<PAGE> 1
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, 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 0-18886
---------------------------------------------------------
HS RESOURCES, INC.
--------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
Delaware 94-3036864
------------------------------- ------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
One Maritime Plaza, Fifteenth Floor
San Francisco, California 94111
---------------------------------------- ------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (415) 433-5795
------------------------------
--------------------------------------------------------------------------------
(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
---- ----
APPLICABLE ONLY TO CORPORATE ISSUERS:
Number of shares of Common Stock, $.001 par value, outstanding as of the close
of business on October 31, 2000: 17,979,640 after deducting 1,819,435 shares in
treasury.
<PAGE> 2
HS RESOURCES, INC.
INDEX
<TABLE>
<CAPTION>
Page
----
<S> <C>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets - September 30, 2000 (Unaudited) and
December 31, 1999........................................................................................3
Unaudited Consolidated Statements of Operations - For the Three Months
and Nine Months Ended September 30, 2000 and 1999........................................................5
Consolidated Statements of Stockholders' Equity - For
the Years Ended December 31, 1999 and 1998 and the Nine Months Ended
September 30, 2000 (Unaudited)...........................................................................6
Unaudited Consolidated Statements of Cash Flows -
For the Nine Months Ended September 30, 2000 and 1999....................................................7
Notes to Unaudited Consolidated Financial Statements.....................................................8
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................................................13
PART II. OTHER INFORMATION
Item 1. Legal Proceedings & Environmental Issues................................................................32
Item 2. Changes in Securities...................................................................................33
Item 3. Defaults Upon Senior Securities.........................................................................33
Item 4. Submission of Matters to a Vote of Security Holders.....................................................33
Item 5. Other Information.......................................................................................33
Item 6. Exhibits and Reports on Form 8-K........................................................................34
</TABLE>
2
<PAGE> 3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
HS RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 2000 AND DECEMBER 31, 1999
ASSETS
<TABLE>
<CAPTION>
September 30,
2000 December 31,
(Unaudited) 1999
-------------- --------------
(In thousands)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 1,349 $ 518
Margin deposits 1,856 935
Accounts receivable
Oil and gas sales 47,242 31,602
Trading and transportation 29,027 18,518
Trade 11,375 3,089
Ad valorem and severance taxes 10,251 11,845
Other 5,374 4,366
Lease and well equipment inventory, at cost 1,018 1,249
Prepaid expenses and other 8,636 3,966
Notes receivable from officers for exercise of stock options
and issuance of common stock (Note 6) 861 1,574
-------------- --------------
Total current assets 116,989 77,662
-------------- --------------
OIL AND GAS PROPERTIES, AT COST, USING THE SUCCESSFUL EFFORTS METHOD
Undeveloped acreage 95,876 99,358
Costs subject to depreciation, depletion and amortization 969,972 892,976
Less accumulated depreciation, depletion and amortization (269,954) (227,691)
-------------- --------------
Net oil and gas properties 795,894 764,643
-------------- --------------
GAS GATHERING AND TRANSPORTATION FACILITIES,
at cost, net of accumulated depreciation of $4,127 and
$2,016 at September 30, 2000 and December 31, 1999, respectively 59,211 52,611
-------------- --------------
OTHER ASSETS
Deferred charges and other, net 8,198 9,673
Mark-to-market receivable relating to trading activity 3,375 397
Office and transportation equipment and other property,
net of accumulated depreciation of $6,230 and
$6,552 at September 30, 2000 and December 31, 1999, respectively 2,912 3,040
Notes receivable from officers for exercise of stock options
and issuance of common stock (Note 6) -- 812
Goodwill, net of accumulated amortization of $1,530 and
$1,260 at September 30, 2000 and December 31, 1999, respectively 2,070 2,340
-------------- --------------
Total other assets 16,555 16,262
-------------- --------------
TOTAL ASSETS $ 988,649 $ 911,178
============== ==============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
3
<PAGE> 4
HS RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 2000 AND DECEMBER 31, 1999
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
September 30,
2000 December 31,
(Unaudited) 1999
-------------- --------------
(In thousands)
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable
Trade $ 22,971 $ 26,653
Revenue 56,906 36,897
Gas purchases 18,578 9,290
Accrued expenses
Ad valorem and production taxes 12,189 10,624
Interest 12,206 5,233
Other 6,476 5,389
Income taxes payable 1,088 958
Payable to KMI 22,317 19,551
-------------- --------------
Total current liabilities 152,731 114,595
-------------- --------------
ACCRUED AD VALOREM TAXES AND OTHER 20,867 15,804
-------------- --------------
PAYABLE TO KMI, NET OF CURRENT PORTION 10,457 27,556
-------------- --------------
LONG-TERM BANK DEBT 222,000 227,000
-------------- --------------
9 7/8% SENIOR SUBORDINATED NOTES,
due 2003, net of unamortized discount of $185 and
$229 at September 30, 2000 and December 31, 1999, respectively 74,815 74,771
-------------- --------------
9 1/4% SERIES A SENIOR SUBORDINATED NOTES,
due 2006, net of unamortized discount of $476 and
$534 at September 30, 2000 and December 31, 1999, respectively 149,524 149,466
-------------- --------------
9 1/4% SERIES B SENIOR SUBORDINATED NOTES,
due 2006, net of unamortized discount of $3,254 and $3,653
at September 30, 2000 and December 31, 1999, respectively 81,746 81,347
-------------- --------------
DEFERRED INCOME TAXES 75,033 53,246
-------------- --------------
COMMITMENTS AND CONTINGENCIES
-------------- --------------
STOCKHOLDERS' EQUITY
Preferred stock -- --
Common stock, $.001 par value, 50,000 shares authorized;
19,792 and 19,528 shares issued and outstanding
at September 30, 2000 and December 31, 1999, respectively 20 20
Additional paid-in capital 197,655 191,406
Retained earnings (deficit) 21,027 (14,302)
Deferred compensation (3,780) (1,981)
Treasury stock, at cost, 1,411 and 731 shares at September 30, 2000
and December 31, 1999, respectively (13,446) (7,750)
-------------- --------------
Total stockholders' equity 201,476 167,393
-------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 988,649 $ 911,178
============== ==============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
4
<PAGE> 5
HS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS AND NINE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999
(UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
(In thousands, except per share amounts)
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales $ 66,163 $ 43,473 $ 187,891 $ 116,280
Trading and transportation 32,857 11,596 76,683 32,874
Gathering and transmission system revenues 3,199 -- 9,563 --
Other gas revenues 2,295 2,281 6,697 7,323
Income from interest in gathering plant 549 -- 1,272 --
Interest income and other 1,085 141 2,337 411
---------- ---------- ---------- ----------
Total revenues 106,148 57,491 284,443 156,888
---------- ---------- ---------- ----------
EXPENSES
Production taxes 6,108 3,372 17,350 7,657
Lease operating 7,438 6,776 22,502 20,936
Cost of trading and transportation 31,059 10,997 72,851 31,442
Gathering and transmission system
operating expenses 1,346 -- 3,925 --
Depreciation, depletion and amortization 14,497 13,070 44,518 40,472
Exploratory and abandonment 4,423 4,359 10,951 9,098
Geological and geophysical 2,756 1,293 9,967 4,780
Impairment and loss (gain) on sales of oil
and gas properties 2,220 (2,328) 2,382 (1,228)
General and administrative 1,265 1,467 5,321 3,942
Interest 12,378 10,717 37,231 31,657
---------- ---------- ---------- ----------
Total expenses 83,490 49,723 226,998 148,756
---------- ---------- ---------- ----------
INCOME BEFORE PROVISION FOR INCOME TAXES 22,658 7,768 57,445 8,132
PROVISION FOR INCOME TAXES 8,862 2,959 22,116 3,098
---------- ---------- ---------- ----------
NET INCOME $ 13,796 $ 4,809 $ 35,329 $ 5,034
========== ========== ========== ==========
BASIC EARNINGS PER SHARE $ 0.75 $ 0.26 $ 1.91 $ 0.27
========== ========== ========== ==========
DILUTED EARNINGS PER SHARE $ 0.72 $ 0.25 $ 1.84 $ 0.27
========== ========== ========== ==========
WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 18,333 18,798 18,539 18,664
========== ========== ========== ==========
WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING ASSUMING DILUTION 19,130 19,131 19,159 18,815
========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
5
<PAGE> 6
HS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999 AND 1998
AND THE NINE MONTHS ENDED SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
Common Stock Additional Retained Treasury Stock
--------------- Paid-In Earnings Deferred -------------------
Shares Amount Capital (Deficit) Compensation Shares Amount
------ ------ ---------- --------- ------------ ------- ---------
(In thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1997 18,655 $ 19 $ 183,191 $ (7,372) $ (144) (160) $ (2,217)
Purchase of treasury stock -- -- -- -- -- (722) (6,524)
Transfer of treasury stock to 40l(k) Plan -- -- 7 -- -- 39 542
Issuance of treasury stock
for exercise of options
including income tax benefit -- -- (115) -- -- 42 583
Issuance of restricted stock 32 -- 428 -- (428) -- --
Amortization of deferred compensation -- -- -- -- 307 -- --
Issuance of performance shares 106 -- 1,534 -- (1,534) -- --
Exercise of stock options, including
income tax benefit 337 -- 3,201 -- -- -- --
Restricted stock forfeited (3) -- (50) -- 50 -- --
Net loss -- -- -- (18,616) -- -- --
------ ------ ---------- --------- ------------ ------- ---------
BALANCE, DECEMBER 31, 1998 19,127 19 188,196 (25,988) (1,749) (801) (7,616)
Purchase of treasury stock -- -- -- -- -- (128) (2,055)
Transfer of treasury stock to 40l(k) Plan -- -- 50 -- -- 75 712
Issuance of treasury stock
for exercise of options
including income tax benefit -- -- 492 -- -- 123 1,209
Issuance of restricted stock 34 -- 301 -- (301) -- --
Amortization of deferred compensation -- -- -- -- 1,067 -- --
Issuance of performance shares 132 1 997 -- (998) -- --
Issuance of common stock 235 -- 1,370 -- -- -- --
Net income -- -- -- 11,686 -- -- --
------ ------ ---------- --------- ------------ ------- ---------
BALANCE, DECEMBER 31, 1999 19,528 20 191,406 (14,302) (1,981) (731) (7,750)
Purchase of treasury stock -- -- -- -- -- (161) (3,219)
Exercise of warrants 6 -- 40 -- -- -- --
Transfer of treasury stock to 40l(k) Plan -- -- 385 -- -- 62 672
Issuance of treasury stock
for exercise of options
including income tax benefit -- -- 745 -- -- 151 1,679
Restricted stock and performance shares
forfeited (9) -- (58) -- 58 -- --
Amortization of deferred compensation -- -- -- -- 1,120 -- --
Exercise of equity swap -- -- -- -- -- (732) (4,828)
Issuance of restricted stock
and performance shares 125 -- 2,977 -- (2,977) -- --
Exercise of stock options 142 -- 2,160 -- -- -- --
Net income -- -- -- 35,329 -- -- --
------ ------ ---------- --------- ------------ ------- ---------
BALANCE, SEPTEMBER 30, 2000 (UNAUDITED) 19,792 $ 20 $ 197,655 $ 21,027 $ (3,780) (1,411) $ (13,446)
====== ====== ========== ========= ============ ======= =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
6
<PAGE> 7
HS RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000 AND 1999
