<PAGE>
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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 SEPTEMBER 30, 1999 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
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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 November 1, 1999, there were 32,152,731 shares of the registrant"s Common
Stock outstanding.
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1
<PAGE>
Western Gas Resources, Inc.
Form 10-Q
Table of Contents
PART I - Financial Information Page
- ------------------------------ ----
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheet - September 30, 1999 and December
31, 1998........................................................ 3
Consolidated Statement of Cash Flows - Nine months ended
September 30, 1999 and 1998..................................... 4
Consolidated Statement of Operations - Three and nine months
ended September 30, 1999 and 1998............................... 5
Consolidated Statement of Changes in Stockholders' Equity -
Nine months ended September 30, 1999............................ 6
Notes to Consolidated Financial Statements...................... 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................... 12
Item 3. Quantitative and Qualitative Disclosures about Market Risk...... 19
PART II - Other Information
- ---------------------------
Item 1. Legal Proceedings............................................... 23
Item 4. Submission of Matters to a Vote of Security Holders............. 24
Item 6. Exhibits and Reports on Form 8-K................................ 24
Signatures................................................................. 25
2
<PAGE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
--------------------
WESTERN GAS RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(Dollars in thousands, except share data)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
-------------- -------------
ASSETS (Unaudited)
------
<S> <C> <C>
Current assets:
Cash and cash equivalents.................................................... $ 5,472 $ 4,400
Trade accounts receivable, net............................................... 220,069 233,574
Product inventory............................................................ 30,031 46,207
Parts inventory.............................................................. 9,952 10,153
Other........................................................................ - 2,951
---------- ----------
Total current assets........................................................ 265,524 297,285
---------- ----------
Property and equipment:
Gas gathering, processing, storage and transmission.......................... 789,353 952,531
Oil and gas properties and equipment......................................... 153,957 111,602
Construction in progress..................................................... 47,343 87,943
---------- ----------
990,653 1,152,076
Less: Accumulated depreciation, depletion and amortization.................. (297,628) (305,589)
---------- ----------
Total property and equipment, net........................................... 693,025 846,487
---------- ----------
Other assets:
Gas purchase contracts (net of accumulated amortization of $30,258 and
$29,978, respectively)...................................................... 37,390 41,263
Other........................................................................ 42,602 34,342
---------- ----------
Total other assets.......................................................... 79,992 75,605
---------- ----------
Total assets.................................................................. $1,038,541 $1,219,377
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable............................................................. $ 244,253 $ 245,315
Accrued expenses............................................................. 26,979 31,727
Dividends payable............................................................ 4,217 4,217
---------- ----------
Total current liabilities.................................................. 275,449 281,259
Long-term debt................................................................ 214,333 504,881
Senior subordinated debt...................................................... 155,000 -
Deferred income taxes payable................................................. 38,816 48,021
---------- ----------
Total liabilities.......................................................... 683,598 834,161
---------- ----------
Commitments and contingent liabilities........................................ - -
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; 32,177,247 and
32,173,009 shares issued and outstanding, respectively..................... 3,218 3,217
Treasury stock, at cost, 25,016 shares....................................... (788) (788)
Additional paid-in capital................................................... 397,397 397,344
Accumulated deficit.......................................................... (45,605) (17,075)
Accumulated other comprehensive income....................................... 1,189 3,053
Notes receivable from key employees secured by common stock.................. (884) (951)
---------- ----------
Total stockholders' equity................................................. 354,943 385,216
---------- ----------
Total liabilities and stockholders' equity.................................... $1,038,541 $1,219,377
========== ==========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
3
<PAGE>
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
(Dollars in thousands)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-------------------------
1999 1998
----------- -----------
<S> <C> <C>
Reconciliation of net income to net cash (used in) provided by operating activities:
Net income............................................................................ $ (15,882) $ 5,893
Add income items that do not affect working capital:
Depreciation, depletion and amortization............................................. 37,850 43,605
Deferred income taxes................................................................ (9,204) 4,412
Distributions (less than) in excess of equity income, net............................ (354) 438
(Gain) loss on the sale of property and equipment.................................... 21,406 (14,813)
Foreign currency translation adjustments............................................. (1,864) 214
Other non-cash items, net............................................................ 493 964
Adjustments to working capital to arrive at net cash (used in) provided by
operating activities:
Decrease in trade accounts receivable................................................ 4,910 62,735
Decrease in product inventory........................................................ 16,176 (44,277)
Decrease in parts inventory.......................................................... 201 (896)
Increase in other current assets..................................................... 11,546 1,854
Decrease in other assets and liabilities, net........................................ 444 143
Decrease in accounts payable......................................................... (1,062) (115,237)
Decrease in accrued expenses......................................................... (5,085) (323)
----------- -----------
Net cash provided by (used in) operating activities................................... 59,575 (96,001)
----------- -----------
Cash flows from investing activities:
Purchase of property and equipment................................................... (49,043) (72,887)
Proceeds from the dispositions of property and equipment............................. 148,100 22,600
Contributions to equity investees.................................................... (100) (748)
----------- -----------
Net cash provided by (used in) investing activities................................... 98,957 (51,035)
----------- -----------
Cash flows from financing activities:
Net proceeds from exercise of common stock options................................... 54 23
Proceeds from issuance of long-term debt............................................. 155,000 -
Debt issue costs paid................................................................ (9,319) (45)
Payments on revolving credit facility................................................ (2,022,000) (2,266,350)
Borrowings under revolving credit facility........................................... 1,815,500 2,380,350
Payments on long-term debt........................................................... (84,047) (7,143)
Dividends paid....................................................................... (12,648) (12,651)
----------- -----------
Net cash (used in) provided by financing activities................................... (157,460) 94,184
----------- -----------
Net increase (decrease) in cash and cash equivalents.................................. 1,072 (12,139)
Cash and cash equivalents at beginning of period...................................... 4,400 19,777
