<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to _________
Commission file number 1-14344
__________________________
PATINA OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 75-2629477
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
1625 Broadway
Denver, Colorado 80202
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code (303) 389-3600
<TABLE>
<CAPTION>
Title of class Name of exchange on which listed
__________________________________ __________________________________
<S> <C>
Common Stock, $.01 par value New York Stock Exchange
7.125% Convertible Preferred Stock, $.01 par value New York Stock Exchange
Common Stock Warrants New York Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
None
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 ___________.
-----------
There were 16,537,667 shares of common stock outstanding on October 27, 1999.
<PAGE>
PART I. FINANCIAL INFORMATION
Patina Oil & Gas Corporation (the "Company") was formed in 1996 to hold the
assets and operations of Snyder Oil Corporation ("SOCO") in the Wattenberg Field
and to facilitate the acquisition of Gerrity Oil & Gas Corporation (the "Gerrity
Acquisition"). Through a series of transactions, the Company became independent
of SOCO in late 1997. The financial statements included herein have been
prepared in conformity with generally accepted accounting principles. The
statements are unaudited but reflect all adjustments which, in the opinion of
management, are necessary to fairly present the Company's financial position and
results of operations.
2
<PAGE>
PATINA OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands except share data)
<TABLE>
<CAPTION>
December 31, September 30,
1998 1999
------------ -------------
(Unaudited)
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents $ 10,086 $ 2,352
Accounts receivable 9,953 12,471
Inventory and other 3,286 3,143
------------ -------------
23,325 17,966
------------ -------------
Oil and gas properties, successful efforts method 598,712 616,216
Accumulated depletion, depreciation and amortization (273,935) (303,600)
------------ -------------
324,777 312,616
------------ -------------
Gas facilities and other 6,692 6,902
Accumulated depreciation (4,590) (5,302)
------------ -------------
2,102 1,600
------------ -------------
Other assets, net 1,329 1,513
------------ -------------
$ 351,533 $ 333,695
============ =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 16,825 $ 14,242
Accrued liabilities 6,754 3,921
------------ -------------
23,579 18,163
------------ -------------
Senior debt 68,000 130,000
Subordinated notes 74,021 -
Other noncurrent liabilities 9,957 10,645
Commitments and contingencies
Stockholders' equity
Preferred stock, $.01 par, 5,000,000 shares
authorized, 3,166,860 and 3,056,845 shares issued
and outstanding 32 31
Common stock, $.01 par, 100,000,000 shares
authorized, 15,752,389 and 16,060,098 shares
issued and outstanding 158 161
Capital in excess of par value 206,792 205,576
Deferred compensation (1,038) (556)
Retained earnings (deficit) (29,968) (30,325)
------------ -------------
175,976 174,887
------------ -------------
$ 351,533 $ 333,695
============ =============
</TABLE>
The accompanying notes are an integral part of these statements.
3
<PAGE>
PATINA OIL & GAS CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per share data)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------- ----------------------
1998 1999 1998 1999
---------- ---------- ---------- ----------
(Unaudited)
<S> <C> <C> <C> <C>
Revenues
Oil and gas sales $ 17,353 $ 24,242 $ 55,151 $ 60,749
Other 1,137 234 2,303 830
---------- ---------- ---------- ----------
18,490 24,476 57,454 61,579
---------- ---------- ---------- ----------
Expenses
Direct operating 4,198 4,762 13,093 13,338
Exploration 25 170 43 191
General and administrative 1,707 1,562 5,532 4,381
Interest expense and other 3,359 2,410 10,022 8,288
Depletion, depreciation and amortization 10,665 10,292 31,425 30,377
---------- ---------- ---------- ----------
Income (loss) before taxes (1,464) 5,280 (2,661) 5,004
---------- ---------- ---------- ----------
Provision (benefit) for income taxes
Current - - - -
Deferred - - - -
---------- ---------- ---------- ----------
Net income (loss) $ (1,464) $ 5,280 $ (2,661) $ 5,004
========== ========== ========== ==========
Basic net income (loss) per common share $ (0.19) $ 0.23 $ (0.46) $ 0.01
========== ========== ========== ==========
Diluted net income (loss) per common share $ (0.19) $ 0.21 $ (0.46) $ 0.01
========== ========== ========== ==========
Basic weighted average shares outstanding 15,934 16,029 16,117 15,913
========== ========== ========== ==========
Diluted weighted average shares outstanding 15,934 25,225 16,117 16,363
========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these statements.
4
<PAGE>
PATINA OIL & GAS CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY
(In thousands)
<TABLE>
<CAPTION>
Preferred Stock Common Stock Capital in Retained
--------------- --------------- Excess of Deferred Earnings
Shares Amount Shares Amount Par Value Compensation (Deficit)
------ ------ ------ ------ ---------- ------------ ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1997 3,094 $ 31 16,450 $ 165 $ 208,525 $ (1,828) $ (18,452)
Repurchase of common and preferred (68) (1) (1,338) (13) (8,676) - -
Issuance of common - - 640 6 3,224 (688) -
Preferred dividends and accretion 141 2 - - 3,719 - (6,335)
Common dividends - - - - - - (657)
Net loss - - - - - 1,478 (4,524)
------ ------ ------ ------ ---------- ------------ ----------
Balance, December 31, 1998 3,167 32 15,752 158 206,792 (1,038) (29,968)
Repurchase of common and preferred (221) (2) (95) (1) (5,642) - -
Issuance of common - - 403 4 1,414 (335) -
Preferred dividends and accretion 111 1 - - 3,012 - (4,874)
Common dividends - - - - - - (487)
Net Income - - - - - 817 5,004
------ ------ ------ ------ ---------- ------------ ----------
Balance, September 30, 1999 (unaudited) 3,057 $ 31 16,060 $ 161 $ 205,576 $ (556) $ (30,325)
====== ====== ====== ====== ========== ============ ==========
</TABLE>
The accompanying notes are an integral part of these statements.
5
<PAGE>
PATINA OIL & GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
Nine Months Ended September 30,
-------------------------------
1998 1999
-------- --------
(Unaudited)
<S> <C> <C>
Operating activities
Net income (loss) $ (2,661) $ 5,004
Adjustments to reconcile net income (loss) to net
cash provided by operations
Exploration expense 43 191
Depletion, depreciation and amortization 31,425 30,377
Deferred compensation expense 1,122 769
Amortization of deferred credits (418) (836)
Gain on sale of assets (1,124) -
Amortization of loan origination fees - 37
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable 7,385 (2,518)
Inventory and other (342) (99)
Decrease in
Accounts payable (3,575) (2,584)
Accrued liabilities (5,157) (2,709)
Other assets and liabilities (3,250) (94)
-------- --------
Net cash provided by operating activities 23,448 27,538
-------- --------
Investing activities
Acquisition, development and exploration (17,760) (17,454)
Other 693 (211)
-------- --------
Net cash used by investing activities (17,067) (17,665)
-------- --------
Financing activities
Decrease in indebtedness (367) (12,021)
Deferred credits 1,271 2,087
Issuance of common stock 1,395 855
Repurchase of common stock (6,369) (427)
Repurchase of preferred stock - (5,218)
Preferred dividends (1,961) (1,941)
Common dividends (495) (487)
Loan origination fees - (455)
-------- --------
Net cash used by financing activities (6,526) (17,607)
-------- --------
Decrease in cash (145) (7,734)
Cash and equivalents, beginning of period 12,609 10,086
-------- --------
Cash and equivalents, end of period $ 12,464 $ 2,352
======== ========
</TABLE>
The accompanying notes are an integral part of these statements.
6
<PAGE>
PATINA OIL & GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Patina Oil & Gas Corporation (the "Company" or "Patina"), a Delaware
corporation, was formed in 1996 to hold the assets and operations of Snyder Oil
Corporation ("SOCO") in the Wattenberg Field and to facilitate the acquisition
of Gerrity Oil & Gas Corporation ("Gerrity"). In conjunction with the Gerrity
Acquisition, SOCO received 14.0 million common shares. In 1997, a series of
transactions eliminated SOCO's 74% ownership in the Company.