(UNAUDITED)
<TABLE>
<CAPTION>
September 30,
-----------------------
2000 1999
---------- ----------
(In thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 35,329 $ 5,034
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization 44,518 40,472
Depreciation expense offset against revenue 1,072 --
Impairment and loss (gain) on sales of oil and gas properties 2,382 (1,228)
Surrendered and expired acreage 4,269 2,960
Amortization of deferred charges, debt issue costs
and deferred compensation 3,183 3,308
Transfer of treasury stock to 401(k) Plan 1,057 763
Deferred income tax provision 21,788 3,038
Increase in accounts receivable (33,849) (19,172)
Increase in accounts payable and accrued expenses 49,125 17,458
Decrease in deferred revenue, net -- (7,436)
Other (8,524) (2,914)
---------- ----------
Net cash provided by operating activities 120,350 42,283
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration, development and leasehold costs (72,296) (48,856)
Purchase of proved and unproved properties (7,496) --
Gas gathering and transmission facilities additions (8,711) (460)
Other property additions (614) (1,148)
Net (purchase) proceeds from the sale of oil and gas properties (578) 3,384
Decrease in property related payables (8,693) (6,227)
---------- ----------
Net cash used in investing activities (98,388) (53,307)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from bank debt 131,000 52,000
Repayments of bank debt (136,000) (48,000)
Repayment of KMI debt (14,333) --
Issuance of common stock -- 611
Exercise of options and warrants 4,625 641
Purchase of treasury stock and exercise of equity swap (8,047) (767)
Payment of officer note and interest 1,624 823
---------- ----------
Net cash (used in) provided by financing activities (21,131) 5,308
---------- ----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 831 (5,716)
Cash and cash equivalents, beginning of year 518 9,659
---------- ----------
Cash and cash equivalents, end of year $ 1,349 $ 3,943
---------- ----------
SUPPLEMENTAL CASH FLOW DISCLOSURE
Interest paid, net of capitalized interest $ 28,157 $ 23,216
Cash paid for income taxes, net of reimbursements $ 251 $ 729
========== ==========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
7
<PAGE> 8
HS RESOURCES, INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. GENERAL
HS Resources, Inc., a Delaware corporation, was organized in January 1987. We
directly or through subsidiaries, acquire, develop, explore for, exploit and
produce oil and gas. Our primary properties are located in the Denver-Julesburg
("D-J") Basin, the onshore area of the Texas-Louisiana Gulf Coast, and to a
lesser extent, the Northern Rocky Mountains and the Mid-Continent. Through our
wholly-owned subsidiary, HS Gathering, L.L.C., we gather and transport our own
and third party gas. Through our subsidiary, HS Energy Services, Inc. ("HSES"),
we market our own gas production, market gas owned by third parties and actively
trade both physical and financial positions in the gas commodities market. The
interim financial data presented here are unaudited; however, all adjustments,
which are of a normal and recurring nature, have been made that are, in the
opinion of management, necessary for a fair statement of our financial position
at September 30, 2000, and our results of operations and cash flows for the
interim periods presented. Because of various factors, results of operations for
these periods are not necessarily indicative of results to be expected for the
full year. For a more complete understanding of our operations and financial
position, these statements should be read in conjunction with audited financial
statements and notes thereto included in our December 31, 1999 Report on Form
10-K filed with the Securities and Exchange Commission on March 24, 2000.
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUCCESSFUL EFFORTS. We utilize the successful efforts method of accounting for
our oil and gas properties. Consequently, leasehold costs are capitalized when
incurred. Unproved properties are assessed periodically within specific
geographic areas, and impairments in value are charged to expense. Exploratory
costs, geological and geophysical expenses and delay rentals are charged to
expense as incurred. Exploratory drilling costs are initially capitalized, but
charged to expense if and when the well is determined to be unsuccessful. Costs
of developmental dry holes and proved leaseholds are amortized on the
unit-of-production method based on proved reserves and calculated on a
field-by-field basis. The depreciation of capitalized drilling costs is also
based on the unit-of-production method using proved developed reserves on a
field-by-field basis.
FINANCIAL INSTRUMENTS. We engage in price and location risk management
activities for both hedging and trading purposes. We engage in hedging
activities to manage our exposure to price and location risks in the marketing
of our oil and gas production and, in the case of our marketing activities,
third party gas. Gains and losses on hedging positions are deferred and
recognized in the period the underlying physical transactions occur in "oil and
gas sales" (for company-owned production) and "trading and transportation
revenues" (for third party gas). Activities for trading purposes are accounted
for
8
<PAGE> 9
HS RESOURCES, INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
using the mark-to-market method. Under this method, changes in the market value
of outstanding financial instruments are recognized as a gain or loss in the
period of change on a net basis in "trading and transportation revenues." The
market prices used to value these transactions reflect management's best
estimate considering various factors including closing exchange and
over-the-counter quotations, time value and volatility factors underlying the
commitments. The values are adjusted to reflect the potential impact of
liquidating our position in an orderly manner over a reasonable period
of time under present market conditions. In the event energy related financial
instruments are terminated prior to the period of physical delivery of the items
being hedged, the gains or losses on the energy related financial instruments at
the time of the termination remain deferred until the period of physical
delivery unless both the energy related financial instruments and the items
being hedged result in a loss. If this occurs, the loss is recorded immediately.
In December 1998, the Emerging Issues Task Force reached consensus on Issue No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" ("EITF Issue 98-10"). EITF Issue 98-10 requires energy trading
contracts to be recorded at fair value on the balance sheet, with changes in
fair value included in earnings. In accordance with EITF Issue 98-10 we
record energy trading contracts at fair value on the balance sheet, with the
changes in fair value included in earnings.
NOTE 3. PRO FORMA STATEMENTS
On November 26, 1999, we acquired certain gas gathering and transmission assets,
the Wattenberg Gathering and Transmission System ("WGS"), from Kinder Morgan,
Inc. and affiliated entities ("KMI") for an adjusted purchase price of
approximately $48 million plus the future assumption of an operating lease which
had a present value of $19 million.
WGS consists of a low pressure gathering system and a high pressure transmission
system. The low pressure gathering system consists of more than 1,500 miles of
pipeline and 3,000 horsepower of compression, located in five northeastern
Colorado counties. Gas is delivered to the inlet of the high pressure
transmission system, which consists of almost 60 miles of high pressure pipeline
and almost 40,000 horsepower of compression. The acquisition is being accounted
for using the purchase method of accounting. Along with the system, we acquired
a 6.9% interest in the BP Amoco Wattenberg Gas Processing Plant, and a right of
first refusal to purchase the remaining interest in the plant.
The following table sets forth our condensed unaudited pro forma operating
results for the nine months ended September 30, 1999. The condensed pro forma
operating results assume the acquisition of WGS from KMI had occurred on January
1, 1999. The condensed pro forma results are not necessarily indicative of the
results of operations had the transaction been consummated on January 1, 1999,
and may not necessarily be indicative of future performance. Amounts in
thousands, except per share amounts.
9
<PAGE> 10
HS RESOURCES, INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
1999
(Unaudited)
-----------------
<S> <C>
Revenues $ 171,393
Net income $ 9,519
Diluted earnings per share $ 0.51
Weighted average number of common
shares outstanding assuming dilution 18,815
</TABLE>
NOTE 4. ISSUANCE OF PERFORMANCE SHARES
In May 2000, our stockholders approved the 2000 Performance and Equity Incentive
Plan (the "Plan"). The Plan allows for the issuance of performance shares to
employees, officers and directors. Accelerated vesting of such shares is
dependent on our attainment of defined performance goals. These shares have a
base vesting schedule over nine years with accelerated vesting to occur no
earlier than one-fourth of the shares in each of the first four years. In the
second quarter of 2000, we issued 100,500 performance shares and recorded
deferred compensation of approximately $2.5 million, which is being amortized
based on management's evaluation regarding the attainment of the defined
performance goals.
NOTE 5. NEWLY ISSUED ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). The
date of this statement was recently amended by SFAS No. 137 extending the
adoption period to fiscal years beginning after June 15, 2000 and was further
amended by SFAS No. 138 ("SFAS 138") "Accounting for Certain Derivative
Instruments and Certain Hedging Activities." SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability, measured at its fair value. It
also requires that changes in the fair value of a derivative instrument be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows gains and losses associated
with a derivative instrument to offset related results on the hedged item in the
statement of operations, and requires that a company must formally document,
designate and assess the effectiveness of transactions that receive hedge
accounting. SFAS 138 clarifies the concept of normal purchases and sales and
excludes certain items from the provisions of SFAS 133.
We have not yet quantified the impact of adopting SFAS 133 on our financial
statements and will adopt the provisions of this statement on January 1, 2001.
However, SFAS 133 could increase volatility in earnings and other comprehensive
income.
10
<PAGE> 11
HS RESOURCES, INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 6. RELATED PARTY TRANSACTIONS
In February 1999, we instituted the 1999 Non-Compensatory Stock Purchase Plan.
This plan is designed to enable our officers to purchase stock at fair market
value in transactions exempt from Section 16(b) of the Securities Exchange Act
of 1934. Five hundred thousand shares of common stock have been allocated to
the plan. The plan is administered by the Compensation Committee of the Board
of Directors. As of September 30, 2000, 235,000 shares of common stock had been
purchased at prices ranging from $5.625 to $6.50. In connection with the stock
purchases, 76,000 shares were purchased for cash. The remaining shares were
purchased with the officers paying 15% of the purchase price in cash, and the
remainder in the form of full recourse promissory notes. The notes mature on
March 3, 2001 and bear interest at the annual rate of 8.5%.
In June 1998, in connection with the exercise of stock options, certain of our
officers issued to us full recourse notes in the amount of $2.1 million. The
notes and accrued interest were due and payable to us on or before June 1, 2000.
In the third quarter of 1999, principal and accrued interest in the amount of
$823,295 was repaid. All remaining principal and accrued interest on these notes
was repaid on or before June 1, 2000.