----------- -----------
Cash and cash equivalents at end of period............................................ $ 5,472 $ 7,638
=========== ===========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
4
<PAGE>
WESTERN GAS RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(Unaudited)
(Dollars in thousands, except share and per share amounts)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Revenues:
Sale of residue gas.................................... $ 392,679 $ 402,600 $ 1,107,734 $ 1,207,572
Sale of natural gas liquids............................ 97,660 99,947 237,514 332,571
Processing, transportation and storage revenue......... 11,799 11,459 36,118 33,450
Other, net............................................. 3,439 2,253 (11,844) 23,892
----------- ----------- ----------- -----------
Total revenues....................................... 505,577 516,259 1,369,522 1,597,485
----------- ----------- ----------- -----------
Costs and expenses:
Product purchases...................................... 456,246 469,367 1,251,424 1,429,835
Plant operating expense................................ 17,096 22,258 50,615 62,919
Oil and gas exploration and production expense......... 2,346 2,050 6,029 5,045
Depreciation, depletion and amortization............... 13,095 14,277 37,850 43,605
Selling and administrative expense..................... 5,759 6,917 21,711 21,824
Interest expense....................................... 9,365 8,969 25,118 25,265
----------- ----------- ----------- -----------
Total costs and expenses............................. 503,907 523,838 1,392,747 1,588,493
----------- ----------- ----------- -----------
Income (loss) before income taxes....................... 1,670 (7,579) (23,225) 8,992
Provision (benefit) for income taxes:
Current................................................ (528) 2,336 754 (1,313)
Deferred............................................... 1,140 (5,268) (9,204) 4,412
----------- ----------- ----------- -----------
Total provision (benefit) for income taxes........... 612 (2,932) (8,450) 3,099
----------- ----------- ----------- -----------
Income (loss) before extraordinary items................ 1,058 (4,647) (14,775) 5,893
Extraordinary charge for early extinguishment of debt,
net of tax benefit of $700,000......................... - - (1,107) -
----------- ----------- ----------- -----------
Net income (loss)....................................... 1,058 (4,647) (15,882) 5,893
Preferred stock requirements............................ (2,610) (2,610) (7,829) (7,829)
----------- ----------- ----------- -----------
Income (loss) attributable to common stock.............. $ (1,552) $ (7,257) $ (23,711) $ (1,936)
=========== =========== =========== ===========
Income (loss) per share of common stock................. $(.05) $(.23) $(.74) $(.06)
=========== =========== =========== ===========
Weighted average shares of common stock outstanding..... 32,150,111 32,147,993 32,148,699 32,147,354
=========== =========== =========== ===========
Income (loss) per share of common stock -
assuming dilution...................................... $(.05) $(.23) $(.74) $(.06)
=========== =========== =========== ===========
Weighted average shares of common stock outstanding -
assuming dilution...................................... 32,516,287 32,147,993 32,332,631 32,148,655
=========== =========== =========== ===========
</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 Treasury
Stock Stock Stock in Treasury Stock Stock Stock Stock
---------- ----------- ---------- ----------- ---------- ----------- ------ --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1998............................. 1,400,000 2,760,000 32,147,993 25,016 $ 140 $ 276 $3,217 $ (788)
Comprehensive Income:
Net loss......................... - - - - - - - -
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............................ - - - - - - - -
Loans forgiven.................... - - - - - - - -
Stock Options Exercised - - 4,238 - - - 1 -
---------- ----------- ---------- ----------- ---------- ----------- ------ --------
Balance at September 30, 1999..... 1,400,000 2,760,000 32,152,231 25,016 $ 140 $ 276 $3,218 $ (788)
---------- ----------- ---------- ----------- ---------- ----------- ------ --------
<CAPTION>
Accumulated
Other Notes Total
Additional Compre- Receivable Stock-
Paid-in Accumulated Hensive from Key holders'
Capital Deficit Income Employees Equity
---------- ----------- ----------- ---------- --------
<S> <C> <C> <C> <C> <C>
Balance at December 31,
1998............................. $ 397,344 $ (17,075) $ 3,053 $ (951) $385,216
Comprehensive Income:
Net loss......................... - (15,882) - - (15,882)
Foreign Currency
Translation..................... - - (1,864) - (1,864)
--------
Comprehensive Income (17,746)
========
Dividends:
Dividends declared on common
stock............................ - (4,821) - - (4,821)
Dividends declared on $2.28
cumulative preferred stock....... - (2,394) - - (2,394)
Dividends declared on $2.625
cumulative convertible preferred
stock............................ - (5,433) - - (5,433)
Loans forgiven.................... - - - 67 67
Stock Options Exercised 53 - - - 54
---------- ----------- ----------- ---------- --------
Balance at September 30, 1999..... $ 397,397 $ (45,605) $ 1,189 $ (884) $354,943
========== =========== =========== ========== ========
</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, 1998.
The interim consolidated financial statements as of September 30, 1999 and for
the three and nine month periods ended September 30, 1999 and 1998 included
herein are unaudited but reflect, in the opinion of management, all adjustments
(which include only normal recurring adjustments) necessary to fairly present
the results for such periods. The results of operations for the three and nine
months ended September 30, 1999 are not necessarily indicative of the results of
operations expected for the year ended December 31, 1999.
Certain prior year amounts in the interim consolidated financial statements and
notes have been reclassified to conform to the presentation used in 1999.
SALE OF SENIOR SUBORDINATED DEBT
In June 1999, we sold $155.0 million of Senior Subordinated Notes in a private
placement. These notes bear interest at 10% and were priced at 99.225% to yield
10.125%. We received net proceeds of approximately $150.0 million from the
offering of these notes, after deducting underwriters' discounts and estimated
expenses of the offering. We applied a portion of the net proceeds to repay
approximately $33.3 million of outstanding indebtedness under the Master Shelf
Agreement, on which pre-tax make-whole payments of $1.1 million were also paid.
The remaining proceeds of approximately $115.6 million were used to repay a
portion of the outstanding indebtedness under our Revolving Credit Facility.
We are in the process of making a registered Exchange Offer to the private
noteholders to exchange these privately placed notes for registered publicly
tradable notes under the same terms and conditions.
EXTRAORDINARY ITEM - EARLY EXTINGUISHMENT OF DEBT
In addition to the $1.1 million make-whole payment incurred in connection with
the repayments under the Master Shelf Agreement, we incurred an additional
$700,000 in fees and expenses related to these prepayments as well as
prepayments of a portion of the 1995 Senior Notes and the prepayment of the 1993
Senior Notes. The total costs incurred of approximately $1.8 million, net of a
tax benefit of $700,000, were reflected as an extraordinary loss on early
extinguishment of debt in the second quarter of 1999. The net extraordinary
loss of $1.1 million resulted in an increase in loss per share of common stock -
assuming dilution of $.03.
EARNINGS (LOSS) 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 $7.8 million,
respectively, for both of the three and nine month periods ended September 30,
1999 and 1998. 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 1,301 for the nine month periods ended September 30, 1998.
Common stock options were anti-dilutive for the three month periods ended
September 30, 1998 and 1999 and the nine month period ended September 30, 1999,
and were not included in the calculation of earnings per share. The numerators
and the denominators for the three and nine month periods ended September 30,
1999 and 1998 are not adjusted to reflect our outstanding $2.625 Cumulative
Convertible Preferred Stock. These shares are antidilutive as the incremental
shares available upon conversion result in an increase in earnings per share or
decrease in the loss per share, after giving effect to the dividend
requirements.
7
<PAGE>
ASSET SALES
Giddings. In April 1999, we sold our Giddings gathering system in Texas to GPM
Gas Corporation, a business unit of Phillips Petroleum Company. This
transaction had an effective date of January 1, 1999. The proceeds from this
sale were $36.0 million. This sale resulted in an approximate pre-tax loss of
$6.6 million in the second quarter of 1999, subject to final accounting
adjustment.