The Company's operations currently consist of the acquisition, development,
exploitation and production of oil and natural gas properties primarily in the
Wattenberg Field of Colorado's D-J Basin.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Producing Activities
The Company utilizes the successful efforts method of accounting for its
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
expenses, including 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 productive wells, unsuccessful developmental wells and
productive leases are capitalized and amortized on a unit-of-production basis
over the life of the remaining proved or proved developed reserves, as
applicable. Oil is converted to natural gas equivalents (Mcfe) at the rate of
one barrel to six Mcf. Amortization of capitalized costs has generally been
provided over the entire Wattenberg Field, as the wells are located in the same
reservoirs. No accrual has been provided for estimated future abandonment costs
as management estimates that salvage value will approximate or exceed such
costs.
In 1995, the Company adopted Statement of Financial Accounting Standards
No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets." SFAS
121 requires the Company to assess the need for an impairment of capitalized
costs of oil and gas properties on a field-by-field basis. During 1997, the
Company recorded an impairment of $26.0 million to oil and gas properties as the
estimated future cash flows (undiscounted and without interest charges) expected
to result from these assets and their disposition, largely proven undeveloped
drilling locations, was less than their net book value. The impairment primarily
resulted from low year-end oil and natural gas prices. While no impairments were
necessary in 1998 or the first nine months of 1999, changes in underlying
assumptions could result in impairments in the future.
Gas facilities and other
Depreciation of gas gathering and transportation facilities is provided
using the straight-line method over the estimated useful life of five years.
Equipment is depreciated using the straight-line method with estimated useful
lives ranging from three to five years.
Other Assets
Other Assets at December 31, 1998 and September 30, 1999 were comprised of
$1.3 million and $1.1 million of notes receivable from certain officers and
managers of the Company, respectively. See Note (9). At September 30, 1999,
the balance also included unamortized loan origination fees of $418,000.
7
<PAGE>
Section 29 Tax Credits
The Company has entered into arrangements to monetize its Section 29 tax
credits. These arrangements result in revenue increases of approximately $0.40
per Mcf on production volumes from qualified Section 29 properties. As a
result, the Company recognized additional gas revenues of $1.5 million and $2.0
million for the nine months ended September 30, 1998 and 1999, respectively.
These arrangements are expected to increase revenues through 2002.
Gas Imbalances
The Company uses the sales method to account for gas imbalances. Under this
method, revenue is recognized based on the cash received rather than the
Company's proportionate share of gas produced. Gas imbalances at December 31,
1998 and September 30, 1999 were insignificant.
Financial Instruments
The book value and estimated fair value of cash and equivalents was $10.1
million and $2.4 million at December 31, 1998 and September 30, 1999. The book
value and estimated fair value of the senior debt was $68.0 million and $130.0
million at December 31, 1998 and September 30, 1999. The book value of these
assets and liabilities approximates fair value due to the short maturity or
floating rate structure of these instruments. The book value of the Senior
Subordinated Notes ("Subordinated Notes" or "Notes") was $74.0 million and the
estimated fair value was $69.9 million at December 31, 1998. The Company
redeemed the Notes in July 1999.
From time to time, the Company enters into commodity derivative contracts and
fixed-price physical contracts to manage its exposure to oil and gas price
volatility. Commodity derivatives contracts, which are generally placed with
major financial institutions or with counterparties of high credit quality that
the Company believes are minimal credit risks, may take the form of futures
contracts, swaps or options. The oil and gas reference prices of these
commodity derivatives contracts are based upon oil and natural gas futures which
have a high degree of historical correlation with actual prices received by the
Company. The Company accounts for its commodity derivative contracts using the
hedge (deferral) method of accounting. Under this method, realized gains and
losses on such contracts are deferred and recognized as an adjustment to oil and
gas sales revenues in the period in which the physical product to which the
contracts relate, is actually sold. Gains and losses on commodity derivative
contracts that are closed before the hedged production occurs are deferred until
the production month originally hedged.
The Company entered into various swap contracts for oil (NYMEX based) for the
first nine months of 1998 and 1999. The Company recognized a gain of $238,000
in the nine-month period ended September 30, 1998 and a loss of $1.4 million in
the nine-month period ended September 30, 1999 related to these swap contracts.
The Company entered into various CIG and PEPL index based swap contracts for
natural gas for the first nine months 1998 and 1999. The Company recognized a
gain of $1.2 million in the nine-month period ended September 30, 1998 and a
loss of $1.1 million in the nine-month period ended September 30, 1999 related
to these swap contracts.
As of September 30, 1999, the Company had entered into swap contracts for oil
(NYMEX based) for approximately 3,200 barrels of oil per day for remainder of
1999 at fixed prices ranging from $18.07 to $23.66 per barrel and approximately
2,300 barrels of oil per day for 2000 at fixed prices ranging from $18.86 to
$22.20 per barrel. Certain swap contracts for oil (NYMEX based) contain "knock
out" provisions. These contracts cover 1,000 barrels of oil per day with a swap
price of $21.00 per barrel and a "knock out" price of $16.00 per barrel for the
period January 2000 to December 2000 and 500 barrels of oil per day with a swap
price of $22.20 per barrel and a "knock out" price of $17.00 per barrel for the
period March 2000 to December 2000. If the average price of NYMEX WTI crude
oil falls below the "knock out" price for the contract month, the swaps will be
considered "knocked out" and no payment will be made to the Company for the
applicable month. The overall weighted average hedged price for the swap
contracts is $19.21 per barrel for the remainder of 1999 and $20.85 per barrel
for 2000 (NYMEX based). The unrecognized losses on these contracts totaled $2.1
million based on estimated market values as of September 30, 1999.
8
<PAGE>
As of September 30, 1999, the Company had entered into natural gas swap
contracts for approximately 25,000 MMBtu's per day of natural gas for the
remainder of 1999 at fixed prices ranging from $1.97 per MMBtu on CIG index
based swap contracts to $3.00 per MMBtu on a PEPL index based swap contract and
approximately 17,000 MMBtu's per day for the period January 2000 through October
2000 at fixed prices ranging from $2.05 to $2.62 per MMBtu on CIG index based
swap contracts. The Company also has entered into physical natural gas sale
contracts for the delivery of approximately 13,000 MMBtu's per day of natural
gas for the remainder of 1999 at prices ranging from $1.82 to $2.84 per MMBtu
and approximately 15,000 of MMBtu's per day for the period January 2000 through
March 2000 at prices ranging from $2.73 to $2.84 per MMBtu. The weighted average
daily volumes and prices for these natural gas swaps and physical contracts are
38,000 MMBtu's per day at $2.49 per MMBtu for the remainder of 1999 and 21,500
MMBtu's per day at $2.30 per MMBtu for the period January 2000 through October
2000. The unrecognized losses on these contracts totaled $867,000 based on
estimated market values as of September 30, 1999.
In October 1998, the Company entered into an interest rate swap contract for
a two-year period, extendable for one additional year at the option of the third
party. The contract is for $30.0 million principal with a fixed interest rate
of 4.57% payable by the Company and the variable interest rate, the three-month
LIBOR, payable by the third party. The difference between the Company's fixed
rate of 4.57% and the three-month LIBOR rate, which is reset every 90 days, is
received or paid by the Company in arrears every 90 days. The Company received
$59,000 in January 1999, $36,000 in April 1999, $33,000 in July 1999 and $57,000
in October 1999 pursuant to this contract. The unrecognized gain on this
contract totaled $438,000 based on estimated market values as of September 30,
1999.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities." SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded on the
balance sheet as either an asset or liability measured at its fair value. It
also requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met.
Special accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement, and
requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. SFAS 133 is
effective for fiscal years beginning after January 1, 2001. The Company has not
yet quantified the impacts of adopting SFAS 133 on its financial statements and
has not determined the timing of, or method of, adoption of SFAS 133. However,
SFAS 133 could increase volatility in earnings and other comprehensive income.