NOTE 7. TOTAL RETURN EQUITY SWAPS
In 1999, we entered into three total return equity swap agreements with
financial institutions. Under the terms of the first agreement, entered into on
February 25, 1999, the financial institution acquired approximately 732,000
shares of our common stock from another investor at a price of $6.0625 per
share. On April 20, 2000 we repurchased the shares for approximately
$4.5 million and retired them into treasury stock.
On May 24, 1999 we entered into a second agreement whereby the financial
institution acquired 100,000 shares of our common stock from another investor at
a price of $11.9875 per share. In addition, on December 1, 1999, we entered into
a third agreement whereby another financial institution agreed to acquire on the
open market approximately 300,000 shares of our common stock at current market
prices over a three month period beginning December 2, 1999. As of March 2000,
the financial institution had acquired 308,100 shares at a weighted average
price of $14.55 per share. In October 2000, we repurchased the 408,100 shares
subject to the second and third agreements for approximately $5.7 million and
retired the shares into treasury stock.
11
<PAGE> 12
HS RESOURCES, INC.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 8. BUSINESS SEGMENT INFORMATION
We are an independent energy company engaged in the following activities:
o acquisition, development, exploitation, exploration and
production of oil and gas
o transportation, marketing and trading of oil and gas and oil
and gas financial derivative instruments.
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
(In thousands) 2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Oil and gas sales D-J Basin $ 49,117 $ 39,423 $ 151,825 $ 110,682
Oil and gas sales Gulf Coast 19,245 6,282 42,535 12,754
Oil and gas sales Mid-Continent and Northern Rockies 95 49 227 167
Gas gathering and transmission facilities 3,748 -- 10,835 --
Trading and transportation 85,088 47,800 209,561 117,812
Intersegment eliminations (52,231) (36,205) (132,877) (84,938)
---------- ---------- ---------- ----------
$ 105,062 $ 57,349 $ 282,106 $ 156,477
========== ========== ========== ==========
OPERATING INCOME (LOSS):
D-J Basin $ 24,725 $ 17,938 $ 77,037 $ 45,329
Gulf Coast 11,144 (204) 19,207 (2,392)
Mid-Continent and Northern Rockies (4,287) 1,826 (7,601) 145
Gas gathering and transmission facilities 1,085 -- 2,503 --
Trading and transportation 2,688 1,138 5,975 3,107
Intersegment eliminations (998) (647) (2,467) (1,999)
---------- ---------- ---------- ----------
OPERATING INCOME 34,357 20,051 94,654 44,190
Other income and expense (11,699) (12,283) (37,209) (36,058)
---------- ---------- ---------- ----------
INCOME BEFORE INCOME TAXES $ 22,658 $ 7,768 $ 57,445 $ 8,132
========== ========== ========== ==========
IDENTIFIABLE ASSETS (NET) (AT SEPTEMBER 30):
Oil and gas properties D-J Basin $ 747,176 $ 721,095 $ 747,176 $ 721,095
Oil and gas properties Gulf Coast 42,622 27,984 42,622 27,984
Oil and gas properties Mid-Continent and Northern Rockies 6,967 5,407 6,967 5,407
Gas gathering and transmission facilities 59,211 4,507 59,211 4,507
Trading and transportation 2,152 2,549 2,152 2,549
Corporate 1,960 2,260 1,960 2,260
---------- ---------- ---------- ----------
$ 860,088 $ 763,802 $ 860,088 $ 763,802
========== ========== ========== ==========
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE:
Oil and gas properties D-J Basin $ 11,956 $ 11,835 $ 37,777 $ 37,121
Oil and gas properties Gulf Coast 1,949 879 4,950 2,134
Oil and gas properties Mid-Continent and Northern Rockies 24 8 67 23
Gas gathering and transmission facilities 256 -- 798 --
Trading and transportation 108 108 324 324
Corporate 204 240 602 870
---------- ---------- ---------- ----------
$ 14,497 $ 13,070 $ 44,518 $ 40,472
========== ========== ========== ==========
CAPITAL EXPENDITURES AND ACQUISITIONS:
Oil and gas properties D-J Basin $ 13,691 $ 15,496 $ 56,732 $ 36,780
Oil and gas properties Gulf Coast 5,598 3,409 20,713 11,214
Oil and gas properties Mid-Continent and Northern Rockies 210 630 2,459 1,724
Gas gathering and transmission facilities 6,899 282 8,711 460
Trading and transportation -- 2 13 56
Corporate 313 50 489 229
---------- ---------- ---------- ----------
$ 26,711 $ 19,869 $ 89,117 $ 50,463
========== ========== ========== ==========
</TABLE>
12
<PAGE> 13
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
GENERAL. Our strategy centers around consolidation of assets in the
Denver-Julesburg ("D-J") Basin, coupled with exploitation and exploration in our
core areas. We use a technology-oriented approach to exploitation and
exploration designed to reduce risk and maximize efficiencies. We currently
operate primarily in three core areas: the D-J Basin, the Gulf Coast and, to a
lesser extent, the Northern Rockies. For the nine months ended September 30,
2000, approximately 84% of our production (on an energy equivalent basis) came
from the D-J Basin and 16% from the Gulf Coast. We intend to continue to pursue
certain technology-oriented exploration projects and other activities in other
regions, including the Mid-Continent. We also intend to continue our
strategically important and historically profitable presence in the gas
marketing, trading and transportation business through our wholly-owned
subsidiary, HSES. HSES provides opportunities for us to enhance our operating
margins on gas production from each of our producing areas and from production
we market on behalf of other oil and gas producers.
In December 1999 we furthered our consolidation strategy in the D-J Basin by
acquiring from KMI the WGS assets for an adjusted purchase price of
approximately $48 million, plus the assumption of an operating lease which had a
net present value of $19 million. As part of this transaction, we also purchased
a 6.9% interest in the BP Amoco Wattenberg Gas Processing Plant, and a right of
first refusal to purchase the remaining interest in the plant. The transaction
is scheduled to close in December 2001, however the acquisition is recorded in
our financial statements as of December 1, 1999 using the purchase method of
accounting. WGS consists of a low pressure gathering system and a high pressure
transmission system. The low pressure gathering system consists of more than
1,500 miles of pipeline and 3,000 horsepower of compression, located in five
northeastern Colorado counties. Gas is delivered to the inlet of the high
pressure transmission system, which consists of almost 60 miles of high pressure
pipeline and almost 40,000 horsepower of compression. This purchase has given us
operational control over the gathering of a large percentage of our gas
production. By operating the pipeline we are better positioned to anticipate and
alleviate any gathering system bottlenecks that might adversely affect our D-J
Basin exploitation program and the production of other operators.
OIL AND GAS PRICES. Profitability in the United States oil and gas industry
fluctuates widely due in part to fluctuating commodity prices and related
changes in rates of reinvestment by industry participants. In early 1999, United
States natural gas prices and international crude oil prices were very low,
resulting in significant reductions in the operating and financial margins of
oil and gas producers. Additionally, low oil prices had a depressing effect on
the price of liquids recovered from natural gas during this time period. Thus,
the low oil price of early 1999 further diminished the overall price received
for our gas production. In April 1999, both oil and gas prices began to recover,
and have continued to increase in 2000. This resulted in HSR realizing for the
three months ended September 30, 2000 an average price per barrel of oil
("Bbl"), excluding hedging effects, of $30.90 compared to $20.14 for the
comparable period in 1999, and $11.43 for the three months ended March 31, 1999.
Natural gas prices per thousand cubic feet of gas ("Mcf"), excluding hedging
13
<PAGE> 14
effects, were $4.12 for the three months ended September 30, 2000 compared to
$2.42 in the comparable period in 1999 and $1.68 for the three months ended
March 31, 1999.
At December 31, 1999, approximately 82% of our proved producing reserves
consisted of gas, of which 97% were located in the D-J Basin. The absolute level
and volatility of gas prices, particularly in the D-J Basin, have a material
impact on us. Historically, the price of D-J Basin gas (on a Btu-equivalent
basis) has been linked closely to the Colorado Interstate Gas Company ("CIG")
pipeline Rocky Mountain Index. This remains the case during the lower demand
summer months (generally April through October). More recently, however, as a
result of increased pipeline capacity into and out of the D-J Basin, a
transportation cost advantage for deliveries into the Public Service Company of
Colorado ("PSCO") market, and seasonal fluctuations, the price more closely
tracks Mid-Continent indices during the higher demand winter periods (generally
November through March).
Gas and oil prices remain strong as of the date of this report. However, we
cannot predict future trends in gas or oil prices. The uncertainty concerning
the price of oil and gas remains a dominant and unpredictable factor in our
profitability.
RESULTS OF OPERATIONS. During 2000 we continued our drilling and development
activities to exploit our opportunities in the D-J Basin. We also continued our
exploitation and exploration activities in the Gulf Coast region. Future results
will be significantly affected by our exploration, exploitation and development
activities as well as fluctuations in oil and gas prices.
Comparative operating results by business segment, consolidated other income,
expenses and income taxes are presented below. Segment operating revenues, costs
and expenses are before intersegment eliminations.
14
<PAGE> 15
COMPARISON OF THREE MONTHS AND NINE MONTHS ENDED
SEPTEMBER 30, 2000 AND 1999
D-J BASIN
OIL AND GAS SALES
(IN THOUSANDS EXCEPT AVERAGE PRICES)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Production:
Oil (Bbl) 532 513 1,695 1,596
Gas (Mcf) 13,108 13,072 41,366 39,468
Mcfe 16,299 16,149 51,539 49,044
Boe 2,717 2,692 8,590 8,174
Prices(1):
Average realized oil price ($/Bbl) $ 26.95 $ 20.02 $ 22.96 $ 15.39
Average realized gas price ($/Mcf) $ 2.48 $ 2.06 $ 2.57 $ 2.00
Operating Revenues:
Oil and gas sales $ 46,823 $ 37,142 $ 145,128 $ 103,359
Other gas revenues 2,294 2,281 6,697 7,323
---------- ---------- ---------- ----------
49,117 39,423 151,825 110,682
---------- ---------- ---------- ----------
Operating Costs and Expenses:
Production taxes 4,951 3,004 14,704 6,899
Lease operating 7,129 6,531 21,548 20,382
Depreciation, depletion
and amortization 11,956 11,835 37,777 37,121
Exploratory and abandonment 286 92 423 657
Geological and geophysical 70 119 336 222
Impairment and (gain) loss on
sales of oil and gas properties -- (96) -- 72
---------- ---------- ---------- ----------
24,392 21,485 74,788 65,353
---------- ---------- ---------- ----------
Operating Income $ 24,725 $ 17,938 $ 77,037 $ 45,329
========== ========== ========== ==========
</TABLE>
(1) Includes effects of hedging activities -- see "LIQUIDITY AND CAPITAL
RESOURCES -- HEDGING ACTIVITIES."