Katy. Effective April 30, 1999, we sold all the stock of our wholly owned
subsidiary, Western Gas Resources Storage, Inc., to the Aquila Energy
Corporation, a business unit of Utilicorp United, for gross proceeds of $100.0
million. The sole asset of this subsidiary was the Katy Hub and Gas Storage
Facility. This transaction resulted in an approximate pre-tax loss of $16.6
million, in the second quarter of 1999, subject to final accounting adjustments.
In April 1999, we also sold 5.1 Bcf of stored gas in the Katy facility to the
same purchaser for total sales proceeds of $11.7 million, which approximated our
cost of the inventory. To meet the needs of our marketing operations, we will
continue to contract for storage capacity. Accordingly, we entered into a long-
term agreement with the purchaser for approximately 3 Bcf of storage capacity at
market rates.
MiVida. In June 1999, we sold our MiVida treating facility for gross proceeds
of $12.0 million. This transaction resulted in an approximate pre-tax gain of
$1.2 million in the second quarter of 1999, subject to final accounting
adjustments.
The proceeds from all of these sales were used to reduce borrowings outstanding
under the revolving credit facility.
SUPPLEMENTARY CASH FLOW INFORMATION
Interest paid was $21.6 million and $26.5 million, respectively, for the nine
months ended September 30, 1999 and 1998.
No income taxes were paid for the nine months ended September 30, 1999 and 1998,
respectively.
SEGMENT REPORTING
We operate in four principal business segments, as follows: Gas Gathering and
Processing, Producing Properties, Marketing and Transmission. These segments
are separately monitored by management for performance against its internal
forecasts 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.
The Gas Gathering and Processing segment connects producers' wells to its
gathering systems for delivery to its processing or treating plants, processes
the natural gas to extract NGLs and treats the natural gas in order to meet
pipeline specifications. The residue gas and NGLs extracted at the processing
facilities are sold by the Marketing segment.
The activities of the Producing Properties segment include the exploration and
development of oil and gas producing properties in basins where our facilities
are located. The majority of the gas and oil produced from these properties is
sold by the Marketing segment.
The Marketing segment buys and sells gas and NGLs nationwide and in Canada,
providing storage, transportation, scheduling, peaking and other services to our
customers. In addition, this segment also markets gas and NGLs produced by our
facilities. The gains and losses from any hedges on equity gas and NGL volumes
are included in this segments' results. The operations associated with the Katy
Facility and the loss from the sale of this facility are included in the
Marketing segment, as are our Canadian marketing operations (which are
immaterial for separate presentation).
The Transmission segment reflects the operations of our MIGC and MGTC pipelines.
The majority of the revenue presented in this segment is derived from
transportation of residue gas.
8
<PAGE>
The following table sets forth our segment information as of and for the three
and nine month periods ended September 30, 1999 and 1998 (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 Producing Trans- inating
Processing Properties Marketing mission Corporate Entries Total
---------- ---------- --------- ------- --------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Three months ended September 30, 1999
Revenues from unaffiliated
customers.............................. $ 10,231 $ (18) $ 492,135 $ 1,706 $ 1,037 $ (12) $505,079
Interest income........................ - - 4 - 6,114 (5,975) 143
Other, net............................. 616 24 (285) - - - 355
Intersegment sales..................... 111,630 9,565 24,784 4,012 - (149,991) -
---------- ---------- --------- ------- --------- --------- --------
Total revenues......................... 122,477 9,571 516,638 5,718 7,151 (155,978) 505,577
---------- ---------- --------- ------- --------- --------- --------
Product purchases...................... 81,254 551 519,456 91 (19) (145,087) 456,246
Plant operating expense................ 13,783 621 143 2,951 163 (565) 17,096
Oil and gas exploration
and production expense................. - 2,343 - - 3 - 2,346
---------- ---------- --------- ------- --------- --------- --------
Operating margin....................... $ 27,440 $ 6,056 $ (2,961) $ 2,676 $ 7,004 $ (10,326) $ 29,889
========== ========== ========= ======= ========= ========= ========
Depreciation, depletion and
amortization........................... 8,198 3,284 41 324 1,180 68 13,095
Interest expense....................... 9,365
Selling and administrative expense..... 5,759
--------
Income before income taxes............. $ 1,670
========
Identifiable assets.................... $ 523,928 $ 96,127 $ 88 $67,892 $ 37,252 $ - $725,287
========== ========== ========= ======= ========= ========= ========
<CAPTION>
Gas
Gathering Elim-
and Producing Trans- inating
Processing Properties Marketing mission Corporate Entries Total
---------- ---------- --------- ------- --------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Three months ended September 30, 1998
Revenues from unaffiliated
customers.............................. $ 9,987 $ 593 $ 504,384 $ 559 $ 332 $ 69 $515,924
Interest income........................ 1 - - - 7,380 (7,204) 177
Other, net............................. (37) - 195 - - - 158
Intersegment sales..................... 103,367 4,916 17,390 2,858 - (128,531) -
---------- ---------- --------- ------- --------- --------- --------
Total revenues......................... 113,318 5,509 521,969 3,417 7,712 (135,666) 516,259
---------- ---------- --------- ------- --------- --------- --------
Product purchases...................... 83,441 301 511,941 35 (635) (125,716) 469,367
Plant operating expense................ 20,646 314 1,771 2,216 129 (2,818) 22,258
Oil and gas exploration
and production expense................. 1 1,909 118 - (1) 23 2,050
---------- ---------- --------- ------- --------- --------- --------
Operating margin....................... $ 9,230 $ 2,985 $ 8,139 $ 1,166 $ 8,219 $ (7,155) $ 22,584
========== ========== ========= ======= ========= ========= ========
Depreciation, depletion and
amortization........................... 9,563 2,287 1,047 253 1,161 (34) 14,277
Interest expense....................... 8,969
Selling and administrative expense..... 6,917
--------
(Loss) before income taxes............. $ (7,579)
========
Identifiable assets.................... $ 649,423 $ 108,527 $ 119,735 $56,215 $ 32,793 $ - $966,693
========== ========== ========= ======= ========= ========= ========
</TABLE>
9
<PAGE>
<TABLE>
<CAPTION>
Gas
Gathering Elim-
and Producing Trans- inating
Processing Properties Marketing mission Corporate Entries Total
---------- ---------- ---------- ------- --------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Nine months ended September 30, 1999
Revenues from unaffiliated
customers............................. $ 33,362 $ 1,062 $1,347,586 $ 5,402 $ 2,759 $ (41) $1,390,130
Interest income....................... 1 - 28 - 19,422 (19,165) 286
Other, net............................ (4,173) 24 (16,745) - - - (20,894)
Intersegment sales.................... 274,835 22,648 63,724 12,194 - (373,401) -
---------- ---------- ---------- ------- --------- --------- ----------
Total revenues........................ 304,025 23,734 1,394,593 17,596 22,181 (392,607) 1,369,522
