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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------------------------------
FORM 10-K
(Mark one)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transaction 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 80202
Denver, Colorado (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (303) 389-3600
<TABLE>
<CAPTION>
<S> <C>
Title of each class Name of each exchange on which registered
- -------------------------------------------------- -----------------------------------------
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
(Title of Class)
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.
[X] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the 13,888,554 shares of voting stock held by
non-affiliates of the registrant, based upon the closing sale price of the
common stock on March 4, 1999 of $3.06 per share as reported on the New York
Stock Exchange, was $42,534,000. Shares of common stock held by each officer
and director and by each person who owns 5% or more of the outstanding common
stock have been excluded in that such persons may be deemed affiliates. This
determination of affiliate status is not necessarily a conclusive determination
for other purposes.
As of March 4, 1999, the registrant had 15,803,702 shares of common stock
outstanding.
DOCUMENT INCORPORATED BY REFERENCE
Part III of the report is incorporated by reference to the Registrant's
definitive Proxy Statement relating to its Annual Meeting of Stockholders, which
will be filed with the Commission no later than April 30, 1999
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<PAGE>
PATINA OIL & GAS CORPORATION
Annual Report on Form 10-K
December 31, 1998
PART I
ITEM 1. BUSINESS
General
Patina Oil & Gas Corporation ("Patina" or the "Company") is an independent
energy company engaged in the acquisition, development, exploitation and
production of oil and natural gas in the Wattenberg Field ("Wattenberg" or the
"Field") of Colorado's Denver-Julesburg Basin ("D-J Basin"). The Company was
formed in early 1996 to hold the Wattenberg assets of Snyder Oil Corporation
("SOCO") and to facilitate the acquisition of Gerrity Oil & Gas Corporation
("Gerrity" or the "Gerrity Acquisition") in May 1996. After the Gerrity
Acquisition, SOCO owned 14,000,000 or approximately 74% of the Company's common
shares. The amounts and results of operations of the Company for periods prior
to the Gerrity Acquisition reflect the historical amounts and results of SOCO's
Wattenberg operations. In October 1997, the Company effectuated a series of
transactions which eliminated SOCO's ownership in the Company.
Patina is one of the largest producers in Wattenberg and currently accounts
for over 30% of the total production from the Field. Wattenberg, a major
onshore producing basin with total cumulative production in excess of three
trillion cubic feet of natural gas equivalents since its discovery in 1970, is
located approximately 35 miles northeast of Denver and stretches over portions
of Adams, Boulder and Weld Counties in Colorado. One of the most attractive
features of Wattenberg is that there are up to eight potentially productive
formations throughout the field ranging in depths from 2,000 to 8,000 feet.
Three of the formations, the Codell, the Niobrara and the J-Sand, are "blanket"
zones in the area of the Company's holdings, while other formations, such as the
Sussex, Shannon and Dakota are more localized. The existence of several pay
sands within the geological structure allows for multiple completions within a
single wellbore, keeping drilling and operating costs low.
In May 1998, the Colorado Oil & Gas Commission adopted new spacing rules for
the Wattenberg Field that greatly enhanced the Company's ability to more
efficiently develop its properties. The rule also eliminated costly and time-
consuming procedures required for certain development activities. All
formations in the Field can now be drilled, produced and commingled from any or
all of ten "drilling windows" on a 320 acre parcel. Primarily as a result of
the new rule, the Company increased its capital development activities during
the year. The increase in development activity allowed the Company to realize
production growth during the second half of 1998 and increase its total proved
reserves over the prior year despite a significant reduction in oil and natural
gas prices.
At December 31, 1998, the Company had $351.5 million of assets and 372.0 Bcfe
of proved reserves. The reserves had an estimated pretax present value of $225.1
million based on unescalated prices and costs in effect on that date.
Approximately 77% of the reserves by volume were natural gas and over 95% of the
pretax present value was attributable to proved developed reserves. The Company
operates almost 95% of the roughly 3,400 producing wells in which it holds a
working interest, representing 99% of its producing reserve value. At December
31, 1998, the Company had 111 proved undeveloped drilling or deepening projects,
235 recompletions and 176 restimulation ("refrac") opportunities included in
total proved reserves. During 1998, production averaged 97.8 MMcfe per day.
Based on year-end 1998 reserves, the Company had a reserve life index of 10.4
years.
From its inception, the Company has focused on consolidating its properties,
developing an efficient organization, reducing costs and improving operations.
During 1998, the Company's revenues and net cash provided from operations
totaled $74.7 million and $34.3 million, respectively. The Company used its
operating cash flow to repurchase $8.7 million of its equity securities and
reduce indebtedness by $4.4 million. In addition, the Company invested $24.1
million in the further development of its properties, the acquisition of proved
reserves in Wattenberg and the acquisition of approximately
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90,000 gross acres in conjunction with a grassroots prospect in Wyoming. During
the year, the Company's development program was primarily comprised of drilling
or deepening 36 development wells, performing 54 refracs and recompleting 21
wells. The Company also completed various minor field projects consisting of
tubing installations and workovers designed to enhance production and reserves.
The successful results of this development activity allowed the Company to
realize production growth during the second half of 1998 and increase its total
proved reserves.
Since 1986, the Company and its predecessors have grown through a series of
acquisitions in combination with the further exploitation and development of its
properties. The Company and its predecessors have completed more than 65
acquisitions having an aggregate purchase price of over $450 million. During
the last six years, the Company has expended approximately $367 million on
development projects including the drilling or deepening of over 1,425 wells and
the recompletion or refrac of more than 475 wells. The Company seeks to
maximize the value of its oil and natural gas properties by increasing
production and recoverable reserves through the implementation of operational
improvements, workovers, multi-zone recompletions, refracs and the drilling or
deepening of new development wells.
Business Strategy
Management believes that the Company's sizable asset base and cash flow,
along with its low production costs and efficient operating structure, provide
it with a competitive advantage in Wattenberg and in certain analogous basins.
Given management's expertise in acquisitions and the advantages set forth above,
the Company believes it is in an excellent position to increase its reserves,
production and cash flows in a cost-efficient manner primarily through: (i)
selectively pursuing consolidation and acquisition opportunities in existing and
future core areas; (ii) further development and exploitation of its properties
in Wattenberg through development activity, well workovers and operational
improvements, and (iii) the generation of grassroots drilling prospects with the
potential to add significant reserves and production. Management believes that
the Company's strong financial position affords it the financial flexibility to
execute its business strategy.
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Production, Revenue and Price History
The following table sets forth information regarding net production of oil
and natural gas, revenues and direct operating expenses attributable to such
production, average sales prices and other production information for each of
the years in the five year period ended December 31, 1998. The financial and
operating information reflect the acquisition of Gerrity by the Company in May
1996.
<TABLE>
<CAPTION>
December 31,
--------------------------------------------
1994 1995 1996 1997 1998
------- ------- ------- -------- -------
(Dollars in thousands, except prices and
per Mcfe information)
<S> <C> <C> <C> <C> <C>
Production
Oil (MBbl)..................................................... 1,829 1,342 1,688 1,889 1,699
Gas (MMcf)..................................................... 23,893 20,981 23,947 26,863 25,522
MMcfe /a/...................................................... 34,872 29,034 34,074 38,194 35,715
Revenues
Oil............................................................ $27,151 $22,049 $34,541 $ 37,197 $22,583
Gas /b/........................................................ 40,598 28,024 47,644 62,342 49,594
------- ------- ------- -------- -------
Subtotal...................................................... 67,749 50,073 82,185 99,539 72,177
Other.......................................................... 73 29 1,003 794 2,533
------- ------- ------- -------- -------
Total......................................................... 67,822 50,102 83,188 100,333 74,710
------- ------- ------- -------- -------
Direct operating expenses
Lease operating expenses....................................... 3,662 5,387 8,866 11,735 12,399
Production taxes............................................... 4,448 3,480 5,653 7,055 4,941
------- ------- ------- -------- -------
Total......................................................... 8,110 8,867 14,519 18,790 17,340
------- ------- ------- -------- -------
Direct operating margin......................................... $59,712 $41,235 $68,669 $ 81,543 $57,370
======= ======= ======= ======== =======
Average sales price
Oil (Bbl)...................................................... $ 14.84 $ 16.43 $ 20.47 $ 19.70 $ 13.29
Gas (Mcf) /b/.................................................. 1.70 1.34 1.99 2.32 1.94
Mcfe /a/....................................................... 1.94 1.73 2.41 2.61 2.02
Average direct operating expense/Mcfe........................... 0.23 0.31 0.43 0.49 0.49
Average production margin/Mcfe.................................. 1.71 1.42 1.99 2.12 1.54
- -----------------------------------------
</TABLE>
/a/ Oil production is converted to natural gas equivalents (Mcfe) at the rate
of one barrel to six Mcf.