15
<PAGE> 16
GENERAL. We have been active in the D-J Basin for almost 20 years. Over the
years we have sought to consolidate our position there by acquiring properties
and conducting active exploitation programs. More recent acquisitions include
the June 1996 acquisition of Basin Exploration, Inc.'s D-J Basin properties, the
December 1997 acquisition of Amoco Production Company's D-J Basin assets, the
1999 acquisition of WGS and the 2000 acquisition of interests in 60 wells and
associated mineral rights for approximately $7.1 million. For the nine months
ended September 30, 2000 and 1999 exploitation programs consisted of
approximately 300 and 250 separate activities, respectively.
OIL AND GAS REVENUES. Our D-J Basin oil and gas production and revenues have
increased for the quarter and nine months ended September 30, 2000 compared to
prior year periods, primarily as the result of the success of our ongoing
exploitation and development activities and increased product prices. Production
for the quarter ended September 30, 2000 increased only slightly compared to the
comparable prior year quarter mainly due to deliverability constraints resulting
from high line pressure and system maintenance closures. We have a significant
compression expansion project underway on WGS which will add substantial
throughput capacity and reduce system line pressures. We expect to have
additional deliverability available in mid-December with completion of the
system expansion by April 2001. Other gas revenues related to the sale of tax
credits decreased for the nine months ended September 30, 2000 and remained
relatively flat for the quarter ended September 30, 2000, compared to the prior
year periods mainly due to normal production declines. Oil and gas revenues in
the quarter and for the nine months ended September 30, 2000 were generally
reduced as a result of hedging activities - see "LIQUIDITY AND CAPITAL RESOURCES
- HEDGING ACTIVITIES."
PRODUCTION EXPENSES. Total lease operating expense ("LOE") increased for the
quarter and nine months ended September 30, 2000 compared to the prior year
periods. LOE per Mcfe was $0.44 and $0.40 for quarters ended September 30, 2000
and 1999, respectively. LOE per Mcfe was $0.42 for both the nine months ended
September 30, 2000 and 1999. The increase in costs was due to a larger number of
producing wells and an increase in workover costs. Production taxes increased
for the quarter and nine months ended September 30, 2000 compared to the prior
year periods. This increase was due to higher realized product prices for the
quarter and nine months ended September 30, 2000.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization ("DD&A"), a non-cash expense, increased for the quarter and nine
months ended September 30, 2000 compared to the prior year periods mainly due to
an increase in production. The weighted average depletion rate per Mcfe for the
D-J Basin was $0.73 for the three months ended September 30, 2000 and 1999. For
the nine months ended September 30, 2000 and 1999 the weighted average depletion
rate per Mcfe for the D-J Basin was $0.73 and $0.75, respectively. We annually
adjust our DD&A rate based on year-end engineering and, if material changes in
our reserves warrant, on an interim basis.
EXPLORATORY AND ABANDONMENT COSTS. Exploratory and abandonment costs include the
costs of exploratory dry holes, delay rentals, plugging and abandonment ("P&A")
costs, expired acreage and salaries and overhead ("overhead") costs directly
related to exploratory activities. Exploratory and abandonment costs increased
slightly for the quarter ended September 30, 2000 mainly due to an increase in
expired acreage. For the nine months ended
16
<PAGE> 17
September 30, 2000, exploratory and abandonment costs decreased due to a
decrease in exploratory dry holes and P&A costs.
GEOLOGICAL AND GEOPHYSICAL COSTS. Geological and geophysical ("G&G") costs
include costs for seismic activity as well as overhead costs directly
attributable to G&G activity. The increase for the nine months ended September
30, 2000 compared to the prior year period relates to costs associated with an
engineering study to evaluate the feasibility of a gas storage facility.
GULF COAST
OIL AND GAS SALES
(IN THOUSANDS EXCEPT AVERAGE PRICES)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Production:
Oil (Bbl) 172 69 439 173
Gas (Mcf) 2,826 1,740 7,170 4,005
Mcfe 3,859 2,153 9,801 5,043
Boe 643 359 1,634 841
Prices(1):
Average realized oil price ($/Bbl) $ 31.54 $ 20.21 $ 29.92 $ 16.62
Average realized gas price ($/Mcf) $ 4.89 $ 2.81 $ 4.10 $ 2.47
Operating Revenues:
Oil and gas sales $ 19,245 $ 6,282 $ 42,535 $ 12,754
Operating Costs and Expenses:
Production taxes 1,148 349 2,627 714
Lease operating 263 201 777 396
Depreciation, depletion
and amortization 1,949 879 4,950 2,134
Exploratory and abandonment 2,855 4,079 9,004 7,995
Geological and geophysical 1,886 978 5,862 3,907
Impairment and loss on sale
of oil and gas properties -- -- 108 --
---------- ---------- ---------- ----------
8,101 6,486 23,328 15,146
---------- ---------- ---------- ----------
Operating Income (Loss) $ 11,144 $ (204) $ 19,207 $ (2,392)
========== ========== ========== ==========
</TABLE>
(1) There were no hedging activities affecting Gulf Coast production in
2000 or 1999.
17
<PAGE> 18
GENERAL. Over the past several years, the majority of our Gulf Coast activities
focused on acquiring, processing and interpreting 3-D seismic information,
acquiring leasehold interests, and drilling in our project areas. During 2000 we
expect to continue to increase our level of Gulf Coast drilling activities on
prospects that we have identified through our 3-D seismic programs.
OIL AND GAS REVENUES. Oil and gas revenues increased significantly for the
quarter and nine months ended September 30, 2000 compared to the prior year
periods due to an increase both in production and in product prices. As of
September 30, 2000 we had interests in 49 gross (14.47 net) wells compared to 34
gross (7.89 net) wells as of September 30, 1999. Of the total wells drilled to
date, 7 gross (3.4 net) are currently awaiting pipeline hookup.
PRODUCTION EXPENSES. Aggregate LOE increased for the quarter and nine months
ended September 30, 2000 compared to the prior year periods because of the
greater number of producing wells and an increase in workover costs. LOE per
Mcfe was $0.07 compared to $0.09 for the quarters ended September 30, 2000 and
1999, respectively. LOE per Mcfe was $0.08 for both the nine months ended
September 30, 2000 and 1999. Production taxes increased for the quarter and nine
months ended September 30, 2000 compared to the prior year periods as a result
of increased production and higher realized product prices.
DEPRECIATION, DEPLETION AND AMORTIZATION. Total DD&A increased for the quarter
and nine months ended September 30, 2000 compared to the prior year periods as a
result of an increase in production and an increase in the DD&A rate. The
weighted average DD&A rate per Mcfe in the Gulf Coast increased to $0.51 from
$0.41 for the three months ended September 30, 2000 and 1999, respectively. For
the nine months ended September 30, 2000 and 1999, DD&A per Mcfe increased to
$0.51 from $0.42, respectively.
EXPLORATORY AND ABANDONMENT COST. During the quarters ended September 30, 2000
and 1999 we expensed $0.8 million and $0.9 million for expired acreage, $1.4
million and $2.4 million for exploratory dry holes, $0.5 million and $0.5
million for delay rentals and $0.2 million and $0.3 million for overhead costs.
In the nine months ended September 30, 2000 and 1999, we expensed $3.8 million
and $2.8 million for expired acreage, $1.3 million and $1.1 million in delay
rentals, $2.8 million and $3.4 million for exploratory dry holes and $1.1
million and $0.7 million for overhead costs directly related to exploratory
activities.
GEOLOGICAL AND GEOPHYSICAL COSTS. Of total G&G costs, we incurred $1.6 million
and $0.7 million for the quarter ended September 30, 2000 and 1999,
respectively, for seismic permits and processing costs in the Gulf Coast. The
remaining G&G of $0.3 million and $0.3 million relates to overhead costs
directly attributable to G&G activity. For the nine months ended September 30,
2000 and 1999 we incurred $4.5 million and $3.0 million, respectively for
seismic permits and processing costs in the Gulf Coast. The remaining G&G of
$1.3 million and $0.9 million relates to overhead costs directly attributable to
G&G activity.
18
<PAGE> 19
IMPAIRMENT AND LOSS ON SALES OF OIL AND GAS PROPERTIES. For the nine months
ended September 30, 2000, we recorded a loss of $108,000 on the sale of one
well.
MID-CONTINENT AND NORTHERN ROCKIES
OIL AND GAS SALES
(IN THOUSANDS EXCEPT AVERAGE PRICES)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Production:
Oil (Bbl) 1 1 1 1
Gas (Mcf) 25 23 70 111
Mcfe 26 25 74 115
Boe 4 4 12 19
Prices:
Average realized oil price ($/Bbl) $ 31.74 $ 17.90 $ 27.42 $ 18.40
Average realized gas price ($/Mcf) $ 3.55 $ 1.87 $ 2.97 $ 1.40
Operating Revenues:
Oil and gas sales $ 95 $ 49 $ 227 $ 167
Operating Costs and Expenses:
Production taxes 9 19 19 44
Lease operating 46 44 177 157
Depreciation, depletion
and amortization 24 8 67 23
Exploratory and abandonment 1,283 187 1,523 446
Geological and geophysical 800 196 3,768 652
Impairment and loss (gain) on
sales of oil and gas properties 2,220 (2,231) 2,274 (1,300)
---------- ---------- ---------- ----------
4,382 (1,777) 7,828 22
---------- ---------- ---------- ----------
Operating (Loss) Income $ (4,287) $ 1,826 $ (7,601) $ 145
========== ========== ========== ==========
</TABLE>
GENERAL. Information for this segment includes activity for both the
Mid-Continent and Northern Rockies areas. Our strategy in the Mid-Continent is
to pursue technology-oriented exploration projects with a focus on high volume,
long-life gas prospects. We have acquired extensive acreage in the Northern
Rockies region. Our current strategy is to utilize our acreage
19
<PAGE> 20
position as a vehicle for generating capital expenditures by third party
operators on our acreage.
OIL AND GAS REVENUES. There were virtually no oil and gas revenues in this
segment because of the earlier Mid-Continent property sale and the sale of
properties in the Northern Rockies region.
EXPLORATORY AND ABANDONMENT COSTS. The majority of exploratory and abandonment
costs for the quarter and nine months ended September 30, 2000 and 1999
represent costs incurred for exploratory dry holes, delay rentals, expired
acreage and overhead costs for projects in the Northern Rockies.
GEOLOGICAL AND GEOPHYSICAL COSTS. The increase in G&G costs for the quarter and
nine months ended September 30, 2000 compared to the prior year periods is the
result of an increase in seismic activity in the Mid-Continent project area
mainly due to the acquisition and processing of 3-D seismic data in the Pine
Ridge and West Rainey project areas in Oklahoma.
