Berco also alleged that we,
along with Amerada Hess, had conspired, through the purchase and sale of our
facilities in the Temple/Tioga Area, to create a monopoly affecting an
appreciable amount of interstate commerce in violation of Sections 1 and 2 of
the Sherman Act. In February 2000, we and Berco reached a confidential
settlement 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
pursuant to the indemnification provisions of our agreement for the sale of the
Temple facilities.
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.
20
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
None.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
10.23 Third Amendment dated April 27, 2000 to Loan Agreement dated April
29, 1999 by and among Western Gas Resources, Inc. and NationsBank,
as agent, and the Lenders.
27 Financial Data Schedule.
(b) Reports on Form 8-K:
A report on Form 8-K was filed on January 2, 2000 announcing the sale of
our interest in the Black Lake facility and related production in
Louisiana, which is incorporated herein by reference.
A report on Form 8-K was filed on January 21, 2000 to notify our
stockholders of the disposition of the Black Lake facility and related
production, which is incorporated herein by reference.
A report on Form 8-K was filed on February 22, 2000 announcing the stock
sale of our wholly-owned subsidiary Western Gas Resources-California, Inc.,
and a report on the 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 is incorporated herein by reference.
21
<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: May 11, 2000 By: /s/ LANNY F. OUTLAW
-------------------
Lanny F. Outlaw
Chief Executive Officer and President
Date: May 11, 2000 By: /s/ WILLIAM J. KRYSIAK
----------------------
William J. Krysiak
Vice President - Finance
(Principal Financial and Accounting
Officer)
22
<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: May 11, 2000 By:
-------------------------------
Lanny F. Outlaw
Chief Executive Officer and President
Date: May 11, 2000 By:
-------------------------------
William J. Krysiak
Vice President - Finance
(Principal Financial and Accounting
Officer)
23
<PAGE>
THIRD AMENDMENT TO LOAN AGREEMENT
---------------------------------
THIS THIRD AMENDMENT TO LOAN AGREEMENT (herein called this "Amendment") is
made as of the 27th day of April, 2000 by and among Western Gas Resources, Inc.
("Borrower"), and Bank of America, N.A. ("Agent"), and the Lenders under the
Loan Agreement referred to below.
W I T N E S S E T H:
WHEREAS, Borrower, Agent, and Lenders have entered into that certain Loan
Agreement dated as of April 29, 1999 (as amended, restated, or supplemented to
the date hereof, the "Original Agreement"), for the purposes and consideration
therein expressed, pursuant to which Lenders made and became obligated to make
loans to Borrower as therein provided;
WHEREAS, Borrower, Agent, and Lenders desire to amend the Original
Agreement for the purposes described herein;
NOW, THEREFORE, in consideration of the premises and the mutual covenants
and agreements contained herein and in the Original Agreement, in consideration
of the loans which may hereafter be made by Lenders to Borrower, and for other
good and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereto do hereby agree as follows:
ARTICLE I.
Definitions and References
--------------------------
1.I. Defined Terms. Unless the context otherwise requires or unless
-------------
otherwise expressly defined herein, the terms defined in the Original
Agreement shall have the same meanings whenever used in this
Amendment. As used herein, the term "Loan Agreement" means the
Original Agreement as amended by this Amendment.
ARTICLE II.
Amendment
---------
2.I. Definitions. The definition of "Tranche A Maturity Date" in
-----------
Section 1.1 of the Loan Agreement is hereby amended in its entirety to
read as follows:
"'Tranche A Maturity Date' means April 26, 2001."
-----------------------
<PAGE>
ARTICLE III.
Conditions of Effectiveness
---------------------------
3.I. Effective Date. This Amendment shall become effective as of the
--------------
date first above written when, and only when, Agent shall have received all of
-------------------
the following:
(1) This Amendment, duly authorized, executed and delivered by
Borrower, Agent, and each Lender, and in form and substance satisfactory to
Agent.
(2) A certificate of a duly authorized officer of Borrower dated
the date of this Amendment certifying: (i) that all of the representations
and warranties set forth in Article IV hereof are true and correct at and
as of the time of such effectiveness; and (ii) as to such other corporate
matters as Agent shall deem necessary.
(c) A written legal opinion of in-house counsel for Borrower,
dated as of the date of this Amendment, addressed to Agent, to the effect
that this Amendment has been duly authorized, executed and delivered by
Borrower and that the Loan Agreement and each other Loan Document, as
affected hereby, to which any Restricted Person is a party constitutes the
legal, valid and binding obligation of each such Restricted Person,
enforceable in accordance with their terms (subject, as to enforcement of
remedies, to applicable bankruptcy, reorganization, insolvency and similar
laws and to general principles of equity) and such other matters of Agent
may require.