/b/ Sales of natural gas liquids are included in gas revenues.
Marketing
The Company's oil and natural gas production is principally sold to end
users, marketers, refiners and other purchasers having access to natural gas
pipeline facilities near its properties and the ability to truck oil to local
refineries or oil pipelines. The marketing of oil and natural gas can be
affected by a number of factors that are beyond the Company's control and which
cannot be accurately predicted. The Company does not believe, however, that the
loss of any of its customers would have a long-term material adverse effect on
its operations.
Natural Gas. Wattenberg natural gas is high in heating content (BTU's) and
must be processed in order to strip natural gas liquids ("NGL's") before residue
gas is sold to utilities, independent marketers and end users through both
intrastate and interstate pipelines. The Company utilizes two separate
arrangements to gather, process and market its natural gas production.
Approximately 30% of the Company's natural gas production is sold to Duke Energy
Field Services ("Duke Energy") at the wellhead under percentage of proceeds
contracts. Pursuant to this type of contract, the Company receives a fixed
percentage of the proceeds from the sale of its residue gas and NGL's by Duke
Energy. Substantially all of the
4
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Company's remaining natural gas production is dedicated for gathering to either
Duke Energy or KN Front Range Gathering Company ("KN") and is then processed at
plants owned by Duke Energy or Amoco Production Company ("Amoco"). Under this
arrangement, the Company retains the right to market its share of residue gas at
the tailgate of the plant and sells it under seasonal spot market arrangements
along the front range of Colorado or transports the gas to Midwest markets under
transportation agreements. NGL's are sold by the processor and the Company
receives payment net of applicable processing fees. A portion of the natural gas
processed by Amoco at the Wattenberg Processing Plant is under a favorable
contract that not only provides payment for a percentage of the NGL's stripped
from the natural gas, but also redelivers to the tailgate the same amount of
MMBtu's as was delivered to the plant under a "keepwhole" arrangement. This
agreement remains in effect until December 2012.
Oil. Oil production is principally sold to refiners, marketers and other
purchasers who truck oil to local refineries or pipelines. The price is
generally based on a local market posting for oil and is adjusted for
transportation costs and quality. Amoco has the right to purchase oil produced
from certain of the Company's properties.
Competition
The oil and natural gas industry is highly competitive. The Company
encounters competition from other oil and natural gas companies in all of its
operations, including the acquisition of exploration and development prospects
and producing properties. Patina competes for the acquisition of oil and natural
gas properties with numerous entities, including major oil companies, other
independent oil and natural gas concerns and individual producers and operators.
Many competitors have financial and other resources substantially greater than
those of the Company. The ability of the Company to increase reserves in the
future will be dependent on its ability to select and acquire suitable producing
properties and prospects for future development and exploration.
Title to Properties
Title to the Company's oil and natural gas properties is subject to royalty,
overriding royalty, carried and other similar interests and contractual
arrangements customary in the oil and natural gas industry, to liens incident to
operating agreements and for current taxes not yet due and other comparatively
minor encumbrances.
As is customary in the oil and natural gas industry, only a perfunctory
investigation as to ownership is conducted at the time undeveloped properties
believed to be suitable for drilling are acquired. Prior to the commencement of
drilling operations, a detailed title examination is conducted and curative work
is performed with respect to known significant title defects.
Regulation
Regulation of Drilling and Production. The Company's operations are affected
by political developments and by federal, state and local laws and regulations.
Legislation and administrative regulations relating to the oil and natural gas
industry are periodically changed for a variety of political, economic and other
reasons. Numerous federal, state and local departments and agencies issue rules
and regulations binding on the oil and natural gas industry, some of which carry
substantial penalties for failure to comply. The regulatory burden on the oil
and natural gas industry increases the Company's cost of doing business,
decreases flexibility in the timing of operations and may adversely affect the
economics of capital projects.
In the past, the federal government has regulated the prices at which oil and
natural gas could be sold. Prices of oil and natural gas sold by the Company are
not currently regulated. In recent years, the Federal Energy Regulatory
Commission ("FERC") has taken significant steps to increase competition in the
sale, purchase, storage and transportation of natural gas. FERC's regulatory
programs allow more accurate and timely price signals from the consumer to the
producer and, on the whole, have helped natural gas become more responsive to
changing market conditions. To date, the Company believes it has not experienced
any material adverse effect as the result of these initiatives. Nonetheless,
increased competition in natural gas markets can and does add to price
volatility and inter-fuel competition, which increases the pressure on the
Company to manage its exposure to changing conditions and position itself to
take advantage of changing market forces.
5
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State statutes govern exploration and production operations, conservation of
oil and natural gas resources, protection of the correlative rights of oil and
natural gas owners and environmental standards. State Commissions implement
their authority by establishing rules and regulations requiring permits for
drilling, reclamation of production sites, plugging bonds, reports and other
matters. Colorado, where the Company's producing properties are located, amended
its statute concerning oil and natural gas development in 1994 to provide the
Colorado Oil & Gas Conservation Commission (the "COGCC") with enhanced authority
to regulate oil and natural gas activities to protect public health, safety and
welfare, including the environment. Several rule makings pursuant to these
statutory changes have been undertaken by the COGCC concerning groundwater
protection, soil conservation and site reclamation, setbacks in urban areas and
other safety concerns, and financial assurance for industry obligations in these
areas. To date, these rule changes have not adversely affected operations of the
Company, as the COGCC is required to enact cost-effective and technically
feasible regulations, and the Company has been an active participant in their
development. However, there can be no assurance that, in the aggregate, these
and other regulatory developments will not increase the cost of conducting
operations in the future.
In Colorado, a number of city and county governments have enacted oil and
natural gas regulations. These ordinances increase the involvement of local
governments in the permitting of oil and natural gas operations, and require
additional restrictions or conditions on the conduct of operations so as to
reduce their impact on the surrounding community. Accordingly, these local
ordinances have the potential to delay and increase the cost of drilling and
recompletion operations.
Environmental Regulation. Operations of the Company are subject to numerous
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection. The Company currently owns or
leases numerous properties that have been used for many years for natural gas
and oil production. Although the Company believes that it and previous owners
have utilized operating and disposal practices that were standard in the
industry at the time, hydrocarbons or other wastes may have been disposed of or
released on or under the properties owned or leased by the Company. In
connection with its most significant acquisitions, the Company has performed
environmental assessments and found no material environmental noncompliance or
clean-up liabilities requiring action in the near or intermediate future. Such
environmental assessments have not, however, been performed on all of the
Company's properties.
The Company operates its own exploration and production waste management
facilities, which enable it to treat, bioremediate and otherwise dispose of tank
sludges and contaminated soil generated from the Company's operations. There can
be no assurance, that these facilities, or other commercial disposal facilities
utilized by the Company from time to time, will not give rise to environmental
liability in the future. To date, expenditures for the Company's environmental
control facilities and for remediation of production sites have not been
significant to Patina. The Company believes, however, that the trend toward
stricter standards in environmental legislation and regulations will continue
and could have a significant adverse impact on the Company's operating costs, as
well as on the oil and natural gas industry in general.
Office and Operations Facilities
The Company, a Delaware corporation, leases its principal executive offices
at 1625 Broadway, Denver, Colorado 80202. The lease covers approximately 29,000
square feet and expires in November 2001. The monthly rent is approximately
$41,000. The Company also owns a 6,000 square foot production facility in
Platteville, Colorado used to support the Company's Wattenberg Field operations.