IMPAIRMENT AND LOSS ON SALE OF OIL AND GAS PROPERTIES. In the third quarter of
2000, we recorded impairment of $1.5 million on several wells in the Northern
Rockies region in accordance with the requirements of successful efforts
accounting. We also recorded a $0.7 million loss relating to the settlement of a
gas imbalance position on a well we previously owned in the Mid-Continent
region.
TRADING AND TRANSPORTATION
(IN THOUSANDS)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Operating Revenues:
Trading and transportation(1) $ 85,088 $ 47,800 $ 209,561 $ 117,812
Operating Costs and Expenses:
Cost of trading and transportation(1) 82,292 46,554 203,262 114,381
Depreciation and amortization 108 108 324 324
---------- ---------- ---------- ----------
82,400 46,662 203,586 114,705
---------- ---------- ---------- ----------
Operating Income $ 2,688 $ 1,138 $ 5,975 $ 3,107
========== ========== ========== ==========
</TABLE>
(1) Includes intercompany revenues and expenses attributable to our volumes
which are marketed by HSES. Such amounts have been eliminated in our
consolidated financial statements.
20
<PAGE> 21
Through our wholly-owned subsidiary, HSES, we market our own gas production as
well as that of third parties. A portion of this gas is sold directly to end
users, while other amounts are used as the equity-gas foundation for a physical
trading business in which gas volumes may be traded several times at different
receipt and delivery points in order to capture the greatest margin possible.
HSES also serves as an intermediary in the execution of financial derivative
instruments for a variety of energy related products and, to a lesser extent,
makes speculative trades for its own account in the commodity and basis markets.
Operating margins increased for the quarter and nine months ended September 30,
2000 compared to 1999 primarily as a result of an increase in the volume of
natural gas marketed. For the quarter and nine months ended September 30, 2000,
gains of $1.7 million and $3.3 million, respectively were recognized in
connection with financial trading activities compared to gains of $0.5 million
and $1.7 million for the quarter and nine months ended September 30, 1999,
respectively.
GAS GATHERING AND TRANSMISSION
(IN THOUSANDS)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Operating Revenues
Gathering and transmission
system revenues $ 3,199 $ -- $ 9,563 $ --
Income from interest in gathering plant 549 -- 1,272 --
---------- ---------- ---------- ----------
3,748 -- 10,835 --
---------- ---------- ---------- ----------
Operating Costs and Expenses
Gathering and transmission system
operating expenses 1,346 -- 3,925 --
Depreciation and amortization 256 -- 798 --
Interest expense 1,061 -- 3,609 --
---------- ---------- ---------- ----------
2,663 -- 8,332 --
---------- ---------- ---------- ----------
Operating Income $ 1,085 $ -- $ 2,503 $ --
========== ========== ========== ==========
</TABLE>
GATHERING AND TRANSMISSION SYSTEM REVENUES AND EXPENSES. Effective December 1,
1999, we took over operation of WGS from Kinder Morgan, Inc. The revenues and
expenses associated with third party gas for the quarter and nine months ended
September 30, 2000 are recorded as gathering and transmission system revenues
and expenses.
During the quarter ended September 30, 2000, WGS transported an average of
approximately 182 MMcf of gas per day. Throughput has increased significantly
since quarter-end to more than 200 MMcf per day as a result of remedial
activities we have undertaken to reduce line pressure, and also due to lower
atmospheric temperatures. Additional compression and other system improvements
which are under way should boost daily capacity on WGS by 20 MMcf
21
<PAGE> 22
per day in mid-December and by up to 50 MMcf per day by April 2001. To
accomplish this goal, we are adding three 1,000 horsepower temporary compressors
and constructing a new 6,000 horsepower compressor station. As part of the
overall WGS system improvement project we are also planning to add a gas
processing facility. This plant is designed to be capable of processing up to 50
MMcf per day while recovering 1,500 barrels of natural gas liquids daily.
Barring permitting or equipment delays, field construction is expected to start
in mid-December, and the plant is expected to be operational by April 2001.
OTHER INCOME AND EXPENSES
(IN THOUSANDS)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Interest income and other $ 1,085 $ 141 $ 2,337 $ 411
General and administrative $ 1,265 $ 1,467 $ 5,321 $ 3,942
Interest $ 11,315 $ 10,717 $ 33,623 $ 31,657
Depreciation $ 204 $ 240 $ 602 $ 870
</TABLE>
INTEREST INCOME AND OTHER INCOME. Interest and other income increased for the
quarter and nine months ended September 30, 2000 compared to the prior year
periods due to interest earned on severance tax refunds.
GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses ("G&A")
reflect costs incurred, net of administrative costs directly attributable to
drilling and well operations (which costs are included in LOE). G&A costs
directly related to geological and geophysical activities and exploratory
activities are included in geological and geophysical costs and exploratory
costs. G&A per Mcfe was $0.06 in the third quarter of 2000 compared to $0.08 in
the third quarter of 1999. For the nine months ended September 30, 2000 and
1999, G&A per Mcfe was $0.09 compared to $0.07. On both an absolute and an Mcfe
basis, G&A increased for the nine months ended September 30, 2000 compared to
the prior year period due to an increase in payroll-related general and
administrative expenses. G&A decreased for the quarter ended September 30, 2000
compared to the prior year period due to differences in timing of costs
incurred.
INTEREST EXPENSE. Interest expense increased for the quarter and nine months
ended September 30, 2000 compared to the prior year periods mainly due to an
increase in the interest rate on our bank debt and interest attributable to the
financing of WGS. For the quarter ended September 30, 2000 and 1999, we
capitalized interest related to undeveloped acreage of $1.6 million and $1.8
million, respectively. For the nine months ended September 30, 2000 and 1999, we
capitalized interest related to undeveloped acreage of $4.9 million and $5.4
million, respectively.
22
<PAGE> 23
INCOME TAXES
(IN THOUSANDS)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Current provision $ -- $ -- $ -- $ --
Deferred provision 8,862 2,959 22,116 3,098
---------- ---------- ---------- ----------
Provision for taxes $ 8,862 $ 2,959 $ 22,116 $ 3,098
========== ========== ========== ==========
Effective tax rate 39.1% 38.1% 38.5% 38.1%
========== ========== ========== ==========
</TABLE>
PROVISION FOR INCOME TAXES. We follow the provisions of Statement of Financial
Accounting Standards ("SFAS") No. 109. Pursuant to SFAS 109, we have recorded a
tax provision based on tax rates in effect during the period. Accordingly, we
accrued taxes at the rate of 39.1% and 38.1% for the quarters ended September
30, 2000 and 1999 and 38.5% and 38.1% for the nine months ended September 30,
2000 and 1999, respectively. Due primarily to significant intangible drilling
costs, which are deductible for income tax purposes, all of our tax provision
is deferred.
LIQUIDITY AND CAPITAL RESOURCES
FINANCING SOURCES. We believe that our current level of debt is manageable under
expected production and pricing levels because our debt is supported by stable,
long-lived producing reserves and by short-term product prices that are
partially hedged at prices that support our bank and other interest
requirements. We expect cash flows from producing activities to be sufficient to
enable us to service our debt for the foreseeable future, absent any major and
prolonged period of low commodity prices or sustained production interruptions.
We have a large number of low-risk, potentially high-return exploitation
projects which should enhance production and cash flow. As part of an overall
financing strategy, we continually evaluate a wide range of future financing
alternatives and are not committed to any particular course. In undertaking any
future financing transactions, we will seek to achieve the optimal capital
structure needed to support our long-term strategic objectives. Any such
financings will reflect market conditions at the time and may include the
issuance of medium or long-term debt, equity, or equity-linked securities.
We currently plan to fund capital expenditures attributable to exploration,
exploitation and development activities primarily out of our expected cash flow
from operations, subject to periodic variation resulting from the timing of
project activities and short-term product price volatility. The borrowing base
under our revolving senior bank credit facility led by The
23
<PAGE> 24
Chase Manhattan Bank is currently $325.0 million. The interest rate under the
Chase facility is the Base Rate plus 0% to 0.625% or LIBOR plus 0.75% to 1.625%.
The borrowing base is based on the review of our reserves by the lending bank
group and their view of future pricing. Under the terms of the Chase facility,
no principal payments are required until December 15, 2002, assuming we maintain
a borrowing base sufficient to support the outstanding loan balance. As of
September 30, 2000, $222.0 million was outstanding under the Chase facility
compared to $227.0 million at December 31, 1999. As of September 30, 2000 and
1999 our ratio of earnings to fixed charges was 2.24x and 1.09x, respectively.
We anticipate that our borrowing capacity under the Chase facility and our
operating cash flow will provide us with adequate financial resources and
flexibility to fund current and ongoing activities, to service our debt and to
meet other financial obligations. The nature of our current development
strategies and other activities provide us with considerable flexibility in
terms of the timing and magnitude of our capital expenditures. If we experience
unforeseen changes in our working capital position or capital resources, we may
revise the capital expenditure program accordingly or alternatively may attempt
to supplement our capital position through, among other things, the issuance of
additional equity, equity-linked or debt securities, the sale or monetization of
properties or by entering into joint venture arrangements.
CAPITAL COMMITMENTS. We continuously evaluate our inventory of drilling
opportunities to develop a growth-oriented portfolio of risk-balanced
development, exploitation and exploration opportunities. On an ongoing basis, we
adjust the amount and allocation of our capital expenditures based on a number
of factors, including seismic results, prospect readiness, product prices,
service company availability and rates, acquisitions and capital position. For
the nine months ended September 30, 2000, we incurred total costs for
exploration, development, leasehold, exploratory and abandonment, geological and
geophysical activities and improvements on WGS of $89.9 million, exclusive of
acquisitions, capitalized interest and overhead costs directly related to
exploratory and G&G activity. We estimate that such expenditures for the year
2000 will be approximately $120 million. These costs will be allocated in
varying amounts primarily to activities in our core geographic areas. A major
component of our capital program relates to our development and gathering
activities in the D-J Basin. We incurred approximately $46.1 million for the
nine months ended September 30, 2000 for leasehold and geological and
geophysical costs and to drill, deepen, recomplete and refrac our D-J Basin
properties as well as $8.7 million on WGS, and we anticipate a total capital
allocation of approximately $60 million to the D-J Basin during 2000.
Another component of our capital program has been to develop our exploitation
and exploration prospects in the onshore portion of the Gulf Coast. For the nine
months ended September 30, 2000, we incurred total expenditures of $28.6 million
for seismic, leasehold and drilling costs in the Gulf Coast. We anticipate
allocating approximately $40 million to the Gulf Coast projects during 2000 for
exploration and development activities including land and seismic.