---------- ---------- ---------- ------- --------- --------- ----------
Product purchases..................... 209,053 1,450 1,408,636 609 (1,520) (366,804) 1,251,424
Plant operating expense............... 38,703 1,623 1,816 8,322 2,079 (1,928) 50,615
Oil and gas exploration
and production expense................ - 5,940 (44) - 133 - 6,029
---------- ---------- ---------- ------- --------- --------- ----------
Operating margin...................... $ 56,269 $ 14,721 $ (15,815) $ 8,665 $ 21,489 $ (23,875) $ 61,454
========== ========== ========== ======= ========= ========= ==========
Depreciation, depletion and
amortization.......................... 23,830 8,553 1,250 844 3,373 - 37,850
Interest expense...................... 25,118
Selling and administrative expense.... 21,711
----------
(Loss) before income taxes............ $ (23,225)
==========
Identifiable assets................... $ 523,928 $ 96,127 $ 88 $67,892 $ 37,252 $ - $ 725,287
========== ========== ========== ======= ========= ========= ==========
<CAPTION>
Gas
Gathering Elim-
and Producing Trans- inating
Processing Properties Marketing mission Corporate Entries Total
---------- ---------- ---------- ------- --------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Nine months ended September 30, 1998
Revenues from unaffiliated
customers............................. $ 27,938 $ 1,453 $1,545,803 $ 3,879 $ 678 $ 617 $1,580,368
Interest income....................... 1 - - - 26,551 (25,625) 927
Other, net............................ 15,360 703 143 (16) - - 16,190
Intersegment sales.................... 328,670 18,253 61,324 8,346 - (416,593) -
---------- ---------- ---------- ------- --------- --------- ----------
Total revenues........................ 371,969 20,409 1,607,270 12,209 27,229 (441,601) 1,597,485
---------- ---------- ---------- ------- --------- --------- ----------
Product purchases..................... 257,428 1,021 1,584,718 126 (2,665) (410,793) 1,429,835
Plant operating expense............... 51,624 1,653 4,651 7,533 2,564 (5,106) 62,919
Oil and gas exploration
and production expense................ - 4,877 125 - 2 41 5,045
---------- ---------- ---------- ------- --------- --------- ----------
Operating margin...................... $ 62,917 $ 12,858 $ 17,776 $ 4,550 $ 27,328 $ (25,743) $ 99,686
========== ========== ========== ======= ========= ========= ==========
Depreciation, depletion and
amortization.......................... 27,796 8,518 3,139 760 3,494 (102) 43,605
Interest expense...................... 25,265
Selling and administrative expense.... 21,824
----------
Income before income taxes............ $ 8,992
==========
Identifiable assets................... $ 649,423 $ 108,527 $ 119,735 $56,215 $ 32,793 $ - $ 966,693
========== ========== ========== ======= ========= ========= ==========
</TABLE>
10
<PAGE>
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities," ("SFAS No. 133") with an effective date for
fiscal years beginning after June 15, 1999. In June 1999, FASB issued Statement
of Financial Accounting Standards No. 137, "Accounting for Derivative
Instruments and Hedging Activities-Deferral of the Effective Date of FASB
Statement No. 133" ("SFAS No. 137"). SFAS No. 137 amended the earlier statement
to defer the effective date one year. The statement will now be effective for
all fiscal quarters of all fiscal years beginning after June 15, 2000. We have
not yet completed our evaluation of the impact that SFAS No. 133 will have upon
our financial statements. When required, we will comply with the accounting and
reporting requirements of SFAS No. 133.
LEGAL PROCEEDINGS
Reference is made to "Part II - Other Information - Item 1. Legal Proceedings,"
of this Form 10-Q.
11
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
-----------------------------------------------------------------------
OF OPERATIONS
-------------
The following discussion and analysis relates to factors, which have affected
our consolidated financial condition and our results of operations for the three
and nine month periods ended September 30, 1999 and 1998. Certain prior year
amounts have been reclassified to conform to the presentation used in 1999.
Reference should also be made to our interim consolidated financial statements
and notes thereto included elsewhere in this document. This section, as well as
other sections in this Form 10-Q, contain "forward-looking statements" within
the meaning of the Private Securities Litigation Reform Act of 1995, which can
be identified by the use of forward-looking terminology, such as "may,"
"intend," "will," "expect," "anticipate," "estimate," or "continue" or the
negative thereof or other variations thereon or comparable terminology. In
addition to the important factors referred to herein, numerous factors affecting
the gas processing industry generally and in the specific markets for gas and
NGLs in which we operate, could cause actual results to differ materially from
those in such forward-looking statements.
Results of Operations
Three and nine months ended September 30, 1999 compared to the three and nine
months ended September 30, 1998
(Dollars in thousands, except per share amounts and operating data).
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- Percent ----------------------- Percent
1999 1998 Change 1999 1998 Change
-------- -------- ------- ---------- ---------- -------
<S> <C> <C> <C> <C> <C> <C>
Financial results:
Revenues................................... $505,577 $516,259 (2) $1,369,522 $1,597,485 (14)
Gross profit............................... 16,794 8,307 102 23,604 56,081 (58)
Net income (loss).......................... 1,058 (4,647) - (15,882) 5,893 -
Income (loss) per share of common stock.... (.05) (.23) 78 (.74) (.06) -
Income (loss) per share of common stock -
assuming dilution..................... (.05) (.23) 78 (.73) (.06) -
Net cash (used in) provided by
operating activities..................... $ 15,827 $(44,416) - $ 59,575 $ (96,001) -
Operating data:
Average gas sales (MMcf/D)................. 1,775 2,295 (23) 1,960 2,200 (11)
Average NGL sales (MGal/D)................. 2,815 4,345 (35) 2,875 4,540 (37)
Average gas prices ($/Mcf)................. $ 2.41 $ 1.90 (27) $ 2.07 $ 2.01 3
Average NGL prices ($/Gal)................. $ .38 $ .25 (52) $ .30 $ .27 11
</TABLE>
Net income increased $5.7 million and decreased $21.8 million for the three and
nine months ended September 30, 1999, respectively, compared to the same periods
in 1998. The increase in net income for the third quarter was primarily due to
increased prices, as well as lower operating costs. The decrease for the nine
month period was primarily due to losses of $14.2 million associated with the
sales of the Giddings gathering systems and the Katy facility, severance charges
associated with a corporate restructuring of $700,000 and an extraordinary loss
on the early extinguishment of debt of $1.1 million. Also included in the 1998
results was the gain on the sale of the Perkins facility.
Revenues from the sale of residue gas decreased approximately $9.9 million to
$392.7 million for the quarter ended September 30, 1999 compared to the same
period in 1998, as average gas sales volumes decreased 520 MMcf per day to 1,775
MMcf per day and average gas prices increased $.51 per Mcf to $2.41 per Mcf.
The decrease in sales volumes was primarily related to the reduction in the sale
of residue gas purchased from third parties. The reduction in third party sales
was prompted by a continuing reduction in margins obtained on the sale of third
party residue gas.