Employees
On December 31, 1998, the Company employed 149 people, including 81 that work
in the Company's field office, none of whom are represented by a labor union.
The Company believes its relationship with its employees is satisfactory.
6
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Directors and Executive Officers
The following table sets forth certain information about the officers and
directors of the Company:
<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<S> <C> <C>
Thomas J. Edelman....... 48 Chairman of the Board and Chief Executive Officer
Jay W. Decker........... 48 President and Director
Brian J. Cree........... 35 Executive Vice President and Chief Operating Officer, Director
David J. Kornder........ 38 Vice President and Chief Financial Officer
James A. Lillo.......... 44 Vice President
David R. Macosko........ 37 Vice President
Terry L. Ruby........... 40 Vice President
David W. Siple.......... 39 Vice President
Christopher C. Behrens.. 38 Director
Robert J. Clark......... 54 Director
Thomas R. Denison....... 38 Director
Elizabeth K. Lanier..... 47 Director
Alexander P. Lynch...... 46 Director
- --------------------
</TABLE>
Thomas J. Edelman has served as Chairman of the Board and Chief Executive
Officer of the Company since its formation. He co-founded SOCO and was its
President from 1981 through February 1997. From 1980 to 1981, he was with The
First Boston Corporation and from 1975 through 1980, with Lehman Brothers Kuhn
Loeb Incorporated. Mr. Edelman received his Bachelor of Arts Degree from
Princeton University and his Masters Degree in Finance from Harvard University's
Graduate School of Business Administration. Mr. Edelman serves as Chairman of
Range Resources Corporation and is a Director of Petroleum Heat & Power Co.
Inc., Star Gas Corporation, and Paradise Music & Entertainment, Inc. Mr.
Edelman is also a Trustee of The Hotchkiss School.
Jay W. Decker has served as President since March 1998 and as a Director of
the Company since May 1996. Mr. Decker had been the Executive Vice President and
a Director of Hugoton Energy Corporation, a public independent oil company since
1995. From 1989 until its merger into Hugoton Energy, Mr. Decker was the
President and Chief Executive Officer of Consolidated Oil & Gas, Inc., a private
independent oil company based in Denver, Colorado and President of a predecessor
company. Prior to 1989, Mr. Decker served as Vice President - Operations for
General Atlantic Energy Company and in various capacities for Peppermill Oil
Company, Wainoco Oil & Gas and Shell Oil Company. Mr. Decker received his
Bachelor of Science Degree in Petroleum Engineering from the University of
Wyoming. Mr. Decker also serves as a Director of FX Energy.
Brian J. Cree has served as Executive Vice President, Chief Operating Officer
and Director of the Company since May 1996. Prior to the Gerrity Acquisition, he
served as Chief Operating Officer and Director of Gerrity since 1993. From 1992
to 1993, Mr. Cree served as Senior Vice President - Operations and Chief
Accounting Officer of Gerrity. Mr. Cree served as Vice President of Gerrity and
its predecessor since 1989 and served in various accounting capacities with that
company from 1987 to 1990. Prior to that, Mr. Cree was employed as an accountant
with the public accounting firm of Deloitte, Haskins & Sells. Mr. Cree received
his Bachelor of Arts Degree in Accounting from the University of Northern Iowa.
David J. Kornder has served as Vice President and Chief Financial Officer of
the Company since May 1996. Prior to the Gerrity Acquisition, he served as a
Vice President - Finance of Gerrity beginning in early 1993. From 1989 through
1992, Mr. Kornder was an Assistant Vice President for Gillett Group Management,
Inc. Prior to that, Mr. Kornder was an accountant with the independent
accounting firm of Deloitte & Touche for five years. Mr. Kornder received his
Bachelor of Arts Degree in Accounting from Montana State University.
7
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Jim A. Lillo has served as Vice President of the Company since May 1998. From
1995 to 1998, Mr. Lillo was President of James Engineering, Inc., an independent
petroleum engineering consulting firm. Prior to that, Mr. Lillo served as Vice
President of Engineering for Consolidated Oil & Gas, Inc., until its merger into
Hugoton Energy Corporation, and President of a predecessor operating company
since 1989. Prior to 1989, Mr. Lillo worked as an independent engineering
consultant and as Manager of Reservoir Engineering for Hart Exploration, and in
various engineering capacities with Champlin Petroleum Company and Shell Oil
Company. Mr. Lillo received his Bachelor of Science Degree in Chemical and
Petroleum Refining Engineering from the Colorado School of Mines and is a
Registered Professional Engineer.
David R. Macosko has served as a Vice President of the Company since May 1996.
Prior to the Gerrity Acquisition, he served as a Vice President of Gerrity from
1994. From 1989 to 1992, Mr. Macosko held various accounting positions with
Gerrity and served as Operations Coordinator from 1992 to 1994. From 1985 to
1989, Mr. Macosko was employed by PanCanadian Petroleum Company as the
supervisor of revenue and expenditure accounting. Mr. Macosko received his
Bachelor of Science Degree in Accounting from West Virginia University.
Terry L. Ruby has served as a Vice President of the Company since May 1996.
Prior to the Gerrity Acquisition, Mr. Ruby served as a senior landman of Gerrity
beginning in 1992 and was appointed Vice President - Land in 1995. Prior to his
employment with Gerrity, Mr. Ruby worked for Apache Corporation from 1990 to
1992, and for Baker Exploration Company from 1982 to 1989. Mr. Ruby received his
Bachelor of Science Degree in Minerals Land Management from the University of
Colorado and his M.B.A. from the University of Denver.
David W. Siple has served as a Vice President of the Company since May 1996.
He joined SOCO's land department in 1994 and was appointed Land Manager of SOCO
in 1995. From 1990 through May 1994, Mr. Siple was the Land Manager of Gerrity.
From 1981 through 1989, Mr. Siple was employed by PanCanadian Petroleum Company
in the Land Department. Mr. Siple received his Bachelor of Science Degree in
Minerals Land Management from the University of Colorado.
Christopher C. Behrens has served as a Director of the Company since February
1999. Mr. Behrens was made a principal at Chase Capital Partners during 1998.
Chase Capital Partners is a General Partner of Chase Venture Capital Associates,
L.P. Before assuming such position, Mr. Behrens was a Vice President in the
Chase Manhattan Corporation's Merchant Banking Group. He received his Bachelor
of Arts from the University of California at Berkeley and his M.B.A. from
Columbia University. Mr. Behrens also serves as a Director of Portola Packaging
and The Pantry, Inc., as well as other private companies.
Robert J. Clark has served as a Director of the Company since May 1996. Mr.
Clark is the President of Bear Paw Energy Inc., a wholly owned subsidiary of
TransMontaigne, Inc. Mr. Clark formed a predecessor company Bear Paw Energy Inc.
in 1995 and joined TransMontaigne in 1996 when TransMontaigne acquired a
majority interest in the predecessor company. From 1988 to 1995 he was President
of SOCO Gas Systems, Inc. and Vice President - Gas Management for SOCO. Mr.
Clark was Vice President Gas Gathering, Processing and Marketing of Ladd
Petroleum Corporation, an affiliate of General Electric from 1985 to 1988. Prior
to 1985, Mr. Clark held various management positions with NICOR, Inc. and its
affiliate NICOR Exploration, Northern Illinois Gas and Reliance Pipeline
Company. Mr. Clark received his Bachelor of Science Degree from Bradley
University and his M.B.A. from Northern Illinois University.
Thomas R. Denison has served as a Director of the Company since January 1998.
Mr. Denison is a Managing Director and the General Counsel of First Reserve
Corporation. He joined the firm in January 1998 and opened its Denver office.
Prior to joining First Reserve, he was a partner in the international law firm
of Gibson, Dunn & Crutcher LLP, a firm which he joined in 1986 as an associate.
Mr. Denison received his Bachelor of Science degree in Business Administration
from the University of Denver and his Juris Doctor from the University of
Virginia. Mr. Denison also serves as a Director of TransMontaigne, Inc.