In our Mid-Continent project area we are acquiring and processing 3-D seismic
data and are preparing to initiate drilling activity on several prospects. One
well was spud in the
24
<PAGE> 25
Mid-Continent project area during the second quarter and is currently awaiting
pipeline hookup. We intend to focus our activity in this area on high volume,
long-life gas prospects. For the nine months ended September 30, 2000, we
incurred $2.5 million for seismic, leasehold and drilling costs in the
Mid-Continent. We anticipate allocating $5 to $6 million to the Mid-Continent
project area during 2000.
Activities in the Northern Rockies are planned to manage risk by utilizing our
extensive acreage positions, operational expertise, and geotechnical ideas to
attract risk capital from partners who also add expertise and other value to
the project. We believe our projects have substantial flexibility in terms of
timing, as a result of long-term leases and minimal future capital obligations.
We have also entered into a number of other standard industry arrangements that
require the drilling of wells or other activities. We believe that we will meet
our obligations under these arrangements, which individually and in the
aggregate are not material.
WORKING CAPITAL AND CASH FLOW. The Company aggressively manages its working
capital position including periodic borrowings and repayments under its
revolving credit facility. Of the total working capital deficit of $35.7 million
at September 30, 2000, $22.3 million represents the current portion of the
payable to KMI for the purchase of WGS. The Company intends to use cash provided
by monthly gathering and transportation revenues from existing contractual
agreements, including amounts paid by HSR, to fund the monthly obligations to
KMI. The Company believes that the payments made under the gathering agreements
will exceed the payments to KMI assuming no unforeseen extended operational
interruptions of the system.
Net cash provided by operating activities for the nine months ended September
30, 2000 was $120.3 million, up from $42.3 million for the same period in 1999
as a result of an increase in production and product prices. Future cash flows
will be influenced by, among other factors, the number of producing wells on
line, product prices and production constraints.
RISK MANAGEMENT. We use financial instruments to reduce our exposure to market
fluctuations in the price and transportation cost of oil and gas. Our general
strategy is to hedge price and location risk of a portion of our production with
swap, collar, floor and ceiling arrangements. In order to minimize risk, we
attempt to hedge certain of our production back to the well head although in
some cases an exact hedge instrument may not exist. In addition to hedging
activities, we are engaged in using the financial markets to capture trading
margins. We have established policies with respect to open positions which limit
our exposure to market risk and require daily reporting to management of the
potential financial exposure resulting from both hedging and trading activities.
Recently issued accounting pronouncements can change current and future
accounting and reporting requirements for certain risk management activities.
See Note 5 of the Notes to Unaudited Consolidated Financial Statements.
HEDGING ACTIVITIES. We enter into transactions for hedging purposes to manage
our exposure to price and location risks in the marketing of our oil and gas
production and, in the case of
25
<PAGE> 26
our marketing activities, third party gas. Gains and losses on hedging positions
are recognized in the period during which the underlying physical transactions
occur and are booked in "oil and gas sales" (for company-owned production) and
"trading and transportation revenues" (for third party gas). Hedging contracts
for our production reduced our oil and gas sales by $21.3 million and $39.8
million for the quarter and nine months ended September 30, 2000, respectively.
For the quarter and nine months ended September 30, 1999, hedging contracts
reduced our oil and gas sales by $4.1 million and increased our oil and gas
sales by $0.3 million, respectively. Hedging contracts for third party gas
decreased trading and transportation revenues by approximately $0.1 million and
by $0.4 million for the quarter and nine months ended September 30, 2000,
respectively. For the quarter and nine months ended September 30, 1999 hedging
contracts for third party gas increased trading and transportation revenues by
approximately $0.1 million and decreased trading and transportation revenues by
$0.2 million, respectively.
As a part of our risk management program, we generally enter into hedges for
delivery into one of several pipelines located near our producing regions,
Panhandle Eastern Pipeline Company ("PEPL"), Northwest Pipeline Corporation
("NW"), CIG, or at the New York Mercantile Exchange ("NYMEX") prices settled at
the Henry Hub. With respect to the NYMEX-hedged volumes that exceed our Gulf
Coast volumes, it is our practice to hedge our basis (meaning the transportation
differential from our producing regions to the location of delivery for a hedged
volume).
26
<PAGE> 27
As of September 30, 2000, we held hedge swap positions as follows:
GAS HEDGES
<TABLE>
<CAPTION>
Average
Daily Fair Value at
Quantity Settlement Price September 30, 2000
Time Period (MMBtu) Location (MMBtu) Gain (Loss)
--------------- -------- ---------- ------- ------------------
<S> <C> <C> <C> <C>
October 2000 - October 2000 15,000 NW 2.193 $ (1,212,255)
October 2000 - October 2000 5,000 NW 2.117 $ (415,714)
October 2000 - October 2000 30,000 NW 2.200 $ (2,417,562)
October 2000 - October 2000 15,000 NW 2.288 $ (1,168,080)
October 2000 - October 2000 25,000 NW 2.150 $ (2,053,363)
October 2000 - October 2000 10,000 NW 2.148 $ (822,120)
October 2000 - October 2000 10,000 NW 2.065 $ (847,695)
October 2000 - October 2000 30,000 NW 2.025 $ (2,580,285)
November 2000 - December 2000 10,000 NW 2.395 $ (1,490,910)
November 2000 - December 2000 10,000 NW 2.400 $ (1,487,860)
November 2000 - December 2000 65,000 NW 2.478 $ (9,363,803)
November 2000 - December 2000 15,000 NW 2.483 $ (2,156,272)
January 2001 - March 2001 20,000 NW 2.370 $ (4,224,140)
January 2001 - March 2001 20,000 NW 2.444 $ (4,090,179)
January 2001 - March 2001 10,000 NW 2.452 $ (2,038,339)
January 2001 - March 2001 5,000 NW 2.474 $ (1,009,045)
January 2001 - March 2001 5,000 NW 2.484 $ (1,004,545)
January 2001 - March 2001 10,000 NW 2.479 $ (2,013,589)
January 2001 - March 2001 15,000 NW 2.431 $ (3,085,589)
January 2001 - March 2001 15,000 NW 2.505 $ (2,985,855)
April 2001 - October 2001 10,000 NYMEX 2.440 $ (4,288,960)
April 2001 - October 2001 20,000 NYMEX 2.423 $ (8,652,820)
April 2001 - October 2001 5,000 NW 2.200 $ (1,828,830)
April 2001 - October 2001 15,000 NW 2.213 $ (5,443,690)
April 2001 - October 2001 5,000 NW 2.350 $ (1,668,330)
April 2001 - October 2001 45,000 NW 2.241 $ (16,063,570)
April 2001 - October 2001 5,000 NW 2.400 $ (1,614,830)
November 2001 - December 2001 5,000 NW 2.150 $ (660,650)
November 2001 - December 2001 15,000 NW 2.100 $ (2,027,670)
January 2002 - March 2002 5,000 NW 2.200 $ (869,600)
January 2002 - March 2002 15,000 NW 2.150 $ (2,676,255)
April 2002 - October 2002 5,000 NYMEX 2.601 $ (1,454,136)
April 2002 - October 2002 10,000 NYMEX 2.541 $ (3,036,672)
April 2002 - October 2002 10,000 NYMEX 2.906 $ (2,255,572)
April 2002 - October 2002 10,000 NYMEX 3.116 $ (1,806,172)
April 2002 - October 2002 5,000 NW 2.336 $ (1,178,611)
April 2002 - October 2002 25,000 NW 2.231 $ (6,454,805)
April 2002 - October 2002 5,000 NW 2.194 $ (1,331,086)
April 2002 - October 2002 20,000 NW 2.224 $ (5,195,944)
April 2002 - October 2002 10,000 NW 2.259 $ (2,523,072)
April 2002 - October 2002 10,000 NW 2.286 $ (2,464,222)
</TABLE>
27
<PAGE> 28
GAS BASIS HEDGES(1)
<TABLE>
<CAPTION>
Average
Daily Basis Fair Value at
Quantity Settlement Differential September 30, 2000
Time Period (MMBtu) Location (MMBtu) Gain (Loss)
--------------- -------- ---------- ------------ ------------------
<S> <C> <C> <C> <C>
November 2000 - December 2000 20,000 ELPASO(SJ) -0.300 $ (22,300)
January 2001 - October 2002 20,000 ELPASO(SJ) -0.300 $ (392,676)
November 2001 - March 2002 30,000 NW -0.310 $ (66,000)
January 2002 - March 2002 15,000 NW -0.300 $ 3,450
November 2002 - March 2003 15,000 NW -0.310 $ (211,400)
November 2002 - December 2002 15,000 NW -0.300 $ (22,875)
</TABLE>
(1) Basis is the differential between the NYMEX contract price and the
regional index.
WRITTEN GAS CALLS
<TABLE>
<CAPTION>
Average
Daily Fair Value at
Quantity Settlement Price September 30, 2000
Time Period (MMBtu) Location (MMBtu) Gain (Loss)
--------------- -------- ---------- ------- ------------------
<S> <C> <C> <C> <C>
October 2000 - December 2000 20,000 NYMEX 3.100 $ (3,962,860)
January 2001 - December 2001 20,000 NYMEX 3.000 $ (11,772,656)
</TABLE>
As of September 30, 2000, we had hedged our expected oil production as follows:
WRITTEN CRUDE HEDGES
<TABLE>
<CAPTION>
Average
Monthly Fair Value at
Quantity Settlement Price September 30, 2000
Time Period (Bbl) Location (Bbl) Gain (Loss)
--------------- -------- ---------- ------ ------------------
<S> <C> <C> <C> <C>
October 2000 - December 2000 61,633 WTI 21.400 $ (2,430,596)
January 2001 - December 2001 60,833 WTI 20.400 $ (5,847,148)
</TABLE>
Additionally, with respect to the hedging of third party gas, we have hedged
60.6 Bcf from October 2000 through December 2003 with offsetting physical
positions at settlement prices which are based upon NYMEX future prices or other
published indices. The fair market value of these hedges at September 30, 2000
was a loss of $3.6 million.
We routinely buy and sell options or forward contracts as part of our overall
hedging strategy. As of September 30, 2000, we had written crude oil and natural
gas calls through December 2001. These calls are hedged by future production.
The counterparties to these call transactions require the maintenance of
specified margin balances. Fluctuations in the mark-to-market value of these
instruments could result in additional margin requirements over the term of the
underlying contracts.
We generally hedge a portion of our crude oil production. Our position as of
September 30, 2000 is shown above. These hedges are indexed to West Texas
Intermediate prices at Cushing, Oklahoma. Our realized price at the wellhead is
expected to average between $0.75 and $1.00 below NYMEX WTI index. We do not
hedge the transportation differential (basis) between the WTI index point and
our wellhead locations because there is no regular market for such hedges and
because the volatility and risk associated with this differential is relatively
low.