Stock Options and Awards
The Company accounts for its stock-based compensation plans under the
principles prescribed by the Accounting Principles Board's Opinion No. 25 ("APB
No. 25"), "Accounting for Stock Issued to Employees." Accordingly, stock
options awarded under the Employee Plan and the Non-Employee Directors Plan are
considered to be "noncompensatory" and do not result in recognition of
compensation expense. However, the restricted stock awarded under the
Restricted Stock Plan is considered to be "compensatory" and the Company
recognized $1.1 million and $769,000 of non-cash general and administrative
expenses for the nine months ended September 30, 1998 and 1999. See Note (6).
Per Share Data
The Company uses the weighted average number of shares outstanding in
calculating earnings per share data. When dilutive, options and warrants are
included as share equivalents using the treasury stock method and are included
in the calculation of diluted per share data. Common stock issuable upon
conversion of convertible preferred securities is also included in the
calculation of diluted per share data if their effect is dilutive.
9
<PAGE>
Risks and Uncertainties
Historically, the market for oil and natural gas has experienced significant
price fluctuations. Prices for oil and for natural gas in the Rocky Mountain
region have, at times, been particularly volatile. The price fluctuations can
result from variations in weather, levels of production in the region,
availability of transportation capacity to other regions of the country and
various other factors. Increases or decreases in prices received could have a
significant impact on the Company's future results.
Supplemental Cash Flow Information
The Company incurred the following significant non-cash items:
Nine Months Ended
September 30,
------------------
1998 1999
------- -------
(In thousands)
Stock grant awarded to officers.................. $ 688 $ 335
Dividends and accretion - 8.50% preferred stock.. 2,790 3,013
The 1998 stock grant award represents 100,000 common shares granted to the
President in conjunction with his appointment in the first quarter of 1998 and
has been recorded as Deferred Compensation in the equity section of the
accompanying consolidated balance sheets. The 1999 stock grant award represents
100,000 common shares granted to the Chief Executive Officer in conjunction with
his voluntary reduction in cash salary, waiver of any 1998 bonus and other
compensation arrangements in the second quarter of 1999 and has also been
recorded as Deferred Compensation in the equity section of the accompanying
consolidated balance sheets. The Company recognized $1.1 million and $769,000 of
non-cash general and administrative expenses for the nine months ended September
30, 1998 and 1999 related to these stock grants and the stock grants awarded to
certain officers and managers in conjunction with the redistribution of SOCO's
ownership of the Company. See Note (9).
Other
All liquid investments with an original maturity of three months or less are
considered to be cash equivalents. Certain amounts in the prior period
consolidated financial statements have been reclassified to conform with the
current classifications.
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries. All significant intercompany balances and
transactions have been eliminated in consolidation. The preparation of
financial statements in conformity with generally accepted accounting principles
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
In the opinion of management, those adjustments to the financial statements
(all of which are of a normal and recurring nature) necessary to present fairly
the financial position and results of operations have been made. These interim
financial statements should be read in conjunction with the Company's Annual
Report on Form 10-K for the year ended December 31, 1998.
10
<PAGE>
(3) OIL AND GAS PROPERTIES
The cost of oil and gas properties included approximately $585,000 and
$559,000 at December 31, 1998 and September 30, 1999, respectively, in
unevaluated leasehold costs related to a prospect in Wyoming. Acreage generally
held for exploration or resale and its value, if any, is excluded from
amortization. The following table sets forth costs incurred related to oil and
gas properties:
Nine
Year Ended Months Ended
December 31, September 30,
1998 1999
------------- -------------
(In thousands)
Acquisition................................ $ 2,319 $ 1,761
Development................................ 21,711 15,502
Exploration and other...................... 59 191
------------- -------------
$24,089 $ 17,454
============= =============
(4) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
December 31, September 30,
1998 1999
------------- -------------
(In thousands)
Bank facilities............................ $68,000 $130,000
Less current portion....................... - -
------------- -------------
Senior debt, net........................... $68,000 $130,000
============= =============
Subordinated notes........................... $74,021 $ -
============= =============
In July 1999, in conjunction with the redemption of the 11.75% Senior
Subordinated Notes, the Company entered into a Second Amended and Restated Bank
Credit Agreement (the "Credit Agreement"). The Credit Agreement is a revolving
credit facility in an aggregate amount up to $200.0 million. The amount
available under the facility is adjusted semiannually, each May 1 and November
1, and equaled $160.0 million at September 30, 1999.
The Company may elect that all or a portion of the credit facility bear
interest at a rate equal to: (i) the higher of (a) the prime rate or (b) the
Federal Funds Effective Rate plus .5%, or ii) the rate at which Eurodollar
deposits for one, two, three or six months (as selected by the Company) are
offered in the interbank Eurodollar market plus a margin which fluctuates from
1.00% to 1.50%, determined by a debt to EBITDA ratio. During the nine-month
period ended September 30, 1999, the average interest rate under the facility
approximated 6.4%.
In October 1998, the Company entered into an interest rate swap contract for
a two-year period, extendable for one additional year at the option of the third
party. The contract is for $30.0 million principal with a fixed interest rate
of 4.57% payable by the Company and the variable interest rate, the three-month
LIBOR, payable by the third party. The difference between the Company's fixed
rate of 4.57% and the three-month LIBOR rate, which is reset every 90 days, is
received or paid by the Company in arrears every 90 days. The Company received
$59,000 in January 1999, $36,000 in April 1999, $33,000 in July 1999 and $57,000
in October 1999 pursuant to this contract.
11
<PAGE>
The Credit Agreement contains certain financial covenants, including but not
limited to a maximum total debt to EBITDA ratio and a minimum current ratio. The
Credit Agreement also contains certain negative covenants, including but not
limited to restrictions on indebtedness; certain liens; guaranties, speculative
derivatives and other similar obligations; asset dispositions; dividends, loans
and advances; creation of subsidiaries; investments; leases; acquisitions;
mergers; changes in fiscal year; transactions with affiliates; changes in
business conducted; sale and leaseback and operating lease transactions; sale of
receivables; prepayment of other indebtedness; amendments to principal
documents; negative pledge causes; issuance of securities; and non-speculative
commodity hedging. Borrowings under the Credit Agreement mature in July 2003,
but may be prepaid at anytime. The Company has periodically negotiated
extensions of the Credit Agreement; however, there is no assurance the Company
will be able to do so in the future. The Company had a restricted payment
basket of $5.7 million as of September 30, 1999, which may be used to repurchase
common stock, preferred stock and warrants and pay dividends on its common
stock.
In conjunction with the Gerrity Acquisition, the Company assumed $100.0
million of 11.75% Senior Subordinated Notes due July 15, 2004. Under purchase
accounting, the Notes were reflected in the financial statements at a book value
of 105.875% of their principal amount, their initial call price as of July 15,
1999. The Notes became redeemable on July 15, 1999. The Company redeemed all of
the Notes at the call price of 105.875% on July 15, 1999. The redemption was
financed with borrowings under the bank credit facility.
Scheduled maturities of indebtedness for the next five years are zero for
1999, 2000, 2001, 2002 and $130.0 million in 2003. Management intends to review
the facility and extend the maturity on a regular basis; however, there can be
no assurance that the Company will be able to do so.
Cash payments for interest totaled $13.1 million and $12.0 million during
the nine months ended September 30, 1998 and 1999, respectively.
(5) STOCKHOLDERS' EQUITY
A total of 100.0 million common shares, $.01 par value, are authorized of
which 16.1 million were issued and outstanding at September 30, 1999. The
Company issued 6.0 million common shares and 3.0 million five-year common stock
warrants exercisable at $12.50 (which expire in May 2001), in exchange for all
of the outstanding stock of Gerrity upon consummation of the Gerrity
Acquisition. Subsequent to the acquisition date, the Company has repurchased
5,650,000 shares of common stock, 346,307 shares of 7.125% preferred stock,
68,743 shares of 8.50% preferred stock, 500,000 warrants issued to Gerrity's
former chief executive officer, and 80,549 five year common stock warrants for
total consideration of $57.0 million. The common stock is listed on the New
York Stock Exchange. Prior to 1997, no dividends had been paid on common stock.
A quarterly cash dividend of one cent per common share was initiated in December
1997.