Revenues from the sale of residue gas decreased approximately $99.8 million to
$1,107.7 million for the nine months ended September 30, 1999 compared to the
same period in 1998, as average gas sales volumes decreased 240 MMcf per day to
1,960 MMcf per day and average gas prices increased $.06 per Mcf to $2.07 per
Mcf. The decrease in sales volumes was primarily
12
<PAGE>
related to the reduction in the sale of residue gas purchased from third
parties. The reduction in third party sales was prompted by a continuing
reduction in margins obtained on the sale of third party residue gas.
Included in the average gas price was approximately $2.0 million and $2.3
million of loss recognized for the three and nine months ended September 30,
1999, respectively, related to futures positions on equity gas volumes. We have
entered into futures positions for a portion of our equity gas for the remainder
of 1999 and in 2000. See further discussion in "Liquidity and Capital Resources
- - Risk Management Activities."
Revenues from the sale of NGLs decreased approximately $2.3 million to $97.7
million for the quarter ended September 30, 1999 compared to the same period in
1998 as average NGL sales volumes decreased 1,530 MGal per day to 2,815 MGal per
day although average NGL prices increased $.13 per gallon to $.38 per gallon.
The decreases in sales volumes were related to a decrease in sales of NGLs
purchased from third parties and a decrease in plant sales volumes. Plant NGL
sales volumes were largely affected by increased volumes taken in kind and
curtailed drilling activity due to low oil prices by a producer behind Midkiff,
and the sale of the Edgewood and Giddings facilities. Volumes taken in kind
affect sales volumes and revenues but do not materially affect income.
Revenues from the sale of NGLs decreased approximately $95.1 million to $237.5
million for the nine months ended September 30, 1999 compared to the same period
in 1998 as average NGL sales volumes decreased 1,665 MGal per day to 2,875 MGal
per day and average NGL prices increased $.03 per gallon to $.30 per gallon.
Plant sales volumes were largely affected by increased volumes taken in kind and
curtailed drilling activity due to low oil prices by a producer behind Midkiff,
and the sale of the Giddings and Edgewood facilities. Volumes taken in kind
affect sales volumes and revenues but do not materially affect income.
Included in the average NGL prices was approximately $2.4 million and $4.4
million of loss recognized for the three and nine months ended September 30,
1999, respectively, related to futures positions on equity volumes. We have
entered into futures positions for a portion of our equity production for the
remainder of 1999 and in 2000. See further discussion in "Liquidity and Capital
Resources - Risk Management Activities."
Overall, excluding the impact of the plants sold in 1998 and 1999, the
production of residue gas and NGLs at our facilities increased in both the three
and nine month periods ended September 30, 1999.
Other net revenue decreased $36.5 million for the nine months ended September
30, 1999 due to the net losses on the sales of the Katy, Giddings and MiVida
assets of $22.3 million in 1999 compared to a $14.9 million gain recognized on
the sale of the Perkins facility in March 1998.
Product purchases decreased $13.1 million and decreased $178.4 million for the
three and nine months ended September 30, 1999, respectively, compared to the
same periods in 1998. The decrease in product purchases in both periods is
primarily due to a decrease in sales volumes of product purchased from third
parties. Overall product purchases as a percentage of residue gas and NGL sales
remained the same at 93% for the three and nine months ended September 30, 1999,
respectively, as compared to the same periods in 1998.
Plant operating expense decreased $5.2 million and $12.3 million, respectively,
for the three and nine months ended September 30, 1999 compared to the same
periods in 1998. The decreases are primarily due to reductions in labor,
increased operational efficiencies and the asset sales.
Depreciation, depletion and amortization decreased $1.2 million and $5.8 million
for the three and nine month periods ended September 30, 1999, respectively,
compared to the same periods in 1998. The decrease is primarily due to a
reduction in depreciation of the Bethel facility resulting from an impairment
charge recorded in the fourth quarter of 1998 and the sale of assets in 1998 and
1999.
Selling and administrative expense decreased $1.2 million for the three months
ended September 30, 1999. The decrease was primarily related to reductions in
labor, resulting from the sale of assets and reductions in residue gas sales
volumes in 1998 and 1999.
13
<PAGE>
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
1998, sources of liquidity included the sales of the Perkins facility and the
Edgewood facility and related production. In the second quarter of 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. The total
gross proceeds from these 1999 transactions was $160.0 million. We used the
proceeds from these sales 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 such 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
such 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 the remainder of
1999.
Historically, while certain individual plants have experienced declines in
dedicated reserves, we have been successful in connecting additional reserves to
more than offset the natural declines. There has been 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 experienced over the
last several years, 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
gas and oil, the drilling budgets of third-party producers, the energy policy of
the federal government and the availability of foreign oil and gas, none of
which is within our control. We have increased our dedicated estimated plant
reserves from 2.2 Tcf at December 31, 1993 to 3.1 Tcf at December 31, 1998. On
average, over this five year period, including the reserves associated with our
joint ventures and partnerships and excluding the facilities sold during this
period, we connected new reserves to our facilities to replace approximately
165% of throughput over this period. There is no assurance that we will
continue to be successful in replacing the dedicated reserves processed at our
facilities.
In addition to the registration statement for the Exchange Offer discussed above
under "Sale of Senior Subordinated Debt," 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 such securities are convertible, and $62 million of debt securities,
preferred stock or common stock.
14
<PAGE>
Our sources and uses of funds for the nine months ended September 30, 1999 are
summarized as follows (In thousands):
<TABLE>
<CAPTION>
Sources of funds:
<S> <C>
Borrowings under revolving credit facility................ $1,815,500
Proceeds from the dispositions of property and equipment.. 148,100
Proceeds from issuance of long-term debt.................. 155,000
Net cash provided by operating activities................. 59,575
Proceeds from exercise of common stock options............ 54
----------
Total sources of funds.................................. $2,178,229
==========
Uses of funds:
Payments related to long-term debt........................ $2,115,366
Capital expenditures...................................... 49,043
Dividends paid............................................ 12,648
----------
Total uses of funds..................................... $2,177,157
==========
</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
10.9 Bcf at an average cost of $2.18 per Mcf at September 30, 1999 compared to
21.3 Bcf at an average cost of $2.08 per Mcf at September 30, 1998 under storage
contracts at various third-party facilities. At September 30, 1999, we had
hedging contracts in place for anticipated sales of approximately 10.8 Bcf of
stored gas at a weighted average price of $2.38 per Mcf for the stored
inventory.
We held NGLs in storage of 15,700 MGal, consisting primarily of propane and
normal butane, at an average cost of $.36 per gallon and 50,700 MGal at an
average cost of $.28 per gallon at September 30, 1999 and 1998, respectively, at
various third-party storage facilities. At September 30, 1999, we had no
significant hedging contracts in place for anticipated sales of stored NGLs.