28
<PAGE> 29
TRADING ACTIVITIES. We engage in the trading of various energy related financial
instruments which require payments to or receipt of payments from counterparties
based on the differential between a fixed and a variable price for the
commodity, swap or other contractual arrangement. Activities for trading
purposes are accounted for using the mark-to-market method. Under this method,
changes in the market value of outstanding financial instruments are recognized
in "trading and transportation revenues" as a net gain or loss in the period of
change. The market prices used to value these transactions reflect management's
best estimate considering various factors, including closing exchange and
over-the-counter quotations, time value and volatility factors underlying the
commitments. The values are adjusted to reflect the potential impact of
liquidating our position in an orderly manner over a reasonable period of time
under present market conditions.
Our policy requires that, within defined trading limits, financial instrument
purchase and sales contracts be balanced in terms of contract volumes and the
timing of performance and delivery obligations. For the quarter and nine months
ended September 30, 2000, gains of $1.7 million and $3.3 million, respectively,
were recognized in connection with financial trading activities, compared to
gains of $0.5 million and $1.7 million for the quarter and nine months ended
September 30, 1999, respectively.
CREDIT RISK. While notional amounts are used to express the volume of various
derivative financial instruments, the amounts potentially subject to credit risk
in the event of nonperformance by the third parties are substantially smaller.
Counterparties to the swap, collar, floor and ceiling arrangements discussed
above are generally investment grade institutions. Accordingly, we do not
anticipate any material impact to our financial position or results of
operations as a result of nonperformance by the third parties to financial
instruments related to hedging activities or trading activities.
INTEREST RATE SWAPS. In the first quarter of 1999, we entered into an interest
rate exchange agreement with a financial institution to hedge $50 million of our
borrowings at 5.66% through March 31, 2004. During the fourth quarter of 1998,
we entered into an interest rate exchange agreement with a financial institution
to hedge the interest rate on $80 million of our borrowings at 5.86% through
December 15, 2006. Under the terms of the agreements, the difference between the
fixed rate and the one-month LIBOR rate is received or paid by us. As part of
the $80 million hedging agreement, we cancelled or offset our pre-1999 interest
rate hedging agreements. The mark-to-market value of our interest rate swaps as
of September 30, 2000 was $4.6 million. Market risk related to borrowings from a
one percent change in interest rates would result in an approximate $0.9 million
impact on pre-tax income, based on the quarter end borrowing level and the
amount of such borrowings which are not subject to interest rate swaps.
TOTAL RETURN EQUITY SWAPS. In 1999 we entered into three total return equity
swap agreements with financial institutions. Under the terms of the first
agreement, entered into on February 25, 1999, the financial institution acquired
approximately 732,000 shares of our common stock from another investor at a
price of $6.0625 per share. Effective April 20, 2000
29
<PAGE> 30
we repurchased the 732,000 shares of our common stock. Those shares were retired
into the treasury, and, as a result, the $4.5 million transaction reduced our
outstanding common stock by approximately 4%.
On May 24, 1999, we entered into a second agreement whereby the financial
institution acquired 100,000 shares of our common stock from another investor at
a price of $11.9875 per share. In addition, on December 1, 1999, we entered into
a third agreement whereby a financial institution agreed to acquire on the open
market approximately 300,000 shares of our stock at current market prices over a
three month period beginning December 2, 1999. As of March 2000, the financial
institution had acquired 308,100 shares at a weighted average price of $14.55
per share. In October 2000, we repurchased the 408,100 shares under the second
and third agreements for approximately $5.7 million and retired the shares into
treasury stock.
CONTINGENCIES. We have resolved the alleged Clean Water Act Section 404
(wetlands) violations in Louisiana. The consent decree order resolving the
matter has been entered by the federal court in Louisiana. The settlement will
not have a material adverse effect on us. In 1999 we accrued an amount in our
financial statements that is sufficient to cover the estimated settlement. See
Part II, Item 1 "Legal Proceedings and Environmental Issues."
30
<PAGE> 31
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q includes statements that are not purely historical and are
"forward-looking statements" within the meaning of Section 27A of the Securities
Act and Section 21E of the Securities Exchange Act of 1934, as amended,
including statements regarding our expectations, hopes, beliefs, intentions or
strategies regarding the future. All statements other than statements of
historical facts included in this Form 10-Q are forward-looking statements,
including without limitation, statements under "Legal Proceedings and
Environmental Issues," "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and "Notes to Unaudited Consolidated
Financial Statements." These statements may concern, among other things:
o planned capital expenditures and expected funding of capital
expenditures from cash flow;
o utilization of third party capital for Northern Rockies
activities;
o trends or expectations concerning oil and gas prices or market
characteristics;
o our financial position, stability of cash flow, debt service
capabilities and capital availability;
o marketing, hedging and trading risks, strategies, policies,
procedures and profitability;
o credit risk on trading and hedging activities;
o the ability to manage risk through hedging and similar
activities;
o business strategy and other plans and objectives for future
operations;
o potential liabilities or the expected absence thereof;
31
<PAGE> 32
o the potential outcome of environmental matters, litigation or
other proceedings;
o ability to anticipate and alleviate gathering system
bottlenecks; and
o ability to boost gathering and transportation system and gas
processing capacity and the timing of such activities.
All forward-looking statements included in this Form 10-Q are based on
information available to us on the date hereof, and we assume no obligation to
update such forward-looking statements. Although we believe the forward-looking
statements are based on reasonable assumptions, we can give no assurance that
our expectations will prove to have been correct or that we will take any
actions that may presently be planned. Actual results may differ materially from
any forward-looking statements made by us depending on a variety of factors,
including, among others, the factors discussed in "Certain Considerations"
described in our report on Form 10-K filed March 24, 2000.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings and Environmental Issues
ENVIRONMENTAL PROCEEDINGS. In May 1995, we were named by the Environmental
Protection Agency ("EPA") pursuant to a Resource Conservation and Recovery Act
administrative order as one of two respondents in addition to the owner/operator
of an oilfield production water evaporation facility. The order requires that
work be performed to abate a perceived endangerment to wildlife, the environment
or public welfare. We and other non-operator respondents have worked together
with the EPA to develop characterization studies of the site, and have caused
the facility to be permanently closed. HSR and other non-operator respondents
have completed substantially all work at the site. We have incurred
approximately $1.3 million as of September 30, 2000 for our portion of the
costs. This amount has been recorded in our financial statements as of September
30, 2000 and we believe that no substantial liability remains.
Additionally, in March of 1999 we became subject to an enforcement action
handled by the EPA and the Department of Justice for alleged violations of
Section 404 of the Clean Water Act concerning wetlands in Louisiana. The consent
decree order resolving the matter has been entered by the federal court in
Louisiana. The settlement will not have a material adverse effect on us. In 1999
we accrued an amount in our financial statements that is sufficient to cover the
estimated settlement costs.
Finally, the gathering and transmission properties we are acquiring from KMI
contain numerous areas of polluted soil and ground water. These conditions have
been reported to the appropriate jurisdictional agencies. HSR expects the costs
associated with cleanup of these
32
<PAGE> 33
environmental problems will be borne by KMI under the indemnification provisions
of our agreement with KMI.
We are subject to minor lawsuits incidental to operations in the oil and gas
industry. We believe we have meritorious defenses to all lawsuits in which we
are a defendant and will vigorously defend against them. We do not believe that
the resolution of such lawsuits will have a material adverse effect on our
financial position or results of operations.
Item 2. Changes in Securities None.
Item 3. Defaults Upon Senior Securities None.
Item 4. Submission of Matters to a Vote of Security Holders None.
Item 5. Other Information None.
33
<PAGE> 34
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits.
Exhibit
Number Description
3.1 Amended and Restated Certificate of Incorporation of the Company.
(Incorporated herein by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-1, No. 33-52774,
filed October 2, 1992.)
3.2 Certificate of Amendment of Certificate of Incorporation filed November
30, 1998. (Incorporated by reference to Exhibit 3.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 1999,
filed May 14, 1999.)
3.3 Third Amended and Restated Bylaws of the Company adopted December 16,
1996. (Incorporated by reference to Exhibit 3.2 to the Company's
Registration Statement on Form S-4, No 333-19433, filed January 8,
1997.)
4.1 Form of Indenture dated December 1, 1993, entered into between the
Company and the Trustee. (Incorporated by reference to Exhibit 4.7 to
Amendment No. 3 to the Company's Registration Statement on Form S-3,
No. 33-70354, filed November 23, 1993.)
4.2 Indenture dated November 27, 1996, among the Company, Orion
Acquisition, Inc., HSRTW, Inc., and Harris Trust and Savings Bank as
Trustee. (Incorporated by reference to Exhibit 4.2 to the Company's
Registration Statement on Form S-4, No 333-19433, filed January 8,
1997.)
4.3 First Supplemental Indenture dated November 25, 1996 among the Company,
Orion Acquisition, Inc., HSRTW, Inc., and Harris Trust and Savings Bank
as Trustee. (Incorporated by reference to Exhibit 4.3 to the Company's
Registration Statement on Form S-4, No 333-19433, filed January 8,
1997.)
10.1 Common Stock Purchase Warrant dated July 12, 1990 by the Company to
James E. Duffy. (Incorporated by reference to Exhibit 10.5 to the Form
8, Second Amendment to Form 10, filed April 8, 1991.)
10.2 HS Resources, Inc. Rule 701 Compensatory Benefit Plan. (Incorporated by
reference to Exhibit 10.5.2 to the Form 8, Second Amendment to Form 10,
filed April 8, 1991.)
34
<PAGE> 35
10.3 1992 Directors' Stock Option Plan. (Incorporated by reference to
Exhibit 10.10 to Amendment No. 1 to the Company's Registration
Statement on Form S-1, No. 33-52774, filed November 9, 1992.)
10.4 Form of Indemnification Agreement for Directors of the Company.
(Incorporated by reference to Exhibit 10.16 to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1995, filed
March 25, 1996.)
10.5 Lease Agreement dated October 6, 1993, between the Company and JMB
Group Trust IV and Endowment and Foundation Realty, Ltd. -- JMB III for
the premises at One Maritime Plaza, San Francisco, California.
(Incorporated by reference to Exhibit 10.13 to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1993, filed
March 31, 1994 (as amended by Form 10-K/A-1 on April 8, 1994.))
10.6 Lease Agreement dated March 28, 1994, between the Company and 1999
Broadway Partnership for the premises at 1999 Broadway, Denver,
Colorado. (Incorporated by reference to Exhibit 10.15 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 1994,
filed August 12, 1994.)