(d) Payment of all fees and expenses owing to Agent and Lenders in
connection with the Loan Agreement and payment of fees and disbursements of
Thompson & Knight L.L.P. relating to this Amendment and the Loan Agreement
as provided in the Loan Agreement.
(e) Agent shall have additionally received such other documents as
Agent may reasonably request.
ARTICLE IV.
Representations and Warranties
------------------------------
4.I. Representations and Warranties of Borrower. In order to induce
------------------------------------------
each Lender to enter into this Amendment, Borrower represents and warrants to
each Lender that:
(1) The representations and warranties contained in Article V of
the Original Agreement are true and correct at and as of the time of the
effectiveness hereof (except as such representations and warranties have
been modified by the transactions contemplated herein).
(2) Borrower is duly authorized to execute and deliver this
Amendment and Borrower is and will continue to be duly authorized to borrow
monies and to perform its
2
<PAGE>
obligations under the Loan Agreement. Borrower has duly taken all corporate
action necessary to authorize the execution and delivery of this Amendment.
(3) The execution and delivery by Borrower of this Amendment, the
performance of its obligations hereunder and the consummation of the
transactions contemplated hereby do not and will not conflict with any
provision of law, statute, rule or regulation or of the certificate of
incorporation and bylaws of Borrower or of any material agreement,
judgment, license, order or permit applicable to or binding upon Borrower
or result in the creation of any lien, charge or encumbrance upon any
assets or properties of Borrower. Except for those which have been
obtained, no consent, approval, authorization or order of any court or
governmental authority or third party is required in connection with the
execution and delivery by Borrower of this Amendment.
(4) When duly executed and delivered, this Amendment, the Loan
Agreement, and each other Loan Document, as affected hereby, will be a
legal and binding obligation of each Restricted Person that is a party
hereto and thereto enforceable against such Restricted Person in accordance
with its terms, except as limited by bankruptcy, insolvency or similar laws
of general application relating to the enforcement of creditors' rights and
by equitable principles of general application.
(5) The audited Consolidated financial statements of Borrower
dated as of December 31, 1999 fairly present the Consolidated financial
position at such date of Borrower and the Consolidated statement of
operations and the changes in Consolidated financial position for the
periods ending on such date for Borrower. Copies of such financial
statements have heretofore been delivered to Agent. Since December 31,
1999, no material adverse change has occurred in the financial condition or
business or in the Consolidated financial condition or business of
Borrower.
ARTICLE V.
Miscellaneous
-------------
5.I. Ratification of Agreements. The Original Agreement as hereby
--------------------------
amended is hereby ratified and confirmed in all respects. Any reference to the
Loan Agreement in any Loan Document shall be deemed to be a reference to the
Original Agreement as hereby amended. The Loan Documents, as they may be
amended or affected by this Amendment, are hereby ratified and confirmed in all
respects. The execution, delivery and effectiveness of this Amendment shall
not, except as expressly provided herein, operate as a waiver of any right,
power or remedy of Lenders under the Loan Agreement, the Notes, or any other
Loan Document nor constitute a waiver of any provision of the Loan Agreement,
the Notes, or any other Loan Document.
5.II. Survival of Agreements. All representations, warranties,
----------------------
covenants and agreements of Borrower herein shall survive the execution and
delivery of this Amendment and the performance hereof, including without
limitation the making or granting of the Loans, and shall further survive until
all of the Obligations are paid in full. All statements and agreements
contained in any certificate or instrument delivered by Borrower hereunder or
under the Loan
3
<PAGE>
Agreement to any Lender shall be deemed to constitute representations and
warranties by, and/or agreements and covenants of, Borrower under this Amendment
and under the Loan Agreement.
5.III. Loan Documents. This Amendment is a Loan Document, and all
--------------
provisions in the Loan Agreement pertaining to Loan Documents apply hereto.
5.IV. Governing Law. This Amendment shall be governed by and construed
-------------
in accordance the laws of the State of Texas and any applicable laws of the
United States of America in all respects, including construction, validity and
performance.
5.V. Counterparts. This Amendment may be separately executed in
------------
counterparts and by the different parties hereto in separate counterparts, each
of which when so executed shall be deemed to constitute one and the same
Amendment.
THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT
BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR,
CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO
UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.
4
<PAGE>
IN WITNESS WHEREOF, this Amendment is executed as of the date first above
written.
WESTERN GAS RESOURCES, INC.
By:_____________________________________
Name:
Title:
5
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