Capital Investment Program
Largely as a result of low commodity prices experienced in the first half of
1999, we have reduced our budget for capital expenditures in 1999 from the
levels expended in 1997 and 1998. We expect capital expenditures related to
existing operations to be approximately $78.3 million during 1999, consisting of
the following: (i) approximately $41.4 million related to gathering, processing
and pipeline assets, of which $6.3 million is for maintaining existing
facilities; (ii) approximately $33.5 million on exploration and production
activities; and (iii) approximately $3.4 million for miscellaneous items.
Overall, capital expenditures in the Powder River basin coal bed methane
development and in Southwest Wyoming operations represent 57% and 20%,
respectively, of the total 1999 budget. As of September 30, 1999, we have
expended $49.1 million, consisting of the following: (i) $28.4 million for new
connects, system expansions and asset consolidations; (ii) $1.6 million for
maintaining existing facilities; (iii) $18.0 million for exploration and
production activities; and (iv) $1.1 million related to other miscellaneous
items.
Powder River Basin - We continue to develop our Powder River basin coal bed
methane natural gas gathering system and our coal seam gas reserves in Wyoming.
We have acquired drilling rights on 830,000 gross acres (or 425,000 net acres)
in the vicinity of known coal bed methane production. We and other operators in
the area have established production from wells drilled to depths of 400 to
1,200 feet. Together with our partner, we expect to drill approximately 580
wells in 1999, of which approximately 484 have been drilled through September
30, 1999, all of which are on locations with proven, undeveloped reserves. The
average drilling, completion and gathering cost for our coal bed methane wells
is approximately $65,000 with proven reserves per well of approximately 320
MMcf. As deeper wells are drilled, the average cost per well is expected to
increase. Production of coal bed methane from the Powder River basin has been
expanding, and approximately 139 MMcf/D of gas volumes in the third quarter of
1999 were being produced by several operators in the area as compared to 61
MMcf/D in January 1998. Approximately 63% of this production is from acreage
equally owned by our partner, Barrett Resources Corporation, and us. We
transport most of the coal bed methane gas through our MIGC interstate pipeline
located in Wyoming, for redelivery to gas markets in the Rocky Mountain and
Midwest regions of the United States.
15
<PAGE>
Current drilling schedules on federal acreage are being delayed subject to
approval of the Wyodak Environmental Impact Statement. The record decision for
this environmental impact statement is expected to be issued in November 1999.
The wells expected to be allowed by this environmental impact statement have
been permitted. Further drilling permits will require additional environmental
studies. However, we can make no assurance as to the timing or conditions of
any future studies. Our drilling plans for the years 2000 and 2001 are primarily
scheduled on fee and state lands which will not require federal permits.
In addition, the Wyoming Department of Environmental Quality is reviewing the
water discharge and quality standards in the Powder River basin, and this review
is causing a delay in the issuance of water disposal permits. Currently
individual well permits are being issued in certain areas. We believe that the
conditions under which water disposal permits will be issued will be clarified
within the second quarter of 2000. However, we can make no assurance that the
conditions under which permits are granted will not impact the level of drilling
or the timing of production.
In December 1998, we joined with other industry partners to form Fort Union Gas
Gathering, L.L.C., which has substantially completed the 106-mile long, 24-inch
gathering pipeline and treater to gather and treat natural gas produced in the
Powder River basin. We own a 13% equity interest in Fort Union and are the
construction manager and field operator. We expect this new gathering pipeline
to have an initial capacity of approximately 450 MMcf/D of natural gas with
expansion capability. The pipeline became operational in September 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 are located in the Southwest Wyoming portion of this basin. They
include the Granger gathering and processing facility and our 72% ownership
interest in the Lincoln Road gathering and processing facility. These
facilities have a combined operational capacity of 225 MMcf/D and processed an
average of 180 MMcf/D in the third quarter of 1999. We believe that as
governmental drilling restrictions affecting a portion of our service area in
this basin are removed in the first half of 2000, we may have the opportunity to
expand these facilities in future years.
16
<PAGE>
Financing Facilities
Revolving Credit Facility. The Revolving Credit Facility is with a syndicate
of banks and provides for a maximum borrowing commitment of $250 million
consisting of an $83 million 364-day Revolving Credit Facility, or Tranche A,
and a five-year $167 million Revolving Credit Facility, or Tranche B. At
September 30, 1999, $29.0 million was outstanding on this facility. The
Revolving Credit Facility bears interest at certain spreads over the Eurodollar
rate, or the greater of the Federal Funds rate or the agent bank's prime rate.
We have the option to determine which rate will be used. We also pay a facility
fee on the commitment. The interest rate spreads and facility fee are adjusted
based on our debt to capitalization ratio and range from .75% to 2.00%. At
September 30, 1999, the interest rate payable on the facility was 6.88%. We are
required to maintain a total debt to capitalization ratio of not more than 60%
through December 31, 2000 and of not more than 55% thereafter, and a senior debt
to capitalization ratio of not more than 40% beginning September 30, 1999
through December 31, 2001 and of not more than 35% thereafter. The agreement
also requires a ratio of EBITDA, excluding certain non-recurring items, to
interest and dividends on preferred stock as of the end of any fiscal quarter,
for the four preceding fiscal quarters, of not less than 1.35 to 1.0 beginning
June 30, 1999 and increasing to 3.25 to 1.0 by December 31, 2002. This facility
is guaranteed and secured via a pledge of the stock of certain of our
subsidiaries. We generally utilize excess daily funds to reduce any outstanding
balances on the Revolving Credit Facility and associated interest expense, and
we intend to continue such practice.
Master Shelf Agreement. In December 1991, we entered into a Master Shelf
Agreement with The Prudential Insurance Company of America. Amounts outstanding
under the Master Shelf Agreement at September 30, 1999 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 $ 8,334 7.51% October 27, 1999 single payment was made at maturity
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
--------
$158,334
========
</TABLE>
In April 1999, effective January 1999, we amended our agreement with Prudential
to reflect the following provisions. We are required to maintain a current
ratio, as defined therein, 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
amendment also requires an EBITDA to interest ratio of not less than 1.75 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 1.75 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 certain non-recurring items. In addition, we are
prohibited from declaring or paying dividends that in the aggregate exceed the
sum of $50 million plus 50% of consolidated net income earned after June 30,
1995, or minus 100% of a net loss, plus the aggregate net cash proceeds received
after June 30, 1995 from the sale of any stock. At September 30, 1999,
approximately $25.7 million was available under this limitation. We financed the
$8.3 million payment due in October 1999 with amounts available under the
Revolving Credit Facility. Borrowings under the Master Shelf Agreement are
guaranteed and secured via a pledge of the stock of certain of our subsidiaries.
In June 1999, we prepaid approximately $33.3 million of notes outstanding under
the Master Shelf Agreement with proceeds from the offering of the Subordinated
Notes.