10.7 Purchase and Sale Agreement, dated December 1, 1995, between the
Company and Wattenberg Gas Investments, LLC. (Incorporated by reference
to Exhibit 10.26 to the Company's Annual Report on Form 10-K for the
fiscal year ended December 31, 1995, filed March 25, 1996.)
10.8 Rights Agreement, dated as of February 28, 1996, between the Company
and Harris Trust Company of California as Rights Agent. (Incorporated
by reference to Exhibit 1 to the Company's Form 8-A, filed March 11,
1996.)
10.9 Purchase and Sale Agreement dated March 25, 1996, between Orion, the
Company and Wattenberg Resources Land, L.L.C. (Incorporated by
reference to Exhibit 10.28 to the Company's Quarterly Report on Form
10-Q for the quarter ended March 31, 1996, filed May 15, 1996.)
10.10 Amended and Restated Credit Agreement dated as of June 14, 1996, among
the Company, Chase as agent, and the Banks signatory thereto.
(Incorporated by reference to Exhibit 10.21 to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1996, filed August
14, 1996.)
10.11 First Amendment to Amended and Restated Credit Agreement dated as of
June 17, 1996, by and among the Company and Chase in its individual
capacity and as agent for the Lenders. (Incorporated by reference to
Exhibit 10.22 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
35
<PAGE> 36
10.12 Second Amendment to Amended and Restated Credit Agreement dated as of
November 27, 1996 among the Company and Chase in its individual
capacity and as agent for the Lenders. (Incorporated by reference to
Exhibit 10.22 to the Company's Registration Statement on Form S-4, No
333-19433, filed January 8, 1997.)
10.13 Purchase and Sale Agreement between the Company and Wattenberg Gas
Investments, LLC dated April 25, 1996. (Incorporated by reference to
Exhibit 10.32 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.14 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
and Wattenberg Gas Investments, LLC dated May 21, 1996. (Incorporated
by reference to Exhibit 10.33 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.15 Purchase and Sale Agreement between Orion and Wattenberg Gas
Investments, LLC dated June 14, 1996. (Incorporated by reference to
Exhibit 10.34 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.16 Purchase and Sale Agreement between Wattenberg Resources Land L.L.C.
and Wattenberg Gas Investments, LLC dated June 14, 1996. (Incorporated
by reference to Exhibit 10.35 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1996, filed August 14, 1996.)
10.17 Purchase and Sale Agreement between Orion and Wattenberg Gas
Investments, LLC dated June 14, 1996. (Incorporated by reference to
Exhibit 10.36 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.18 Purchase and Sale Agreement between the Company and Wattenberg Gas
Investments, LLC dated June 28, 1996. (Incorporated by reference to
Exhibit 10.37 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996, filed August 14, 1996.)
10.19 Purchase and Sale Agreement between the Company and Amoco Production
Company dated November 25, 1997. (Incorporated by reference to Exhibit
10.1 to the Company's Current Report on Form 8-K, filed December 23,
1997.)
10.20 Side Letter Agreement between the Company and Amoco Production Company
dated November 25, 1997. (Incorporated by reference to Exhibit 10.2 to
the Company's Current Report on Form 8-K, filed December 23, 1997.)
36
<PAGE> 37
10.21 Closing Side Agreement between the Company and Amoco Production Company
dated December 15, 1997. (Incorporated by reference to Exhibit 10.3 to
the Company's Current Report on Form 8-K, filed December 23, 1997.)
10.22 Third Amendment to Amended and Restated Credit Agreement dated as of
December 15, 1997, among the Company and The Chase Manhattan Bank as
agent for the Lenders signatory thereto. (Incorporated by reference to
Exhibit 10.4 to the Company's Current Report on Form 8-K, filed
December 23, 1997.)
10.23 Purchase and Sale Agreement dated December 15, 1997, by and between HS
Resources, Inc. as Seller and WestTide Investments, LLC as Buyer.
(Incorporated by reference to Exhibit 10.46 to the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1997, filed
March 31, 1998.)
10.24 Fifth Amendment and Supplement to Amended, Restated and Consolidated
Mortgage, Assignment of Production, Security Agreement and Financing
Statement between HS Resources (Mortgagor) and The Chase Manhattan
Bank, as agent for the Lenders, effective as of December 15, 1997.
(Incorporated by reference to Exhibit 10.37 to the Company's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1998, filed May 14,
1998.)
10.25 Agreement and Plan of Merger between Orion Acquisition, Inc. and HS
Resources, Inc. dated April 20, 1998, but effective May 1, 1998.
(Incorporated by reference to Exhibit 10.38 to the Company's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1998, filed May 14,
1998.)
10.26 First Amendment to Agreement of Lease between 1999 Broadway Partnership
(Landlord) and HS Resources, Inc. (Tenant), dated March 21, 1997.
(Incorporated by reference to Exhibit 10.39 to the Company's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1998, filed May 14,
1998.)
10.27 HS Resources, Inc. Form of Key Employee Severance Agreement (March 27,
1998). (Incorporated by reference to Exhibit 10.40 to the Company's
Quarterly Report on Form 10-Q for the quarter ended March 31, 1998,
filed May 14, 1998.)
10.28 Fourth Amendment to Amended and Restated Credit Agreement dated as of
June 16, 1998, among the Company and The Chase Manhattan Bank in its
individual capacity and as agent for the Lenders. (Incorporated by
reference to Exhibit 10.41 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1998, filed August 14, 1998.)
37
<PAGE> 38
10.29 Stock Purchase and Sale Agreement between the Company and Universal
Resources Corporation dated July 27, 1998. (Incorporated by reference
to Exhibit 10.1 to the Company's Form 8-K, filed August 6, 1998.)
10.30 Fifth Amendment to Amended and Restated Credit Agreement dated as of
September 1, 1998, among the Company and The Chase Manhattan Bank in
its individual capacity and as agent for the lenders. (Incorporated by
reference to Exhibit 10.37 to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1998, filed November 16,
1998.)
10.31 Sixth Amendment and Supplement to Amended, Restated and Consolidated
Mortgage, Assignment of Production, Security Agreement and Financing
Statement dated as of July 22, 1998, among the Company and The Chase
Manhattan Bank in its individual capacity and as agent for the Lenders.
(Incorporated by reference to Exhibit 10.38 to the Company's Quarterly
Report on Form 10-Q for the quarter ended September 30, 1998, filed
November 16, 1998.)
10.32 Sixth Amendment to Amended and Restated Credit Agreement dated as of
December 10, 1998, among the Company and The Chase Manhattan Bank in
its individual capacity and as agent for the Lenders. (Incorporated by
reference to Exhibit 10.40 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1998, filed March 31, 1999.)
10.33 Seventh Amendment to Amended and Restated Credit Agreement dated as of
December 31, 1998, among the Company and The Chase Manhattan Bank in
its individual capacity and as agent for the Lenders. (Incorporated by
reference to Exhibit 10.41 to the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1998, filed March 31, 1999.)
10.34 1999 Non-Compensatory Stock Purchase Plan. (Incorporated by reference
as Exhibit 4.1 to Form S-8 filed January 25, 1999.)
10.35 Supplemental Indenture dated as of March 1, 1999, among the Company and
Harris Trust and Savings Bank as Trustee, amending Indenture dated as
of December 1, 1993, concerning 9-7/8% Senior Subordinated Notes due
2003. (Incorporated by reference to Exhibit 10.43 to the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1998,
filed March 31, 1999.)
10.36 Supplemental Indenture dated as of March 1, 1999, among the Company and
Harris Trust and Savings Bank as Trustee, amending Indenture dated as
of November 27, 1996, concerning 9-1/4% Series A Senior Subordinated
Notes due 2006. (Incorporated by reference to Exhibit 10.44 to the
Company's
38
<PAGE> 39
Annual Report on Form 10-K for the fiscal year ended December 31, 1998,
filed March 31, 1999.)
10.37 Supplemental Indenture dated as of March 1, 1999, among the Company and
Harris Trust and Savings Bank as Trustee, amending Indenture dated as
of December 11, 1998, concerning 9-1/4% Series B Senior Subordinated
Notes due 2006. (Incorporated by reference to Exhibit 10.45 to the
Company's Annual Report on Form 10-K for the fiscal year ended December
31, 1998, filed March 31, 1999.)
10.38 Seventh Amendment and Supplement to Amended, Restated and Consolidated
Mortgage, Assignment of Production, Security Agreement and Financing
Statement dated as of September 1, 1999 among: The Company and The
Chase Manhattan Bank in its individual capacity, and as agent to the
Lenders. (Incorporated by reference to Exhibit 10.41 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1999,
filed November 15, 1999).
10.39 Eighth Amendment to Amended and Restated Credit Agreement dated as of
August 27, 1999 among: The Company and The Chase Manhattan Bank in its
individual capacity, and as agent for the Lenders. (Incorporated by
reference to Exhibit 10.42 to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1999, filed November 15,
1999).
10.40 Exchange Agreement dated August 27, 1999 between HS Resources, Inc. and
Patina Oil & Gas Corporation. (Incorporated by reference to Exhibit
10.43 to the Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1999, filed November 15, 1999).
10.41 Ninth Amendment to Amended and Restated Credit Agreement dated as of
October 28, 1999 among: The Company and The Chase Manhattan Bank in its
individual capacity, and as agent for the Lenders. (Incorporated by
reference to Exhibit 10.43 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1999, filed March 24, 2000.)
10.42 Tenth Amendment to Amended and Restated Credit Agreement dated as of
May 16, 2000 among: The Company and The Chase Manhattan Bank in its
individual capacity, and as agent for the Lenders. (Incorporated by
reference to Exhibit 10.42 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2000, filed August 11, 2000.)
10.43* Sublease Agreement dated as of May 22, 2000, by and between HS
Resources, Inc. and Cooley Godward LLP for the premises located at One
Maritime Plaza, 15th Floor, San Francisco, California.
27* Financial Data Schedule
* Filed herewith
39
<PAGE> 40
b. Reports on Form 8-K.
Form 8-K dated August 3, 2000 filing the July 27, 2000 press release in
connection with the Company's second quarter earnings release. Item 5.
40
<PAGE> 41
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, HS
Resources, Inc. has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
HS RESOURCES, INC.
Dated: November 13, 2000 By: /s/ JAMES E. DUFFY
---------------------------------
James E. Duffy
Vice President and Chief Financial
Officer
By: /s/ ANNETTE MONTOYA
---------------------------------
Annette Montoya
Vice President and Principal
Accounting Officer
41
<PAGE> 42
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------ -----------
<S> <C>
10.43* Sublease Agreement dated as of May 22, 2000, by and between HS
Resources, Inc. and Cooley Godward LLP for the premises located at One
Maritime Plaza, 15th Floor, San Francisco, California.
27* Financial Data Schedule
</TABLE>
----------
* Filed herewith