8
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Elizabeth K. Lanier has served as a Director of the Company since January
1998. Mrs. Lanier has served as Vice President and General Counsel of General
Electric Power Systems since August 1998. From 1996 to 1998, Mrs. Lanier served
as Vice President and Chief of Staff of Cinergy Corp. Mrs. Lanier received her
Bachelor of Arts Degree with honors from Smith College in 1973 and her law
degree from Columbia Law School in 1977 where she was a Harlan Fiske Stone
Scholar. Mrs. Lanier was awarded an Honorary Doctorate of Technical Letters by
Cincinnati Technical College in 1991 and an Honorary Doctorate of Letters in
1995 from the College of Mt. St. Joseph. From 1982 to 1996 she was a Partner in
the Corporate and Litigation Departments of Frost & Jacobs, a law firm in
Cincinnati, Ohio. From 1977 to 1982 she was with the law firm of Davis Polk &
Wardwell in New York City. She is immediate past Chair of the Ohio Board of
Regents.
Alexander P. Lynch has served as a Director of the Company since May 1996. Mr.
Lynch is currently a General Partner of The Beacon Group, a private investment
and financial advisory firm. From 1995 to 1996, Mr. Lynch had been Co-President
and Co-Chief Executive Officer of The Bridgeford Group, a financial advisory
firm. From 1991 to 1994, he served as Senior Managing Director of Bridgeford.
From 1985 until 1991, Mr. Lynch was a Managing Director of Lehman Brothers, a
division of Shearson Lehman Brothers Inc. Mr. Lynch received his Bachelor of
Arts Degree from the University of Pennsylvania and his M.B.A. from the Wharton
School of Business at the University of Pennsylvania. Mr. Lynch also serves as a
Director of Canadian National Railway Company.
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ITEM 2. PROPERTIES
General
The Company's reserves are concentrated in the Wattenberg Field within the D-
J Basin of north central Colorado. Discovered in 1970, the Field is located
approximately 35 miles northeast of Denver and stretches over portions of Adams,
Boulder and Weld counties in Colorado. One of the most attractive features of
Wattenberg is the presence of several productive formations. In a section only
4,500 feet thick, there are up to eight potentially productive formations.
Three of the formations, the Codell, Niobrara and J-Sand, are considered
"blanket" zones in the area of the Company's holdings, while others, such as the
D-Sand, Dakota and the shallower Shannon, Sussex and Parkman, are more
localized. Although referred to as a "formation" or "sand," many such
formations actually are comprised of more than one rock strata. For example,
the Niobrara has three separate and distinct bodies or "benches" with potential
hydrocarbon development. The presence of several prospective zones tends to
reduce the risk of a dry hole. The following chart lists the formations present
in Wattenberg:
Producing Formations
Approximate
Formation Depth
--------- -----
(feet)
Parkman................................... 3,600
Sussex.................................... 4,500
Shannon................................... 4,800
Niobrara.................................. 7,000
Codell.................................... 7,300
D-Sand.................................... 7,500
J-Sand.................................... 7,800
Dakota.................................... 8,000
Drilling in Wattenberg is considered low risk from the perspective of finding
oil and gas reserves, with better than 95% of the wells drilled being completed
as producers. Prior to 1998, the Codell/Niobrara formations were the primary
drilling objective of the Company. These formations produce both oil and
natural gas, with oil comprising approximately 30% of the total per well
reserves. Although the cost of drilling and completing a Codell/Niobrara well
is approximately $225,000, the decline in oil and gas prices since the fall of
1997 has significantly reduced the economic attractiveness of such drilling. In
May 1998, the Colorado Oil & Gas Commission adopted new spacing rules for the
Wattenberg Field that greatly enhanced the Company's ability to more efficiently
develop its properties. The rule also eliminated costly and time-consuming
procedures required for certain development activities. All formations in the
Field can now be drilled, produced and commingled from any or all of ten
"drilling windows" on a 320 acre parcel. Primarily as a result of the new rule,
the Company increased its capital development activities during the year. The
increase in development activity allowed the Company to realize production
growth during the second half of 1998 and increase its total proved reserves
over the prior year despite a significant reduction in oil and natural gas
prices.
During 1998, the Company drilled or deepened 26 wells to the J-Sand or Dakota
formation and eight wells to the Codell/Niobrara formation. The cost of
drilling and completing a J-Sand well approximates $300,000 while a completed
deepening within an existing wellbore costs roughly $225,000. The reserves
associated with a typical J-Sand well are substantially more prolific than those
of a Codell/Niobrara, with over 95% of such per well reserves comprised of
natural gas. Thus, the economics associated with a J-Sand project are more
dependant on natural gas prices. The finding and development costs for the J-
Sand and Dakota drilling and deepening projects for 1998 averaged $0.50 per
Mcfe. At December 31, 1998 the Company had 108 proven J-Sand drilling locations
or deepening projects in inventory.
10
<PAGE>
The Company also performed 54 refracs during 1998, expanding on the program
initiated in 1997. A refrac consists of the restimulation of a producing
formation within an existing wellbore to enhance production and add new
reserves. During 1998, the refrac program was focused primarily on the Codell
formation, although the Company successfully completed two J-Sand refracs. A
typical refrac costs approximately $90,000. The finding and development costs
associated with the Company's 1998 refrac program averaged $0.83 per Mcfe. At
December 31, 1998 the Company had 176 proven refrac projects. Given the
positive results of the refrac program to date, management has identified over
250 additional refrac opportunities that are not included in proved reserves at
year-end.
In addition to the development activity described above, the Company
recompleted 21 wells and installed tubing in another 149 wellbores. These
projects, combined with well workovers and reactivations, were an integral part
of the Company's 1998 development program and elimination of the long-term
decline in the Company's production. The Company estimates it has over 350 of
these minor projects at year-end 1998.
At December 31, 1998, the Company had working interests in 3,392 gross (3,034
net) producing oil and natural gas wells in the D-J Basin and held royalty
interests in an additional 216 producing wells. As of December 31, 1998,
estimated proved reserves totaled 372.0 Bcfe, including 14.2 million barrels of
oil and 286.6 Bcf of gas.
Proved Reserves
The following table sets forth estimated year-end net proved reserves for the
three years ended December 31, 1998.
<TABLE>
<CAPTION>
December 31,
-------------------------
1996 1997 1998
------- ------- -------
<S> <C> <C> <C>
Oil (MBbl)
Developed...... 15,799 14,594 13,655
Undeveloped.... 6,676 2,382 585
------- ------- -------
Total...... 22,475 16,976 14,240
======= ======= =======
Natural gas (MMcf)
Developed...... 242,777 232,058 244,736
Undeveloped.... 53,882 23,577 41,859
------- ------- -------
Total 296,659 255,635 286,595
======= ======= =======
Total MMcfe......... 431,509 357,491 372,035
======= ======= =======
</TABLE>
The following table sets forth for the year ended December 31, 1998, pretax
future net revenues from the production of proved reserves and the pretax
present value discounted at 10% of such revenues, net of estimated future
capital costs, including estimated costs of $24.9 million in 1999.
<TABLE>
<CAPTION>
December 31, 1998
---------------------------------
Developed Undeveloped Total
--------- ------------ --------
(In thousands)
<S> <C> <C> <C>
Future Net Revenues
- --------------------------
1999..................... $ 40,074 $(8,526) $ 31,548
2000..................... 35,181 (4,887) 30,294
2001..................... 34,929 5,331 40,260
Remainder................ 252,134 49,540 301,674
-------- ------- --------
Total................... $362,318 $41,458 $403,776
======== ======= ========
Pretax PW 10% Value /a/.. $213,116 $12,015 $225,131
======== ======= ========
- ------------------
</TABLE>
/a/ The after tax present value discounted at 10% of the proved reserves totaled
$205.4 million at year-end 1998.
11
<PAGE>
The quantities and values in the preceding tables are based on prices in
effect at December 31, 1998, which averaged $10.60 per barrel of oil and $1.87
per Mcf of gas. Price declines decrease reserve values by lowering the future
net revenues attributable to the reserves and reducing the quantities of
reserves that are recoverable on an economic basis. Price increases have the
opposite effect. 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.
Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of such reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required to establish production.
Future prices received from production and future production costs may vary,
perhaps significantly, from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that prices and costs will remain constant.
There can be no assurance that actual production will equal the estimated
amounts used in the preparation of reserve projections.