A total of 5.0 million preferred shares, $.01 par value, are authorized. At
September 30, 1999, the Company had two issues of preferred stock outstanding
consisting of 1,247,301 shares of 7.125% preferred and 1,809,544 shares of 8.50%
preferred.
In May 1996, 1.2 million shares of 7.125% preferred stock were issued to
certain Gerrity preferred shareholders electing to exchange their preferred
shares (the "Original Exchange Offer"). There were no proceeds received related
to this issuance. In October 1996, all remaining shares of Gerrity's preferred
stock were exchanged for 389,000 7.125% preferred shares on the same terms as
the Original Exchange Offer. Each share of 7.125% preferred stock is
convertible into common stock at any time at $8.61 per share, or 2.9036 common
shares. The 7.125% preferred stock pays quarterly cash dividends, when declared
by the Board of Directors, based on an annual rate of $1.78 per share. The
7.125% preferred stock is currently redeemable at the option of the Company at
an initial call price of $26.25 per share, declining ratably to $25.00 through
2006. The liquidation preference of the 7.125% preferred stock is $25 per
share, plus accrued and unpaid dividends. As of September 30, 1999, there were
1,247,301 shares of 7.125% preferred stock outstanding with an aggregate
liquidation preference of $31.2 million. On September 21, 1999, the Company
called for redemption one-half of its 7.125% preferred stock. The effective
date of the redemption was October 25, 1999. Of the 623,000
12
<PAGE>
7.125% preferred shares called, 166,000 were converted into 482,000 shares of
common stock and the remaining 457,345 were redeemed for $12.0 million in cash.
The cash redemption was financed with borrowings under the bank credit facility.
The 7.125% preferred stock is listed on the New York Stock Exchange. Holders of
the 7.125% preferred stock are not generally entitled to vote, except with
respect to certain limited matters. The Company paid $1,961,000 and $1,941,000
($.4453 per 7.125% convertible preferred share each quarter) in preferred
dividends during the nine months ended September 30, 1998 and 1999, and had
accrued an additional $322,000 and $241,000 at September 30, 1998 and 1999,
respectively, for dividends.
In October 1997, 1.6 million shares of 8.50% preferred stock and 160,000
common shares were issued to a group of private investors for $40.0 million.
Each share of the 8.50% preferred stock is convertible into common stock at any
time at $9.50 per share or 2.6316 common shares. The 8.50 % preferred stock
pays quarterly dividends, when declared by the Board of Directors, and are
payable-in-kind ("PIK Dividend") until October 1999, and in cash thereafter.
The 8.50% preferred stock is redeemable at the option of the Company at any time
after October 2000 at 106% of its stated value declining by 2% per annum
thereafter. The liquidation preference is $25 per share, plus accrued and
unpaid dividends. As of September 30, 1999, there were 1,809,544 shares of 8.50%
preferred stock outstanding with an aggregate liquidation preference of $45.2
million. The 8.50% preferred stock is privately held. Holders of the 8.50%
preferred stock are entitled to vote with the common stock, based upon the
number of shares of common stock into which the shares of 8.50% preferred stock
are convertible. The Company paid $2.6 million and $2.8 million in PIK Dividends
(issued an additional 105,892 and 110,610 8.50% preferred shares) during the
nine months ended September 30, 1998 and 1999, respectively.
The Company adopted Statement of Financial Accounting Standards No. 128
("SFAS 128"), "Earnings per Share" during 1997. SFAS 128 specifies computation,
presentation and disclosure requirements for earnings per share for entities
with publicly held common stock or potential common stock. All prior period
earnings per share amounts have been restated in accordance with SFAS 128.
<TABLE>
<CAPTION>
Three Months Ended Three Months Ended
September 30, 1998 September 30, 1999
--------------------------- -----------------------
Net Common Per Net Common Per
Loss Shares Share Income Shares Share
--------- -------- ------ ------- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Basic net income (loss) $(1,464) 15,934 $5,280 16,029
7.125% preferred stock dividends (654) - (567) -
8.50% preferred stock dividends (901) - (941) -
Preferred stock accretion (48) - (83) -
--------- -------- ------- ------
Basic net income (loss) attributable
to common stock (3,067) 15,934 $(0.19) 3,689 16,029 $0.23
====== =====
Effect of dilutive securities:
7.125% preferred stock - - 567 3,834
8.50% preferred stock - - 941 4,663
Stock options - - - 422
Stock grant - - - 277
$12.50 common stock warrants - - - -
--------- -------- ------- ------
Diluted net income (loss) attributable
to common stock $(3,067) 15,934 $(0.19) $ 5,197 25,225 $0.21
========= ======== ====== ======= ====== =====
</TABLE>
13
<PAGE>
<TABLE>
<CAPTION>
Nine Months Ended Nine Months Ended
September 30, 1998 September 30, 1999
---------------------------- ------------------------
Net Common Per Net Common Per
Loss Shares Share Income Shares Share
--------- ------- ------- ------- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Basic net income (loss) $(2,661) 16,117 $ 5,004 15,913
7.125% preferred stock dividends (1,961) - (1,859) -
8.50% preferred stock dividends (2,648) - (2,766) -
Preferred stock accretion (142) - (248) -
------- ------- ------- -------
Basic net income (loss) attributable
to common stock (7,412) 16,117 $ (0.46) 131 15,913 $0.01
======= =====
Effect of dilutive securities:
7.125% preferred stock - - - -
8.50% preferred stock - - - -
Stock options - - - 173
Stock grant - - - 277
$12.50 common stock warrants - - - -
------- ------- ------- -------
Diluted net income (loss) attributable
to common stock $(7,412) 16,117 $ (0.46) $ 131 16,363 $0.01
======= ======= ======= ======= ======= =====
</TABLE>
The potential common stock equivalents of the 7.125% and 8.50% preferred
stock, $12.50 common stock warrants and stock options were anti-dilutive for all
periods presented except for the periods identified above.
(6) EMPLOYEE BENEFIT PLANS
401(k) Savings
The Company has a 401(k) profit sharing and savings plan (the "401(k)
Plan"). Eligible employees may make voluntary contributions to the 401(k) Plan.
The amount of employee contributions is limited as specified in the 401(k) Plan.
The Company may, at its discretion, make additional matching or profit sharing
contributions to the 401(k) Plan. The Company has historically made profit
sharing contributions to the 401(k) Plan, which totaled $338,000 for 1998. The
1998 profit sharing contribution was made through the issuance of 138,462 shares
of the Company's common stock.
Stock Purchase Plan
In 1998, the Company adopted and the stockholders approved a stock purchase
plan ("Stock Purchase Plan"). Pursuant to the Stock Purchase Plan, officers,
directors and certain managers are eligible to purchase shares of common stock
at prices ranging from 50% to 85% of the closing price of the stock on the
trading day prior to the date of purchase ("Closing Price"). In addition,
employee participants may be granted the right to purchase shares pursuant to
the Stock Purchase Plan with all or a part of their salary and bonus. A total
of 500,000 shares of common stock are reserved for possible purchase under the
Stock Purchase Plan. In May 1999, an amendment to the Stock Purchase Plan was
approved by the stockholders allowing for the annual renewal of the 500,000
shares of common stock reserved for possible purchase under the Plan. In 1998,
the Board of Directors approved 291,250 common shares (exclusive of shares
available for purchase with participants' salaries and bonuses) for possible
purchase by participants at 75% of the Closing Price during the current Plan
Year as defined in the Stock Purchase Plan. As of December 31, 1998,
participants had purchased 257,632 shares of common stock, including 76,712
shares purchased with participant's 1997 bonuses, at prices ranging from $3.69
to $7.31 per share ($2.77 to $5.48 net price per share), resulting in cash
proceeds to the Company of $1.3 million. In 1999, the Board of Directors
approved 136,250 common shares (exclusive of shares available for purchase with
participants' salaries and bonuses) for possible purchase by participants at 75%
of the Closing Price during the current Plan Year as defined in the Stock
Purchase Plan. As of September 30, 1999, participants had purchased 92,850
shares of common stock at prices ranging from $5.06 to $8.63 per share ($3.80 to
$6.47 net price per share), resulting
14
<PAGE>
in cash proceeds to the Company of $395,000. The Company recorded non-cash
general and administrative expenses of $172,000 and $53,000 associated with
these purchases for the nine months ended September 30, 1998 and 1999.