17
<PAGE>
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. These payments were financed by a
portion of the $37 million Bridge Loan described below and by amounts available
under the Revolving Credit Facility. 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 certain of our
subsidiaries. This facility contains covenants similar to the Master Shelf
Agreement. In the second quarter of 1999, we posted letters of credit for a
total of approximately $10.8 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.
1993 Senior Notes. In 1993, we sold $50 million of 7.65% Senior Notes, the
1993 Senior Notes, to a group of insurance companies. Scheduled annual principal
payments of $7.1 million on the 1993 Senior Notes were made on April 30 of 1997
and 1998. In February 1999, we prepaid $33.5 million of the total principal
amounts outstanding of $35.6 million at par. These payments were financed by a
portion of the $37 million Bridge Loan. We prepaid the remaining outstanding
principal of $2.1 million in April 1999 with amounts available under the
Revolving Credit Facility.
In connection with the repayments on the Master Shelf Agreement, the 1995 Senior
Notes and the 1993 Senior Notes, we incurred approximately $1.8 million of pre-
tax yield maintenance and other charges. These charges are reflected as an
extraordinary loss from early extinguishment of long-term debt in the second
quarter of 1999.
Bridge Loan. In February 1999, in order to finance prepayments of amounts
outstanding on the 1993 and 1995 Senior Notes, we entered into a Bridge Loan
agreement in the amount of $37 million with our agent bank. This facility was
paid in full in April 1999 with proceeds from the sale of the Katy facility.
Senior Subordinated Notes. In June 1999, we sold $155.0 million of Senior
Subordinated Notes in a private placement. The Subordinated Notes bear interest
at 10% 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 certain of our subsidiaries. We are in
the process of making a registered Exchange Offer to the private noteholders to
exchange these privately placed notes for registered publicly tradable notes
under the same terms and conditions.
Covenant Compliance. Taking into account all the covenants contained in these
agreements, we had approximately $124.0 million of available borrowing capacity
at September 30, 1999. In the second quarter of 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 will 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.
18
<PAGE>
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
----------------------------------------------------------
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 1999,
particularly in the first quarter, at pricing levels approximating our 1999
operating budget. Our equity hedging strategy establishes a minimum price while
allowing varying levels of market participation above these levels. As of
September 30, 1999, we had hedged approximately 70% of our anticipated equity
gas for 1999 at a weighted average NYMEX equivalent minimum price of $2.00 per
Mcf and approximately 51% of our anticipated equity gas for 2000 at a weighted
average NYMEX equivalent minimum price of $2.22. Additionally, we have hedged
approximately 77% of our anticipated equity NGLs for 1999 at a weighted average
composite Mont Belvieu and West Texas Intermediate crude oil equivalent minimum
price of $.23 per gallon and approximately 52% of our anticipated equity NGLs
for 2000 at a weighted average composite Mont Belvieu and West Texas
Intermediate crude oil equivalent minimum price of $.28 per gallon.
At September 30, 1999, we had $1.6 million of gains deferred in inventory that
will be recognized over the remainder of 1999, and will be offset by margins
from our related forward fixed price hedges and physical sales. At September
30, 1999, we had unrecognized net gains of $349,000 related to financial
instruments that were offset by corresponding unrecognized net gains from our
obligations to sell physical quantities of gas and NGLs.
We enter into speculative futures, swap and option trades on a very limited
basis for purposes that include testing of hedging techniques. Our policies
contain strict guidelines for these trades including predetermined stop-loss
requirements and net open position limits. Speculative futures, swap and option
positions are marked to market at the end of each accounting period and any gain
or loss is recognized in income for that period. Net gains or losses from these
speculative activities for the quarters and nine months ended September 30, 1999
and 1998 were not material.
19
<PAGE>
Year 2000
We have made a comprehensive review of our computer systems to identify the
systems that could be affected by the Year 2000 issue. As provided in our
project plan, we have: (i) created a Year 2000 awareness program to educate
employees; (ii) compiled an inventory of all systems; (iii) developed system
test plans as appropriate; (iv) substantially completed the testing and
remediation as required for both information and non-information technology
systems; and (v) prepared our contingency plans to minimize the impact of a
Year 2000 related failure caused either internally or externally. Additionally,
we have initiated a program under which we survey our business counterparties
periodically regarding their Year 2000 conversion and contingency plans.
Through September 30, 1999 we have spent approximately $1.5 million for
remediation purposes, which primarily consisted of hardware and operating system
upgrades. We have incurred and will continue to incur internal staff costs as
well as some consulting and other expenses, which have been and are expected to
continue to be immaterial. Our Year 2000 conversion project is substantially
complete. Currently, we believe our most significant risk for the Year 2000
issue is that the systems of other companies on which we rely will not be Year
2000 compliant and that any failure to convert by another company will have an
adverse effect on our results of operations or financial position. In order to
mitigate this risk, we continue to modify contingency plans as appropriate and
continue to survey our vendors and customers to verify the status of their
conversion and contingency plans.
20
<PAGE>
Principal Facilities
The following tables provide information concerning our principal facilities at
September 30, 1999. We also own and operate several smaller treating,
processing and transmission facilities located in the same areas as our other
facilities.
<TABLE>
<CAPTION>
Average for the Nine Months Ended
September 30, 1999
Gas Gas -------------------------------------
Gathering Throughput Gas Gas NGL
Year Placed Systems 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>
Southern Region:
Texas
Bethel Treating (6)............ 1997 86 350 83 79 -
Giddings Gathering(14)......... 1979 - 80 48 31 66
Gomez Treating................. 1971 385 280 109 101 -
Midkiff/Benedum................ 1955 2,140 165 143 92 877
Mitchell Puckett Gathering..... 1972 86 120 115 75 2
MiVida Treating (6)(16)........ 1972 - 150 46 44 -
Rosita Treating................ 1973 - 60 42 - -
Louisiana
Black Lake..................... 1966 56 75 11 6 17
Toca (7)(8).................... 1958 - 160 88 83 71
Northern Region:
Wyoming
Coal Bed Methane
Gathering..................... 1990 449 105 122 87 -
Granger (7)(9)(10)............. 1987 467 235 156 139 285
Hilight Complex (7)............ 1969 622 80 19 35 92
Kitty/Amos Draw (7)............ 1969 313 17 12 8 49
Lincoln Road (10).............. 1988 149 50 24 22 23
Newcastle...................... 1981 146 5 2 2 18
Red Desert..................... 1979 111 42 17 15 29
Reno Junction (9).............. 1991 - - - - 51
Oklahoma
Arkoma......................... 1985 72 8 7 7 -
Chaney Dell.................... 1966 2,050 180 60 47 190
Westana........................ 1986 800 45 67 57 80
New Mexico
San Juan River (6)............. 1955 140 60 26 20 26
Utah
Four Corners Gathering......... 1988 104 15 3 4 14
----- ----- ----- --- -----
Total......................... 8,176 2,282 1,200 954 1,890
===== ===== ===== === =====
</TABLE>
<TABLE>
<CAPTION>
Average for the
Nine Months Ended
September 30, 1999
Interconnect ------------------
and Pipeline Gas
Storage and Year Placed Transmission Capacity Throughput
Transmission Facilities (1) In Service Miles(2) (MMcf/D)(2) (MMcf/D)(3)
- --------------------------------- ----------- ------------ ---------- ------------------
<S> <C> <C> <C> <C>
Katy Facility (11)(14)........... 1994 - - 244
MIGC (12)(15).................... 1970 245 130 162
MGTC (13)........................ 1963 252 18 12
Fort Union Pipeline (17)......... 1999 106 450 14
----- ----- ---
Total.......................... 603 598 432
==== ===== =====
</TABLE>
Footnotes on following page.