The present values shown should not be construed as the current market value
of the reserves. The quantities and values shown in the preceding tables are
based on average oil and natural gas prices in effect on December 31, 1998.
Subsequent to year-end, natural gas prices have fallen. The value of the
Company's assets is in part dependent on the prices the Company receives for oil
and natural gas, and a significant decline in the price of oil or gas could have
a material adverse effect on the Company's financial condition and results of
operations. The 10% discount factor used to calculate present value, which is
specified by the Securities and Exchange Commission (the "SEC"), is not
necessarily the most appropriate discount rate, and present value, no matter
what discount rate is used, is materially affected by assumptions as to timing
of future production, which may prove to be inaccurate. For properties operated
by the Company, expenses exclude Patina's share of overhead charges. In
addition, the calculation of estimated future net revenues does not take into
account the effect of various cash outlays, including, among other things
general and administrative costs and interest expense.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures. The data in the above tables represent estimates only. Oil and
natural gas reserve engineering must be recognized as a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact way, and estimates of other engineers might differ
materially from those shown above. The accuracy of any reserve estimate is a
function of the quality of available data and engineering and geological
interpretation and judgment. Results of drilling, testing and production after
the date of the estimate may justify revisions. Accordingly, reserve estimates
are often materially different from the quantities of oil and natural gas that
are ultimately recovered.
The proved oil and natural gas reserves and future revenues as of December
31, 1998 were audited by Netherland, Sewell & Associates, Inc. ("NSAI"). Since
January 1, 1999, the Company has filed Department of Energy Form EIA-23, "Annual
Survey of Oil and Gas Reserves," as required by operators of domestic oil and
gas properties. There are differences between the reserves as reported on Form
EIA-23 and reserves as reported herein. Form EIA-23 requires that operators
report on total proved developed reserves for operated wells only and that the
reserves be reported on a gross operated basis rather than on a net interest
basis.
12
<PAGE>
Producing Wells
The following table sets forth certain information at December 31, 1998
relating to the producing wells in which the Company owned a working interest.
The Company also held royalty interests in 216 producing wells at such date. The
Company had 157 wells (150 net) shut in at December 31, 1998. The Company's
average working interest in all wells was 90%. Wells are classified as oil or
natural gas wells according to their predominant production stream.
<TABLE>
<CAPTION>
Principal Gross Net
Production Stream Wells Wells
----------------- ----- -----
<S> <C> <C>
Oil................................... 2,739 2,494
Natural gas........................... 653 540
----- -----
Total.......................... 3,392 3,034
===== =====
</TABLE>
Drilling Results
The following table sets forth information with respect to wells drilled or
deepened by the Company during the past three years. All the wells were
development wells. The information should not be considered indicative of
future performance, nor should it be assumed that there is necessarily any
correlation between the number of productive wells drilled, quantities of
reserves found or economic value. Productive wells are those that produce
commercial quantities of hydrocarbons whether or not they produce a reasonable
rate of return.
<TABLE>
<CAPTION>
1996 1997 1998
---- ---- ----
<S> <C> <C> <C>
Productive
Gross..... 12.0 28.0 36.0
Net....... 12.0 28.0 36.0
Dry
Gross..... 0.0 1.0 0.0
Net....... 0.0 1.0 0.0
</TABLE>
At December 31, 1998 no development wells were in progress.
Acreage
The following table sets forth certain information at December 31, 1998
relating to acreage held by the Company. Undeveloped acreage is acreage held
under lease, permit, contract or option that is not in a spacing unit for a
producing well, including leasehold interests identified for development or
exploratory drilling. Developed acreage is acreage assigned to producing wells.
<TABLE>
<CAPTION>
Developed Undeveloped
---------------- --------------
Gross Net Gross Net
------- ------- ------ ------
<S> <C> <C> <C> <C>
Colorado.. 177,000 138,000 7,000 6,000
Wyoming... - - 35,000 24,000
------- ------- ------ ------
Total... 177,000 138,000 42,000 30,000
======= ======= ====== ======
</TABLE>
During 1998, the Company acquired 35,000 gross (24,000 net) acres in
southwestern Wyoming. The Company also acquired the option to earn through
drilling an additional 58,000 gross (58,000 net) acres of coalbed methane gas
leases in this same area. As such, the Company controls approximately 93,000
gross (82,000 net) acres with respect to this grassroots prospect.
13
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
In March 1996, a complaint was filed in the Court of Chancery for the State
of Delaware against Gerrity and each of its directors, Brickell Partners v.
Gerrity Oil & Gas Corporation, C.A. No. 14888 (Del. Ch.). The complaint alleges
that the "action is brought (a) to restrain defendants from consummating the
Gerrity Acquisition which will benefit the holders of Gerrity's common stock at
the expense of the holders of Gerrity's preferred stock and (b) to obtain a
declaration that the terms of the proposed Gerrity Acquisition constitute a
breach of the contractual rights of the preferred." The complaint sought, among
other things, certification as a class action on behalf of all holders of
Gerrity's preferred stock, a declaration that the defendants have committed an
abuse of trust and have breached their fiduciary and contractual duties, an
injunction enjoining the Gerrity Acquisition and money damages. In April 1996,
the defendants were granted an indefinite extension of time in which to answer
the complaint and no answer had been filed by February 1997. In February 1997,
the attorney for the plaintiff filed a Status Report with the court stating
"Case has been mooted. Plaintiff is preparing an application for counsel fees."
No fee application was filed. In November 1997, the plaintiff filed an amended
complaint. The amended complaint realleges the substance of the original
complaint and includes an allegation that the defendants coerced the holders of
the Gerrity preferred stock into exchanging their stock for the 7.125% Preferred
Stock of the Company. The amended complaint also alleges the defendants
participated in a scheme to eliminate the outstanding Gerrity preferred by
forcing the exchange of those shares for shares of the Company's preferred in
October 1996. The amended complaint seeks rescission of the transactions
described in the complaint or money damages if rescission is impractical. On
January 5, 1998, defendants filed a motion to dismiss the amended complaint. A
brief in support of the motion to dismiss was filed in August 1998 and there has
been no response from the plaintiffs. Defendants believe that the amended
complaint is without merit and intend to vigorously defend against this action.
At this time, the Company is unable to estimate the range of potential loss, if
any, from this uncertainty. However, the Company believes the resolution of
this uncertainty should not have a material adverse effect upon the Company's
financial position, although an unfavorable outcome in any reporting period
could have a material adverse effect on results for that period.
The Company is a party to various other lawsuits incidental to its business,
none of which are anticipated to have a material adverse impact on its financial
position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
14
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER
MATTERS
The Company's Common Stock, $12.50 Warrants and 7.125% Preferred Stock are
listed on the New York Stock Exchange ("NYSE") under the symbols "POG", "POGWT"
and "POGPr", respectively. Such listings became effective in May 1996. The
Company's 8.50% Preferred Stock was privately placed and does not trade
publicly. The following table sets forth the range of high and low closing
prices as reported on the NYSE Composite Tape.
<TABLE>
<CAPTION>
Common Stock Warrants Preferred Stock
------------- ------------ ---------------
High Low High Low High Low
------ ----- ----- ----- ------- ------
<S> <C> <C> <C> <C> <C> <C>
1997
----
First Quarter... $10.50 $8.63 $2.88 $1.50 $31.75 $29.50
Second Quarter.. 9.50 8.00 1.88 1.25 29.75 28.00
Third Quarter... 9.94 8.00 2.25 1.13 32.38 27.75
Fourth Quarter.. 10.31 6.88 2.56 1.25 33.00 27.50
1998
----
First Quarter... $ 7.75 $6.69 $1.63 $1.13 $29.50 $27.00
Second Quarter.. 7.81 6.50 1.56 1.13 29.56 25.94
Third Quarter... 7.13 3.56 1.25 0.38 26.75 20.06
Fourth Quarter.. 4.56 2.38 0.63 0.22 21.50 17.19
</TABLE>
On March 4, 1999, the closing prices of the Common Stock, Warrants and 7.125%
Preferred Stock were $3.06, $0.34 and $16.81, respectively. As of December 31,
1998, there were approximately 187 holders of record of the common stock and
15.8 million shares outstanding.