Stock Option and Award Plans
In 1996, the shareholders adopted a stock option plan for employees
providing for the issuance of options at prices not less than fair market value.
Options to acquire the greater of up to three million shares of common stock or
10% of outstanding diluted common shares may be outstanding at any given time.
The specific terms of grant and exercise are determinable by a committee of
independent members of the Board of Directors. A summary by year of stock
options granted under the stock option plan for employees is summarized below:
Weighted
Range Average
of Exercise Exercise
Options Price Per Price Per
Year Granted Common Share Common Share
---- ------- -------------- ------------
1996............ 512,000 $ 7.75 $7.75
1997............ 521,000 $8.75 - $9.88 $9.75
1998............ 614,000 $6.56 - $7.19 $7.03
1999............ 628,000 $2.94 - $9.13 $3.53
The options vest over a three-year period (30%, 60%, 100%) and expire five
years from the date of grant, except for 250,000 fully vest five year options
which were granted in October 1997 at an exercise price of $9.88.
In 1996, the shareholders adopted a stock grant and option plan (the
"Directors' Plan") for nonemployee Directors. The Directors' Plan provides for
each nonemployee Director to receive common shares having a market value equal
to $2,500 quarterly in payment of one-half their retainer. A total of 3,632
shares were issued in 1996, 4,512 shares were issued in 1997, 11,914 shares were
issued in 1998 and 7,070 were issued in the first nine months of 1999. It also
provides for 5,000 options to be granted annually to each nonemployee Director.
A summary by year of stock options granted under the Directors' Plan is
summarized below:
Weighted
Range Average
of Exercise Exercise
Options Price Per Price Per
Year Granted Common Share Common Share
---- ------- -------------- ------------
1996........... 20,000 $ 7.75 $7.75
1997........... 30,000 $8.63 - $10.31 $9.19
1998........... 35,000 $7.19 - $7.75 $7.59
1999........... 30,000 $2.94 - $5.13 $4.76
The options vest over a three-year period (30%, 60%, 100%) and expire five
years from date of grant.
In 1997, the shareholders approved a special stock grant and purchase plan
for certain officers and managers ("Management Investors") in conjunction with
the redistribution of SOCO's ownership in the Company. The plan, which was
amended effective December 31, 1997, provided for the grant of 496,250
restricted common shares to the Management Investors. These shares vest at 25%
per year on January 1, 1998, 1999, 2000 and 2001. The non-vested granted common
shares have been recorded as Deferred Compensation in the equity section of the
accompanying consolidated balance sheets. The Management Investors
simultaneously purchased 303,797 common shares from the Company at $9.875 per
share. A portion of this original purchase ($850,000) was financed by the
Company. See Note (9).
15
<PAGE>
In conjunction with the appointment of a President in March 1998, the
President was included in the stock grant and purchase plans. He was granted
100,000 restricted common shares that vest at 33% per year in March 1999, 2000
and 2001. The non-vested granted common shares have been recorded as Deferred
Compensation in the equity section of the accompanying consolidated balance
sheets. The President simultaneously purchased 100,000 common shares from the
Company at $6.875 per share. A portion of this purchase ($584,000) was financed
by the Company. See Note (9).
In April 1999, the Chief Executive Officer was granted 100,000 restricted
shares of common stock in consideration of his voluntary reduction in cash
salary, waiver of any 1998 bonus and other compensation arrangements. The shares
vest ratably throughout 1999 and have been recorded as Deferred Compensation in
the equity section of the accompanying consolidated balance sheets.
The Company recognized $1.1 million and $769,000 of non-cash general and
administrative expenses for the nine months ended September 30, 1998 and 1999
with respect to these stock grants.
(7) FEDERAL INCOME TAXES
A reconciliation of the federal statutory rate to the Company's effective
rate as they apply to the provision (benefit) for the nine months ended
September 30, 1998 and 1999 follows:
1998 1999
------ ------
Federal statutory rate...................................... (35%) 35%
Utilization of net deferred tax asset....................... - -
Increase (decrease) in valuation allowance against
deferred tax asset.......................................... 35% (35%)
------ ------
Effective income tax rate................................... - -
====== ======
For tax purposes, the Company had regular net operating loss carryforwards
of approximately $90.3 million and alternative minimum tax ("AMT") loss
carryforwards of approximately $44.2 million at December 31, 1998. Utilization
of the regular and AMT net operating loss carryfowards will be limited to
approximately $12.5 million per year as a result of the redistribution of SOCO's
majority ownership in the Company in 1997. In addition, utilization of $31.9
million regular net operating loss carryforwards and $31.6 million AMT loss
carryforwards will be limited to $5.2 million per year as a result of the
Gerrity Acquisition in May 1996. These carryforwards expire from 2006 through
2018. At December 31, 1998, the Company had alternative minimum tax credit
carryforwards of $650,000 which are available indefinitely. There were no cash
payments made by the Company for federal taxes during 1997. The Company paid
$239,000 of federal taxes during 1998.
(8) MAJOR CUSTOMERS
During the nine months ended September 30, 1998 and 1999, Duke Energy Field
Services, Inc. accounted for 39% and 37%, Amoco Production Company accounted for
13% and 23%, Enron Capital & Trade Resources accounted for 12% and 4%, and
Aurora Natural Gas, LLC accounted for zero and 12% of revenues, respectively.
Management believes that the loss of any individual purchaser would not have a
long-term material adverse impact on the financial position or results of
operations of the Company.
(9) RELATED PARTY
In October 1997, certain officers and managers purchased 303,797 common
shares at $9.875 per share from the Company. A portion of this original
purchase ($850,000) was financed by the Company through the issuance of 8.50%
recourse promissory notes. The remaining notes are secured by the common stock
purchased and additional common shares granted to the respective officers and
managers. Interest is due annually and the notes mature in January 2001. These
notes have been reflected as Other Assets in the accompanying consolidated
balance sheets.
16
<PAGE>
In conjunction with the appointment of a President in March 1998, the
President purchased 100,000 shares of common stock at $6.875 per share. The
Company loaned him $584,000, or 85% of the purchase price, represented by a
recourse promissory note that bears interest at 8.50% per annum payable each
March 31 until the note is paid. The note matures in March 2001 and is secured
by all of the shares purchased and granted to him (100,000 shares) in connection
with his employment with the Company. The note has been reflected as Other
Assets in the accompanying consolidated balance sheets. In consideration of the
then depressed stock price and overall lower 1998 bonuses, the interest due as
of March 31, 1999 under the Management Investors' and President's notes was
forgiven.
(10) COMMITMENTS AND CONTINGENCIES
The Company leases office space and certain equipment under non-cancelable
operating leases. Future minimum lease payments under such leases approximate
$500,000 per year through 2001.
The Company is a party to various lawsuits incidental to its business, none
of which are anticipated to have a material adverse impact on its financial
position or results of operations.
17
<PAGE>
PATINA OIL & GAS CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Three months ended September 30, 1999 compared to three months ended September
30, 1998.
Revenues for the third quarter of 1999 totaled $24.5 million, a 32%
increase from the prior year period. The increase was due primarily to increases
in production and higher oil and gas prices. Net income for the third quarter
of 1999 totaled $5.3 million compared to a net loss of $1.5 million in the third
quarter of 1998. The increase was attributed to higher production, cost
efficiencies and recovering oil and gas prices.
Average daily oil and gas production for the third quarter totaled 4,377
barrels and 82.1 MMcf (108.3 MMcfe), an increase of 11% on an equivalent basis
from the same period in 1998. During the quarter, four wells were drilled or
deepened and 25 refracs were performed, compared to ten wells and 23 refracs and
recompletions in the same period of 1998. The Company's current development
activity, the benefits of certain minor acquisitions and continued success with
the production enhancement program has resulted in increasing production for
five successive quarters. The decision to increase development activity is
heavily dependent on the prices being received for production.