21
<PAGE>
(1) Our interest in all facilities is 100% except for Midkiff/Benedum (73%);
Black Lake (69%); Lincoln Road (72%); Westana Gathering Company (50%);
Newcastle (50%) and Fort Union Pipeline (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 systems miles, interconnect and transmission miles, gas
storage capacity and pipeline capacity are as of September 30, 1999.
(3) Gas throughput capacity is as of September 30, 1999 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,
aggregate volumes delivered over the header at the Katy Facility 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 such 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) Hub and gas storage facility.
(12) MIGC is an interstate pipeline located in Wyoming and is regulated by the
Federal Energy Regulatory Commission.
(13) MGTC is a public utility located in Wyoming and is regulated by the
Wyoming Public Service Commission.
(14) This facility was sold in April 1999.
(15) Pipeline capacity represents capacity at the Powder River junction only
and does not include northern delivery points.
(16) This facility was sold in May 1999.
(17) This pipeline is a non-regulated pipeline which became operational during
September 1999.
22
<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 concerns 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 November
1998, the court granted summary judgment in favor of McMurry as to the ownership
of 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. Trial on the liability phase of the litigation between McMurray
and Mountain Gas was held in May 1999 and judgment was rendered against Mountain
Gas in June 1999, assessing liability for intentional interference of business
expectancies and opportunities and a finding that such interference caused
McMurry to forego or delay entry into these opportunities and further, that
Mountain Gas' assertion of ownership of Preferential Rights were false and
thereby disparaged McMurry's title and rights. Initially, the court ruled that
McMurry was entitled to seek damages against Mountain Gas and that the damages
may include punitive damages. In October 1999 the court ruled, in response to a
motion filed by Mountain Gas, that McMurry was not entitled to seek punitive
damage claims which had been previously asserted in this matter. McMurry has
alleged non-punitive damage claims in this matter of approximately $30 million.
In addition, the jury trial to determine causation and mitigation and the extent
and amount of McMurry's damage claims has been rescheduled for January 2000.
Mountain Gas still believes the damage claims are excessive and unjustified and
will vigorously defend its actions and contest the damage claims raised by
McMurry in this matter. Under the terms of the court's order, Mountain Gas is
not permitted to file any appeal until the damage claims have been litigated.
Mountain Gas believes it has several grounds for appeal in this matter. At the
present time, it is not possible to express an opinion as to the final outcome
of this litigation or to estimate the final amount of damages, if any, to be
assessed in this matter.
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 an independent producer and marketer of natural gas and
alleges that it owns or has the right to produce and sell natural gas in the
Temple/Tioga Area in North Dakota. Berco alleges 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 alleges that we, along with Amerada Hess, have 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. Berco seeks an award against Amerada Hess
and us of threefold the amount of damages actually sustained by Berco, in an
amount to be determined at trial, and/or divestiture of the assets which Amerada
Hess acquired, for an order restraining and enjoining us and Amerada Hess from
violating the antitrust laws, and for costs, attorney fees and interest. A
trial is currently scheduled for October 2000. We believe that we have
meritorious defenses to the claims and will vigorously contest such claims. At
the present time it is not possible to predict the outcome of this litigation or
to estimate the amount of potential damages.
Internal Revenue Service
The Internal Revenue Service ("IRS") has completed its examination of our tax
returns for the years 1990 and 1991 and has proposed adjustments to taxable
income reflected in such tax returns that would shift the recognition of certain
items of income and expense from one year to another ("Timing Adjustments"). To
the extent taxable income in a prior year is increased by proposed Timing
Adjustments, taxable income may be reduced by a corresponding amount in other
years. However, we would incur an interest charge as a result of such
adjustments. We are currently protesting certain of these proposed adjustments.
In the opinion of management, any proposed adjustments for the additional income
taxes and interest that may result would not be material. However, it is
reasonably possible that the ultimate resolution could result in an amount,
which differs, materially from management's estimates.
Other
We are involved in various other litigation and administrative proceedings
arising in the normal course of 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.
23
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
None
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
27 Financial Data Schedule
(b) Reports on Form 8-K:
We filed a report on Form 8-K/A on July 7, 1999 with the Securities
and Exchange Commission. We had filed a Form 8-K on May 10, 1999
regarding the sale of our wholly owned subsidiary, Western Gas
Resources Storage, Inc. At the time of the Form 8-K filing, it was
impractical to provide the required audited financial statements of
the business disposed of and pro forma financial information. This
amendment to the May 10, 1999 Form 8-K sets forth the required
financial information.
We filed a report on Form 8-K on September 22, 1999 with the
Securities and Exchange Commission reflecting changes to our Board of
Directors and top management.
24
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
WESTERN GAS RESOURCES, INC.
---------------------------
(Registrant)
Date: November 15, 1999 By: /s/ LANNY F. OUTLAW
-------------------------------------
Lanny F. Outlaw
Chief Executive Officer and President
Date: November 15, 1999 By: /s/ WILLIAM J. KRYSIAK
--------------------------------------
William J. Krysiak
Vice President - Finance
(Principal Financial and Accounting
Officer)
25
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 5,472
<SECURITIES> 0
<RECEIVABLES> 220,069
<ALLOWANCES> 0
<INVENTORY> 39,983
<CURRENT-ASSETS> 265,524
<PP&E> 990,653
<DEPRECIATION> (297,628)
<TOTAL-ASSETS> 1,038,541
<CURRENT-LIABILITIES> 275,449
<BONDS> 369,333
3,218
0
<COMMON> 416
<OTHER-SE> 351,309
<TOTAL-LIABILITY-AND-EQUITY> 1,038,541
<SALES> 1,381,366
<TOTAL-REVENUES> 1,369,522
<CGS> 1,257,453
<TOTAL-COSTS> 1,257,453
<OTHER-EXPENSES> 110,176
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 25,118
<INCOME-PRETAX> (23,225)
<INCOME-TAX> 8,450
<INCOME-CONTINUING> (14,775)
<DISCONTINUED> 0
<EXTRAORDINARY> (1,107)
<CHANGES> 0
<NET-INCOME> (15,882)
<EPS-BASIC> (.74)
<EPS-DILUTED> (.74)
</TABLE>