Dividend Policy. Prior to the fourth quarter of 1997, the Company had not
declared dividends on its common stock. The Company declared and paid an initial
quarterly dividend on its common stock in December 1997 at a rate of one cent
per share. During 1998, the Company declared and paid dividends on its common
stock at the rate of one cent per share each quarter. The Company currently
plans to continue to pay dividends on its common stock. However, continuation
of dividends and the amounts thereof will depend upon the Company's earnings,
financial condition, capital requirements and other factors. Under the terms of
its bank Credit Agreement, the Company had $8.4 million available for dividends
on its common stock as of December 31, 1998.
15
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected historical financial data of the
Company as of or for each of the years in the five year period ended December
31, 1998. Future results may differ substantially from historical results
because of changes in oil and natural gas prices, production increases or
declines and other factors. This information should be read in conjunction with
the financial statements and notes thereto and Management's Discussion and
Analysis of Financial Condition and Results of Operations, presented elsewhere
herein. The financial statements reflect the Gerrity Acquisition in May 1996.
<TABLE>
<CAPTION>
As of or for the Year Ended December 31,
-----------------------------------------------------
1994 1995 1996 1997 1998
--------- --------- --------- --------- ---------
(In thousands except per share data)
<S> <C> <C> <C> <C> <C>
Statement of Operations Data
Revenues.................................... $ 67,822 $ 50,102 $ 83,188 $100,333 $ 74,710
Expenses
Direct operating.......................... 8,110 8,867 14,519 18,790 17,340
Exploration............................... 784 416 224 131 59
General and administrative................ 7,484 5,974 6,151 7,154 7,139
Interest and other........................ 3,869 5,476 14,304 16,038 13,001
Depletion, depreciation and amortization.. 43,036 32,591 44,822 49,076 41,695
Impairment of oil and gas properties...... - - - 26,047 -
-------- -------- -------- -------- --------
Total expenses............................ 63,283 53,324 80,020 117,236 79,234
-------- -------- -------- -------- --------
Income (loss) before taxes.................. 4,539 (3,222) 3,168 (16,903) (4,524)
Provision (benefit ) for income taxes...... 1,589 (1,128) (394) - -
-------- -------- -------- -------- --------
Net income (loss)........................... $ 2,950 $ (2,094) $ 3,562 $(16,903) $ (4,524)
======== ======== ======== ======== ========
Net income (loss) per
common share........................... $0.21 $(0.15) $0.08 $(1.11) $(0.68)
======== ======== ======== ======== ========
Weighted average shares outstanding......... 14,000 14,000 17,796 18,324 16,025
Cash dividends per common share............. $0.00 $0.00 $0.00 $0.01 $0.04
Balance Sheet Data
Current assets............................ $ 11,083 $ 9,611 $ 27,587 $ 31,068 $ 23,325
Oil and gas properties, net............... 234,821 214,594 398,640 342,833 324,777
Total assets.............................. 246,686 224,521 430,233 376,875 351,533
Current liabilities....................... 23,838 9,611 26,572 30,297 23,579
Debt...................................... 79,333 75,000 197,594 146,435 142,021
Stockholders' equity...................... 115,846 113,663 196,236 188,441 175,976
Cash Flow Data
Net cash provided by operations........... $ 47,690 $ 18,407 $ 52,996 $ 68,645 $ 34,331
Net cash used by investing................ (96,378) (21,060) (9,796) (18,801) (23,145)
Net cash realized (used) by financing..... 48,688 2,653 (38,047) (43,388) (13,709)
</TABLE>
16
<PAGE>
The following table sets forth unaudited summary financial results on a
quarterly basis for the two most recent years.
<TABLE>
<CAPTION>
1997
---------------------------------------
First Second Third Fourth
-------- -------- -------- ---------
<S> <C> <C> <C> <C>
(In thousands, except per share data)
Revenues.................................. $29,486 $22,854 $21,703 $ 26,290
Direct operating expenses................. 4,975 4,347 4,185 5,283
Depletion, depreciation and amortization.. 12,428 12,348 11,487 12,813
Impairment of oil and gas properties...... - - - 26,047
Net income (loss)......................... 6,256 828 799 (24,786)
Net income (loss) per common share........ 0.29 0.01 0.01 (1.55)
1998
--------------------------------------
First Second Third Fourth
----- ------ ----- ------
(In thousands, except per share data)
Revenues.................................. $20,637 $18,327 $18,490 $ 17,256
Direct operating expenses................. 4,637 4,258 4,198 4,247
Depletion, depreciation and amortization.. 10,538 10,222 10,665 10,270
Net income (loss)......................... 304 (1,501) (1,464) (1,863)
Net income (loss) per common share........ (0.08) (0.19) (0.19) (0.22)
</TABLE>
17
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Results of Operations
In May 1996, the Company acquired Gerrity Oil & Gas Corporation ("Gerrity" or
"Gerrity Acquisition"). The acquisition was accounted for as a purchase.
Accordingly, the results of operations since the Gerrity Acquisition reflect the
impact of the purchase.
Comparison of 1998 results to 1997. Revenues for 1998 totaled $74.7 million,
a 26% decrease from the prior year. The decrease was due primarily to the sharp
decline in oil and gas prices and, to a lesser extent, lower production. The net
loss in 1998 was $4.5 million compared to net loss of $16.9 million in 1997.
The net loss in 1997 was primarily attributed to a $26.0 million impairment of
oil and gas properties recorded in the fourth quarter of 1997. Exclusive of the
non-cash impairment, the Company would have recognized $9.1 million of net
income in 1997. No impairment of oil and gas properties was recorded in 1998.
Average daily oil and gas production for 1998 totaled 4,654 barrels and 69.9
MMcf (97.8 MMcfe), decreases of 10% and 5%, respectively, from 1997. During
1998, 36 wells and 75 recompletions and refracs were placed on production,
compared to 28 wells and 102 recompletions and refracs in 1997. The Company's
increase in development activity, the benefits of certain minor acquisitions and
the continued success of the production enhancement program appear to have
resulted in the elimination of the Company's long-term production decline.
Based upon budgeted development activity during 1999 of $25.0 million, the
Company expects production to continue to increase in the foreseeable future.
The level of future development activity and consequent changes in production
are partially dependent on future oil and gas prices.
Average oil prices decreased from $19.70 per barrel in 1997 to $13.29 in
1998. Average natural gas prices decreased from $2.32 per Mcf in 1997 to $1.94
in 1998. The average oil price includes hedging gains in 1997 and 1998 of
$297,000 or $0.16 per barrel and $285,000 or $0.17 per barrel. The decrease in
natural gas prices was primarily the result of the decrease in the average CIG
and PEPL indexes for 1998 compared to 1997 and lower natural gas liquids prices
in 1998. The average natural gas price for 1997 and 1998 includes hedging gains
of $2.0 million or $0.07 per Mcf and $1.7 million or $0.06. Direct operating
expenses totaled $17.3 million or $0.49 per Mcfe in 1998 compared to $18.8
million or $0.49 per Mcfe in the prior year. The decrease in operating expenses
was primarily attributed to the decrease in production taxes as a result of
lower average product prices somewhat offset by increases in well workovers and
more effective production methods.
General and administrative expenses, net of third party reimbursements, for
1998 and 1997 totaled $7.1 million and $7.2 million, respectively. Included in
general and administrative expense is $1.5 million and $2.0 million in 1998 and
1997 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 October 1997. In the fourth quarter of 1998,
the Company instituted a cost reduction program in response to the sharp decline
in oil and gas prices. This plan resulted in the elimination of nine positions,
or 15% of the Company's office staff, and the institution of additional cost
cutting measures. The Company incurred approximately $500,000 of charges
related to this restructuring.
Interest and other expenses totaled $13.0 million in 1998, a decrease of $3.0
million or 19% from the prior year. Interest expense decreased as a result of
lower average debt levels and the repurchase of over $22.0 million of face
amount of 11.75% Subordinated Notes, through borrowings on the Company's bank
facility. The Company's average interest rate for 1998 was 10.0% compared to
9.6% in 1997.