Average oil prices increased 35% from $12.83 per barrel in the third
quarter of 1998 to $17.35 in 1999. Average natural gas prices increased 24% from
$1.85 per Mcf for the third quarter of 1998 to $2.29 in 1999. The average oil
price in 1999 includes hedging losses of $1.0 million or $2.55 per barrel. The
average natural gas prices include hedging gains of $677,000 or $0.11 per Mcf in
1998 and hedging losses $1.5 million or $0.19 per Mcf in 1999, respectively.
Direct operating expenses, consisting of lease operating and production taxes,
totaled $4.8 million or $0.48 per Mcfe for the third quarter of 1999 compared to
$4.2 million or $0.47 per Mcfe in the prior year period. The increase in direct
operating expenses was entirely attributable to a sharp rise in production taxes
due to higher oil and gas prices and production offset by a decrease in lease
operating expenses of $160,000.
General and administrative expenses, net of third party reimbursements, for
the third quarter of 1999 totaled $1.6 million, a $145,000 or 8% decrease from
the same period in 1998. The reduction in general and administrative expense
was due to the Company's cost reduction program implemented at the beginning of
1999. Included in general and administrative expenses is $289,000 and $356,000
for the three months ended September 30, 1999 and 1998 of non-cash expenses
related to the common stock grants awarded to certain officers and managers of
the Company in conjunction with the redistribution of SOCO's ownership of the
Company in 1997.
Interest and other expenses fell to $2.4 million in the third quarter of
1999, a $949,000 or 28% decline from the prior year period. Interest expense
decreased as a result of lower average debt balances outstanding and lower
interest rates on the Company's debt due to the redemption of the 11.75%
Subordinated Notes on July 15, 1999. The redemption was financed with borrowings
under the bank credit facility. The average interest rate for the third quarter
of 1999 was 7.1% compared to 10.0% in the third quarter of 1998.
Depletion, depreciation and amortization expense for the third quarter of
1999 totaled $10.3 million, a decrease of $373,000 or 3% from the 1998 level.
Depletion expense totaled $10.1 million or $1.01 per Mcfe for the third quarter
of 1999 compared to $10.5 million or $1.17 per Mcfe for 1998. The decrease in
depletion expense resulted primarily from a lower depletion rate, partially
offset by higher production quantities. The depletion rate was lowered in the
second quarter of 1999 in conjunction with the completion of an internal mid-
year reserve report reflecting additional oil and gas reserves due primarily to
the identification of additional refrac projects and drilling locations and
upward revisions due to over-performance and the increase in oil and gas prices.
Depreciation and amortization expense for the three months ended September 30,
1999 totaled $242,000, or $0.02 per Mcfe compared to $211,000, or $0.02 per Mcfe
for the same period in 1998.
18
<PAGE>
Nine months ended September 30, 1999 compared to nine months ended September 30,
1998.
Revenues for the nine months ended September 30, 1999 totaled $61.6
million, a 7% increase from the prior year period. The increase was due
primarily to higher production and oil prices. Net income in the first nine
months of 1999 was $5.0 million compared to a net loss of $2.7 million in the
first nine months of 1998. The increase was attributed to higher production,
cost efficiencies and recovering oil prices.
Average daily oil and gas production for the first nine months of 1999
totaled 4,469 barrels and 78.4 MMcf (105.2 MMcfe), an increase of 9% on an
equivalent basis from the same period in 1998. Twenty-five wells were drilled
or deepened and 74 refracs and recompletions were performed during the first
nine months of 1999, compared to 23 wells and 59 refracs and recompletions in
the same period of 1998. The Company's current development activity, the
benefits of certain minor acquisitions and continued success with the production
enhancement program has resulted in increasing production for five successive
quarters. The decision to increase development activity is heavily dependent on
the prices being received for production.
Average oil prices increased from $13.86 per barrel in the first nine
months of 1998 to $14.68 in 1999. Average natural gas prices increased from
$1.99 per Mcf for the first nine months of 1998 to $2.00 in 1999. The average
oil prices includes hedging gains of $285,000 or $0.22 per barrel in 1998 and
hedging losses of $1.4 million or $1.14 per barrel in 1999. The average natural
gas prices include hedging gains of $1.4 million or $0.07 per Mcf in 1998 and
hedging losses of $1.1 million or $0.05 per Mcf in 1999. Direct operating
expenses totaled $13.3 million or $0.46 per Mcfe for the first nine months of
1999 compared to $13.1 million or $0.50 per Mcfe in the prior year period.
General and administrative expenses, net of third party reimbursements, for
the first nine months of 1999 totaled $4.4 million, a $1.2 million or 21%
decrease from the same period in 1998. The reduction in general and
administrative expense was due to the Company's cost reduction program
implemented at the beginning of 1999. Included in general and administrative
expenses is $769,000 and $1.1 million for the nine months ended September 30,
1999 and 1998 of non-cash expenses related to the common stock grants awarded to
certain officers and managers of the Company in conjunction with the
redistribution of SOCO's ownership of the Company in 1997.
Interest and other expenses fell to $8.3 million for the nine-month period
ended September 30, 1999, a $1.7 million or 17% decline from the prior year
period. Interest expense decreased as a result of lower average debt balances
outstanding and lower interest rates on the Company's debt due to the redemption
of the 11.75% Subordinated Notes on July 15, 1999. The redemption was financed
with borrowings under the bank credit facility. The average interest rate for
the first nine months of 1999 was 8.4% compared to 10.3% in the first nine
months of 1998.
Depletion, depreciation and amortization expense for the nine-month period
ended September 30, 1999 totaled $30.4 million, a decrease of $1.0 million or 3%
from the 1998 level. Depletion expense totaled $29.7 million or $1.03 per Mcfe
for the first nine months of 1999 compared to $30.8 million or $1.17 per Mcfe
for 1998. The decrease in depletion expense resulted from a lower depletion
rate, partially offset by higher production quantities. The depletion rate was
lowered in the second quarter of 1999 in conjunction with the completion of an
internal mid-year reserve report reflecting additional oil and gas reserves due
primarily to the identification of additional refrac projects and drilling
locations and upward revisions due to over-performance and the increase in oil
and gas prices. Depreciation and amortization expense for the nine months ended
September 30, 1999 totaled $712,000, or $0.02 per Mcfe compared to $582,000, or
$0.02 per Mcfe for the same period in 1998.
19
<PAGE>
Development, Acquisition and Exploration
During the first nine months of 1999, the Company incurred $17.5 million in
capital expenditures, with development expenditures comprising $15.5 million.
During the period, the Company successfully drilled or deepened 25 wells,
recompleted one well and refraced 73 wells. The Company also acquired
additional proved reserves in Wattenberg for $1.8 million. The Company
anticipates incurring approximately $6.0 million on the further development of
its properties during 1999. The decision to increase or decrease development
activity is heavily dependent on the prices being received for production.
Financial Condition and Capital Resources
At September 30, 1999, the Company had $333.7 million of assets. Total
capitalization was $304.9 million, of which 57% was represented by stockholders'
equity and 43% by senior debt. During the nine months ended September 30, 1999,
net cash provided by operations totaled $27.5 million, as compared to $23.4
million in the first nine months of 1998 ($35.5 million and $28.4 million prior
to changes in working capital, respectively). At September 30, 1999, there were
no significant commitments for capital expenditures. The Company anticipates
1999 capital expenditures, exclusive of acquisitions, to approximate $23.0
million. The level of these and other future expenditures is largely
discretionary, and the amount of funds devoted to any particular activity may
increase or decrease significantly, depending on available opportunities and
market conditions. The Company plans to finance its ongoing development,
acquisition and exploration expenditures and additional security repurchases
using internal cash flow, proceeds from asset sales and bank borrowings. In
addition, joint ventures or future public and private offerings of debt or
equity securities may be utilized.
In July 1999, in conjunction with the redemption of the 11.75% Senior
Subordinated Notes, the Company entered into a Second Amended and Restated Bank
Credit Agreement (the "Credit Agreement"). The Credit Agreement is a revolving
credit facility in an aggregate amount up to $200.0 million. The amount
available under the facility is adjusted semiannually, each May 1 and November
1, and equaled $160.0 million at September 30, 1999.
The Credit Agreement contains certain financial covenants, including but
not limited to a maximum total debt to EBITDA ratio and a minimum current ratio.
The Credit Agreement also contains certain negative covenants, including but not
limited to restrictions on indebtedness; certain liens; guaranties, speculative
derivatives and other similar obligations; asset dispositions; dividends, loans
and advances; creation of subsidiaries; investments; leases; acquisitions;
mergers; changes in fiscal year; transactions with affiliates; changes in
business conducted; sale and leaseback and operating lease transactions; sale of
receivables; prepayment of other indebtedness; amendments to principal
documents; negative pledge causes; issuance of securities; and non-speculative
commodity hedging. Borrowings under the Credit Agreement mature in July 2003,
but may be prepaid at anytime. The Company has periodically negotiated
extensions of the Credit Agreement; however, there is no assurance the Company
will be able to do so in the future. The Company had a restricted payment basket
of $5.7 million as of September 30, 1999, which may be used to repurchase common
stock, preferred stock and warrants and pay dividends on its common stock.
The Company may elect that all or a portion of the credit facility bear
interest at a rate equal to: (i) the higher of (a) the prime rate or (b) the
Federal Funds Effective Rate plus .5%, or ii) the rate at which Eurodollar
deposits for one, two, three or six months (as selected by the Company) are
offered in the interbank Eurodollar market plus a margin which fluctuates from
1.00% to 1.50%, determined by a debt to EBITDA ratio. During the nine-month
period ended September 30, 1999, the average interest rate under the facility
approximated 6.4%.
In October 1998, the Company entered into an interest rate swap contract
for a two-year period, extendable for one additional year at the option of the
third party. The contract is for $30.0 million principal with a fixed interest
rate of 4.57% payable by the Company and the variable interest rate, the three-
month LIBOR, payable by the third party. The difference between the Company's
fixed rate of 4.57% and the three-month LIBOR rate, which is reset every 90
days, is received or paid by the Company in arrears every 90 days. The Company
received $59,000 in January 1999, $36,000 in April 1999, $33,000 in July 1999
and $57,000 in October 1999 pursuant to this contract.
20
<PAGE>
The Company had $72.3 million of 11.75% Senior Subordinated Notes due July
15, 2004 outstanding on June 30, 1999. The Notes had been reflected in the
accompanying financial statements at a book value of 105.875% of their principal
amount, the initial call price ($68.3 million of principal amount outstanding as
of June 30, 1999). The Notes became redeemable on July 15, 1999. The Company
redeemed all of the Notes at the call price of 105.875% on July 15, 1999. The
redemption was financed with borrowings under the bank credit facility.
In conjunction with the appointment of a President in March 1998, the
President purchased 100,000 shares of common stock at $6.875 per share. The
Company loaned him $584,000, or 85% of the purchase price, represented by a
recourse promissory note that bears interest at 8.50% per annum payable each
March 31 until the note is paid. The note matures in March 2001 and is secured
by the 200,000 shares purchased and granted to him in connection with his
employment with the Company.
The Company has entered into arrangements to monetize its Section 29 tax
credits. These arrangements result in revenue increases of approximately $0.40
per Mcf on production volumes from qualified Section 29 properties. As a
result, the Company recognized additional gas revenues of $1.5 million and $2.0
million for the nine months ended September 30, 1998 and 1999, respectively.
These arrangements are expected to increase revenues through 2002.
The Company's primary cash requirements will be to finance acquisitions,
development expenditures, repayment of indebtedness, and general working capital
needs. However, future cash flows are subject to a number of variables,
including the level of production and oil and natural gas prices, and there can
be no assurance that operations and other capital resources will provide cash in
sufficient amounts to maintain planned levels of capital expenditures or that
increased capital expenditures will not be undertaken.
The Company believes that available borrowings under its Credit Agreement,
projected operating cash flows and the cash on hand will be sufficient to cover
its working capital, capital expenditures, planned development activities and
debt service requirements for the next 12 months. In connection with
consummating any significant acquisition, additional debt or equity financing
will be required, which may or may not be available on terms that are acceptable
to the Company.
Certain Factors That May Affect Future Results
Statements that are not historical facts contained in this report are
forward-looking statements that involve risks and uncertainties that could cause
actual results to differ from projected results. Such statements address
activities, events or developments that the Company expects, believes, projects,
intends or anticipates will or may occur, including such matters as future
capital, development and exploration expenditures (including the amount and
nature thereof), drilling or deepening of wells, reserve estimates (including
estimates of future net revenues associated with such reserves and the present
value of such future net revenues), future production of oil and natural gas,
business strategies, expansion and growth of the Company's operations, cash flow
and anticipated liquidity, prospect development and property acquisition,
obtaining financial or industry partners for prospect or program development, or
marketing of oil and natural gas. Factors that could cause actual results to
differ materially ("Cautionary Disclosures") are described, among other places,
in the Marketing, Competition, and Regulation sections in the Company's 1998
Form 10-K and under the caption "Management's Discussion and Analysis of
Financial Condition and Results of Operations." Without limiting the Cautionary
Disclosures so described, Cautionary Disclosures include, among others: general
economic conditions, the market price of oil and natural gas, the risks
associated with exploration, the Company's ability to find, acquire, market,
develop and produce new properties, operating hazards attendant to the oil and
natural gas business, uncertainties in the estimation of proved reserves and in
the projection of future rates of production and timing of development
expenditures, the strength and financial resources of the Company's competitors,
the Company's ability to find and retain skilled personnel, climatic conditions,
labor relations, availability and cost of material and equipment, environmental
risks, the results of financing efforts, and regulatory developments. All
written and oral forward-looking statements attributable to the Company or
persons acting on its behalf are expressly qualified in their entirety by the
Cautionary Disclosures. The Company disclaims any obligation to update or
revise any forward-looking statement to reflect events or circumstances
occurring hereafter or to reflect the occurrence of anticipated or unanticipated
events.
21
<PAGE>
Year 2000 Issues
The Company is aware of the issues associated with the programming code in
many existing computer systems and devices with embedded technology as the
millennium approaches. The "Year 2000" problem concerns the inability of
information and technology-based operating systems to properly recognize and
process date-sensitive information beyond December 31, 1999. The Year 2000
problem is potentially pervasive; virtually every computer operation or business
system that utilizes embedded computer technology may be affected in some way by
the rollover of the two-digit year value to 00. The risk is that computer
systems will not properly recognize date sensitive information when the year
changes to 2000, which could result in system failures or miscalculations,
resulting in a serious threat of business disruption.
In response to the potential impact of the Year 2000 issue on the Company's
business and operations, the Board of Directors formed a Year 2000 Committee
consisting of members of senior management and the Information Systems Manager.
The committee reports to the Board at each quarterly meeting as to the progress
of the evaluation and the necessity for any systems modifications and
contingency planning. This committee has assessed the readiness for Year 2000
compliance of the Company's internal computer systems and field operations and
continues to identify its critical and non-critical third party dependencies
with respect to vendors, suppliers, customers and other significant business
relationships.
The internal assessment included a review of the Company's inventory of
computer hardware and software. During 1998, the Company purchased and
converted to its own in-house computer system. In conjunction with this
process, the Company determined that the new systems and hardware were
substantially Year 2000 compliant. Certain other software has been corrected or
reprogrammed for Year 2000 compliance. Based on current information from system
and software vendors, all internal systems and software are Y2K compliant.
However, the software updates to our internal field gathering and reporting
production system, have not been installed. These updates will be installed by
November 15, 1999, allowing adequate time for testing. As such, management
believes the Year 2000 issues with respect to its internal systems can be
mitigated without a significant potential effect on the Company's financial
position or operations.
The Company's internal review also included an assessment of the field
operations and any related software or control equipment with embedded chip
technology utilized in the production and development of its oil and gas
properties. Through vendor inquiries and actual field testing, the Company
anticipates minimal disruption of the field operations and equipment.