Depletion, depreciation and amortization expense for 1998 totaled $41.7
million, a decrease of $7.4 million or 15% from 1997. Depletion expense totaled
$40.9 million or $1.14 per Mcfe, for 1998 compared to $46.2 million or $1.21 per
Mcfe for 1997. The decrease in depletion expense resulted primarily from lower
oil and natural gas production and a reduction of the depletion rate to $1.08
per Mcfe in the fourth quarter of 1998 due to the increase in proved reserves at
December 31, 1998. Depreciation and amortization expense for 1998 totaled
$807,000, or $0.02 per Mcfe compared to $2.9 million or $0.08 per Mcfe for 1997.
Amortization expense for 1997 included $2.5 million related to the expensing of
a noncompete agreement.
18
<PAGE>
Comparison of 1997 results to 1996. Total revenues for 1997 increased to
$100.3 million from $83.2 million, representing an increase of 21% from the
prior year. The revenue increase was due to the higher production associated
with the Gerrity Acquisition and improved product prices. Exclusive of the
Gerrity Acquisition, revenues would have decreased. The net loss for 1997 was
$16.9 million compared to net income of $3.6 million in 1996. The net loss was
primarily attributed to the $26.0 million impairment of oil and gas properties.
Exclusive of the non-cash impairment, the Company would have recognized $9.1
million of net income in 1997.
Average daily oil and gas production for 1997 was 5,174 barrels and 73.6 MMcf
(104.6 MMcfe), increases of 12% and 12%, respectively. The production increases
resulted solely from the Gerrity Acquisition. Exclusive of the Gerrity
Acquisition, average daily production would have declined due to the Company's
limited development schedule and expected initial declines on the large number
of wells drilled and completed in 1994 and early 1995. However, successful
production enhancement and development programs have substantially reduced the
expected decline in production. There were 28 wells and 102 recompletions and
refracs placed on production in 1997 compared to 12 wells and 90 recompletions
in 1996. In the future, a decrease in production is expected unless development
activity is substantially increased or acquisitions are consummated.
Average oil prices decreased from $20.47 per barrel in 1996 to $19.70 in
1997. Average natural gas prices increased from $1.99 per Mcf in 1996 to $2.32
in 1997. The average oil price includes hedging gains in 1997 of $297,000 or
$0.16 per barrel. The increase in average natural gas prices was primarily the
result of the 35% increase in the average CIG index in 1997 from 1996 and the
Company's ability to realize Mid-Continent pricing for a significant portion of
its natural gas production during the winter months. The average natural gas
price for 1997 includes hedging gains of $2.0 million or $.07 per Mcf. Direct
operating expenses totaled $18.8 million or $0.49 per Mcfe in 1997 compared to
$14.5 million or $0.43 per Mcfe in the prior year. The increase in operating
expenses was primarily attributed to focusing more attention on enhancing
production through increased well workovers and more effective production
methods and the increase in production taxes as a result of higher average
product prices.
General and administrative expenses, net of third party reimbursements, for
1997 totaled $7.2 million, a 16% increase from 1996. The increase was
attributed to the expensing of $2.0 million related to a common stock grant
awarded to the officers and key managers of the Company in October 1997.
Exclusive of the non-cash stock grant expense, general and administrative
expenses declined by $1.0 million or 16%, due to continued efficiencies realized
as a result of the Gerrity Acquisition. Prior to the Gerrity Acquisition, the
Company did not have its own employees. Employees, office space, furniture,
fixtures and equipment were provided by SOCO. SOCO allocated estimated general
and administrative expenses to the Company.
Interest and other expenses were $16.0 million in 1997 compared to $14.3
million in 1996. Interest expense increased as a result of the higher average
outstanding debt levels and interest rates as a result of the Gerrity
Acquisition. The Company's average interest rate for 1997 was 9.6% compared to
9.3% in the prior year. This increase was due primarily to the 11.75% Senior
Subordinated Notes due July 15, 2004 (the "Notes") assumed by the Company in the
Gerrity Acquisition in May 1996. These Notes were outstanding for all of 1997
compared to only eight months of 1996.
Depletion, depreciation and amortization expense for 1997 totaled $49.1
million, an increase of $4.3 million or 9% from 1996. Depletion expense totaled
$46.2 million for 1997 compared to $41.3 million for 1996. The depletion rate
for 1996 and 1997 averaged $1.21 per Mcfe. The increase in expense resulted
from higher oil and natural gas production as a result of the Gerrity
Acquisition. Depreciation and amortization expense for 1997 totaled $2.9
million, or $.08 per Mcfe compared to $3.5 million or $0.10 per Mcfe in 1996.
Amortization expense consisted primarily of the expensing of a noncompete
agreement entered into as part of the Gerrity Acquisition of $2.6 million in
1996 and $2.5 million in 1997. In the fourth quarter of 1997, management
determined that the noncompete agreement had no remaining value and expensed the
remaining book value.
Impairment of oil and gas properties expense for 1997 totaled $26.0 million.
The impairment was the result of applying Statement of Financial Accounting
Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long Lived
Assets." In applying this statement, the Company determined that the estimated
future cash flows (undiscounted and without interest charges) expected to result
from use of these assets and their disposition, largely proven undeveloped
drilling locations, was less than the net book value of these assets and,
accordingly, recorded an impairment. The impairment primarily resulted from
lower oil and natural gas prices at year-end.
19
<PAGE>
Development, Acquisition and Exploration
During the 1998, the Company incurred $24.1 million in capital expenditures,
with development expenditures comprising $21.7 million. During the period, the
Company successfully drilled or deepened 36 wells, recompleted 21 wells and
refraced 54 wells. The Company also acquired $1.7 million of proved reserves in
Wattenberg and secured approximately 90,000 gross acres in conjunction with a
grassroots prospect in Wyoming. The Company anticipates incurring approximately
$25.0 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 December 31, 1998, the Company had $351.5 million of assets. Total
capitalization was $318.0 million, of which 55% was represented by stockholders'
equity, 21% by senior debt and 24% by subordinated debt. During 1998, net cash
provided by operations totaled $34.3 million, as compared to $68.6 million in
1997. At December 31, 1998, there were no significant commitments for capital
expenditures. The Company anticipates 1999 capital expenditures, exclusive of
acquisitions, to approximate $25.0 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.
The Company entered into an amended Credit Agreement in April 1997. The
Credit Agreement consists of a revolving credit facility in an aggregate amount
up to $140.0 million. The amount available under the revolving credit facility
is adjusted semiannually, each May 1 and November 1, and equaled $100.0 million
at December 31, 1998, with $68.0 million of debt outstanding at that time.
The Credit Agreement contains certain financial covenants, including but not
limited to, a maximum total debt to capitalization ratio, a maximum total debt
to EBITDA ratio, a minimum current ratio and various other negative covenants
that could limit the Company's ability to incur other debt, consummate
acquisitions, dispose of assets, pay dividends or repurchase securities.
Borrowings under the Credit Agreement mature in 2000, 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 $8.4 million as of
December 31, 1998, 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 nine months (as selected by the Company) are
offered in the interbank Eurodollar market plus a margin which fluctuates from
0.625% to 1.125%, determined by a debt to EBITDA ratio. During 1998, the
average interest rate under the facility approximated 6.6%.
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 three-month LIBOR
rate on the date the contract was entered into was 5.34%. Accordingly, the
Company received $59,000 in January 1999.
The Company had $74.0 million of 11.75% Senior Subordinated Notes due July
15, 2004 outstanding on December 31, 1998. The Notes have been reflected in the
accompanying financial statements at a book value of 105.875% of their principal
amount ($69.9 million of principal amount outstanding as of December 31, 1998).
The Company has repurchased $30.1 million principal amount of the 11.75%
Subordinated Notes through borrowings on the Company's bank facility. The Notes
are redeemable at the option of the Company, in whole or in part, at any time on
or after July 15, 1999 at 105.875% of their principal amount. The Notes are
unsecured general obligations and are subordinated to all senior indebtedness
and to any existing and future indebtedness of the Company's subsidiaries.