In addition, to ensure external Year 2000 readiness, the Company made
written inquiries concerning the Year 2000 readiness of all of its vendors,
suppliers, customers and others with whom the Company has significant business
relationships. Responses have been received from many of those contacted,
although some of the responses have been inconclusive with respect to Year 2000
compliance. As a result, follow up inquiries were made for any critically
dependent third parties not responding. Upon review of the responses and
discussions with certain critically dependant third parties, the Company is not
currently aware of any third party issues that would cause a significant
disruption of its business or operations. If any subsequent information is
received from any significant third party indicating that they will not be Year
2000 compliant, it may be necessary to develop contingency plans to minimize the
negative impact on the Company.
The Company also relies on non-information technology systems such as
telephones, facsimile machines, air conditioning, heating, elevators in its
leased office building and other equipment which may have embedded technology
such as micro processors, which may or may not be Year 2000 compliant. Written
inquiries have been sent to these third parties, but as much of this technology
is outside of the Company's control and not easily tested by these entities, it
is difficult to assess or remedy any such non-compliance that could adversely
affect the Company's ability to conduct business. Management believes any such
disruption is not likely to have a significant effect on the Company's financial
position or operations.
22
<PAGE>
Although the Company currently anticipates that minimal business disruption
will occur as a result of Year 2000 issues, in the event the computer based
programs and embedded technology equipment of the Company, or that owned and
operated by third parties, should fail to function properly, possible
consequences include but are not limited to loss of communication links,
inability to produce and transport oil and natural gas, loss of electric power,
and the inability to engage in normal automated or computerized business
activities.
The Company's goal was to have all internal systems Year 2000 compliant,
and third party assessments completed no later than September 30, 1999. Based on
internal reviews and responses from critical third parties as to their Y2K
efforts and compliance, the Company's review was substantially completed by that
date with no significant problems or non-compliance noted. Accordingly, the
Company anticipates minimal business disruption with respect to Y2K. However,
given the complexity of the Year 2000 issue, there can be no assurance that the
Company was able to address all these problems and may incur additional costs
and encounter uncertainties that might affect future financial results or cause
reported financial information not to be necessarily indicative of future
operating results or future financial condition. The Company will utilize our
internal communication tree to further evaluate and act upon any unexpected
events. The total costs incurred to date in the assessment, evaluation and
remediation of the Year 2000 compliance matters have been nominal and management
estimates that total future third party, software and equipment costs, based
upon information developed to date, will be less than $25,000.
Market and Commodity Risk
The Company's major market risk exposure is in the pricing applicable to
its oil and natural gas production. Realized pricing is primarily driven by the
prevailing domestic price for oil and spot prices applicable to the Rocky
Mountain and Mid-Continent regions for its natural gas production. Historically,
prices received for oil and gas production have been volatile and unpredictable.
Pricing volatility is expected to continue. Natural gas price realizations
during 1998 ranged from a monthly low of $1.79 per Mcf to a monthly high of
$2.36 per Mcf and ranged from a monthly low of $1.68 per Mcf to a monthly high
of $2.43 per Mcf during the first nine months of 1999. Oil prices ranged from a
monthly low of $9.56 per barrel to a monthly high of $17.44 per barrel during
1998 and ranged from a monthly low of $10.70 per barrel to a monthly high of
$17.51 per barrel during the first nine months of 1999. Both oil and natural gas
prices increased significantly from the first quarter to the third quarter of
1999. A significant decline in the prices of oil or natural gas could have a
material adverse effect on the Company's financial condition and results of
operations.
From time to time, the Company enters into commodity derivative contracts
and fixed-price physical contracts to manage its exposure to oil and gas price
volatility and to support oil and natural gas prices at targeted levels. The
Company uses futures contracts, swaps, options and fixed-price physical
contracts to hedge its commodity prices. Realized gains or losses from price
risk management activities are recognized in oil and gas sales revenues in the
period in which the associated production occurs.
As of September 30, 1999, the Company had entered into swap contracts for
oil (NYMEX based) for approximately 3,200 barrels of oil per day for remainder
of 1999 at fixed prices ranging from $18.07 to $23.66 per barrel and
approximately 2,300 barrels of oil per day for 2000 at fixed prices ranging from
$18.86 to $22.20 per barrel. Certain swap contracts for oil (NYMEX based)
contain "knock out" provisions. These contracts cover 1,000 barrels of oil per
day with a swap price of $21.00 per barrel and a "knock out" price of $16.00 per
barrel for the period January 2000 to December 2000 and 500 barrels of oil per
day with a swap price of $22.20 per barrel and a "knock out" price of $17.00 per
barrel for the period March 2000 to December 2000. If the average price of NYMEX
WTI crude oil falls below the "knock out" price for the contract month, the
swaps will be considered "knocked out" and no payment will be made to the
Company for the applicable month. The overall weighted average hedged price for
the swap contracts is $19.21 per barrel for the remainder of 1999 and $20.85 per
barrel for 2000 (NYMEX based). The unrecognized losses on these contracts
totaled $2.1 million based on estimated market values as of September 30, 1999.
23
<PAGE>
As of September 30, 1999, the Company had entered into natural gas swap
contracts for approximately 25,000 MMBtu's per day of natural gas for the
remainder of 1999 at fixed prices ranging from $1.97 per MMBtu on CIG index
based swap contracts to $3.00 per MMBtu on a PEPL index based swap contract and
approximately 17,000 MMBtu's per day for the period January 2000 through October
2000 at fixed prices ranging from $2.05 to $2.62 per MMBtu on CIG index based
swap contracts. The Company also has entered into physical natural gas sale
contracts for the delivery of approximately 13,000 MMBtu's per day of natural
gas for the remainder of 1999 at prices ranging from $1.82 to $2.84 per MMBtu
and approximately 15,000 of MMBtu's per day for the period January 2000 through
March 2000 at prices ranging from $2.73 to $2.84 per MMBtu. The weighted average
daily volumes and prices for these natural gas swaps and physical contracts are
38,000 MMBtu's per day at $2.49 per MMBtu for the remainder of 1999 and 21,500
MMBtu's per day at $2.30 per MMBtu for the period January 2000 through October
2000. The unrecognized losses on these contracts totaled $867,000 based on
estimated market values as of September 30, 1999.
Inflation and Changes in Prices
While certain of its costs are affected by the general level of inflation,
factors unique to the oil and natural gas industry result in independent price
fluctuations. Over the past five years, significant fluctuations have occurred
in oil and natural gas prices. Although it is particularly difficult to
estimate future prices of oil and natural gas, price fluctuations have had, and
will continue to have, a material effect on the Company.
The following table indicates the average oil and natural gas prices
received over the last five years and highlights the price fluctuations by
quarter for 1998 and 1999. Average price computations exclude hedging gains and
losses and other nonrecurring items to provide comparability. Average prices per
Mcfe indicate the composite impact of changes in oil and natural gas prices. Oil
production is converted to natural gas equivalents at the rate of one barrel per
six Mcf.
Average Prices
--------------------------------
Natural Equivalent
Oil Gas Mcf
--- --- ---
(Per Bbl) (Per Mcf) (Per Mcfe)
Annual
------
1994....................... $14.84 $1.70 $1.94
1995....................... 16.43 1.34 1.73
1996....................... 20.47 1.99 2.41
1997....................... 19.54 2.25 2.55
1998....................... 13.13 1.87 1.96
Quarterly
---------
1998
----
First...................... $14.70 $2.04 $2.16
Second..................... 13.41 1.95 2.03
Third...................... 12.83 1.72 1.84
Fourth..................... 11.45 1.78 1.81
1999
----
First...................... $11.65 $1.65 $1.72
Second..................... $16.10 $1.99 $2.17
Third...................... $19.90 $2.48 $2.68
24
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Information with respect to this item is incorporated by reference from
Notes to Consolidated Financial Statements in Part 1 of this report.
Item 4. Submission of Matters to a Vote of Security Holders
None
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits -
27 Financial Data Schedule.*
* Filed herewith
(b) No reports on Form 8-K were filed by Registrant during the quarter ended
September 30, 1999.
25
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PATINA OIL & GAS CORPORATION
BY /s/ David J. Kornder
------------------------------------------
David J. Kornder, Vice President and Chief
Financial Officer
October 28, 1999
26
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