20
<PAGE>
In October 1997, a series of transactions took place that eliminated SOCO's
ownership in the Company. The transactions included: (i) the sale by SOCO of
10.9 million common shares of its Patina stock in a public offering, (ii) the
repurchase by the Company of SOCO's remaining 3.0 million common shares, (iii)
the sale by the Company of $40.0 million of 8.50% convertible preferred stock
and the issuance of 160,000 common shares to certain institutional investors and
(iv) the sale of 303,797 common shares at $9.875 per share and the grant of
496,250 restricted common shares by the Company to certain officers and
managers. As a result of these transactions, SOCO no longer has any ownership
in the Company.
In conjunction with the appointment of a new President of the Company in
March 1998, the President purchased 100,000 shares of Common Stock at $6.875 per
share. The Company loaned the President $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 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 natural gas revenues of $1.5 million,
$1.8 million and $2.1 million during 1996, 1997 and 1998, 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 the Credit Agreement,
projected operating cash flows and the Company's 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, the Company will require
additional debt or equity financing, which 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 this 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 is being corrected or
reprogrammed for Year 2000 compliance. It is anticipated that all new systems,
upgrades and reprogramming efforts will be completed by June 30, 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 has 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 are planned for any critically
dependent third parties not responding. A further assessment of the potential
impact of the Year 2000 issue on the Company's business and operations will be
made as this information is received and evaluated. The Company is not
currently aware of any third party issues that would cause a significant
disruption of its business or operations. If the follow-up assessment of any
significant third party responses indicates 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.
The Company's goal is to have all internal systems Year 2000 compliant, and
third party assessments completed no later than June 30, 1999. This should
allow sufficient time prior to January 1, 2000 to validate the system
modifications and complete any additional contingency planning for third parties
that may not be Year 2000 compliant. However, given the complexity of the Year
2000 issue, there can be no assurance that the Company will be able to address
these problems without costs and 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.
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 natural gas, loss of electric power, and the inability to
engage in normal automated or computerized business activities.
To date, the Company has not finalized its contingency plans for possible
Year 2000 issues. After the completion of the assessment and review of the
results of monitoring the compliance efforts and status of third parties, the
Company will finalize such contingency plans based on its assessment of outside
risks. The Company anticipates that final contingency plans, as necessary, will
be in place by September 30, 1999. 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
$100,000.
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 crude oil and spot prices applicable to the Rocky
Mountains and Mid-Continent region 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. Oil prices ranged from a monthly low of $9.56 per barrel
to a monthly high of $17.44 per barrel during 1998. 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 derivatives 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. The Company entered into
various swap contracts for oil (NYMEX based) during 1997 and 1998. The Company
recognized a loss of $(27,000) in 1997 and a gain of $238,000 in 1998 related to
these swap contracts based on settlements during the respective periods. The
Company entered into various CIG and PEPL index based swap contracts for natural
gas during 1997 and 1998. The Company recognized gains of $1.8 million in 1997
and $1.5 million in 1998 related to these swap contracts based on settlements
during the respective periods
23
<PAGE>
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
1997 and 1998. 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.
<TABLE>
<CAPTION>
Average Prices
---------------------------------
Natural Equivalent
Oil Gas Mcf
--------- --------- -----------
(Per Bbl) (Per Mcf) (Per Mcfe)
<S> <C> <C> <C>
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
-----------
1997
----
First...... $21.79 $2.63 $2.93
Second..... 19.09 1.85 2.26
Third...... 18.53 1.92 2.26
Fourth..... 18.80 2.61 2.76
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
</TABLE>
24
<PAGE>
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
<TABLE>
<CAPTION>
PATINA OIL & GAS CORPORATION
<S> <C>
Report of Independent Public Accountants...................... F-2
Consolidated Balance Sheets as of December 31, 1997 and 1998.. F-3
Consolidated Statements of Operations for the years ended
December 31, 1996, 1997 and 1998............................. F-4
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1996, 1997 and 1998......... F-5
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1997 and 1998............................. F-6
Notes to Consolidated Financial Statements.................... F-7
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of
Patina Oil & Gas Corporation:
We have audited the accompanying consolidated balance sheets of Patina Oil & Gas
Corporation (a Delaware corporation) and subsidiaries as of December 31, 1997
and 1998, and the related consolidated statements of operations, changes in
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Patina Oil & Gas Corporation
and subsidiaries as of December 31, 1997 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
Denver, Colorado, ARTHUR ANDERSEN LLP
February 12, 1999
F-2
<PAGE>
PATINA OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands except share data)
<TABLE>
<CAPTION>
December 31,
----------------------
1997 1998
---------- ----------
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents $ 12,609 $ 10,086
Accounts receivable 15,307 9,953
Inventory and other 3,152 3,286
--------- ---------
31,068 23,325
--------- ---------
Oil and gas properties, successful efforts method 575,508 598,712
Accumulated depletion, depreciation and amortization (232,675) (273,935)
--------- ---------
342,833 324,777
--------- ---------
Gas facilities and other 5,930 6,692
Accumulated depreciation (3,807) (4,590)
--------- ---------
2,123 2,102
--------- ---------
Other assets, net 851 1,329
--------- ---------
$376,875 $ 351,533
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 20,451 $ 16,825
Accrued liabilities 9,846 6,754
--------- ---------
30,297 23,579
--------- ---------
Senior debt 49,000 68,000
Subordinated notes 97,435 74,021
Other noncurrent liabilities 11,702 9,957
Commitments and contingencies
Stockholders' equity
Preferred Stock, $.01 par, 5,000,000 shares
authorized, 3,094,363 and 3,166,860 shares issued
and outstanding 31 32
Common Stock, $.01 par, 100,000,000 shares
authorized, 16,450,425 and 15,752,389 shares
issued and outstanding 165 158
Capital in excess of par value 208,525 206,792
Deferred compensation (1,828) (1,038)
Retained earnings (deficit) (18,452) (29,968)
--------- ---------
188,441 175,976
--------- ---------
$376,875 $ 351,533
========= =========
</TABLE>
The accompanying notes are an integral part of these statements.
F-3
<PAGE>
PATINA OIL & GAS CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except per share data)
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
1996 1997 1998
------- -------- --------
<S> <C> <C> <C>
Revenues
Oil and gas sales $82,185 $ 99,539 $72,177
Other 1,003 794 2,533
------- -------- -------
83,188 100,333 74,710
Expenses
Direct operating 14,519 18,790 17,340
Exploration 224 131 59
General and administrative 6,151 7,154 7,139
Interest and other 14,304 16,038 13,001
Depletion, depreciation and amortization 44,822 49,076 41,695
Impairment of oil and gas properties - 26,047 -
------- -------- -------
Income (loss) before taxes 3,168 (16,903) (4,524)
------- -------- -------
Provision (benefit) for income taxes
Current - - -
Deferred (394) - -
------- -------- -------
(394) - -
------- -------- -------
Net income (loss) $ 3,562 $(16,903) $(4,524)
======= ======== =======
Net income (loss) per common share $ 0.08 $ (1.11) $ (0.68)
======= ======== =======
Weighted average shares outstanding 17,796 18,324 16,025
======= ======== =======
</TABLE>
The accompanying notes are an integral part of these statements.
F-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 Investment Deferred Earnings
Shares Amount Shares Amount Par Value By SOCO Compensation (Deficit)
----------- -------- ---------- ----------- ---------- ------------ ------------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995 - $ - 14,000 $ 140 $ - $ 113,523 $ - $ -
Credit in lieu of taxes - - - - - 171 - -
Change in investment by
SOCO - - - - - (7,514) - -
Net loss through the
Merger date - - - - - (532) - -
Merger 1,205 12 6,000 60 194,291 (105,648) - -
Issuance of common - - 4 - 27 - - -
Repurchase of common and
warrants - - (1,117) (11) (9,722) - - -
Issuance of preferred 389 4 - - 9,470 - - -
Preferred dividends - - - - - - - (2,129)
Net income subsequent to
the Merger - - - - - - - 4,094
--------- -------- --------- ---------- ---------- ----------- ----------- ------------
Balance, December 31, 1996 1,594 16 18,887 189 194,066 - - 1,965
Repurchase of common and
preferred (126) (1) (3,101) (31) (32,723) - - -
Issuance of common - - 664 7 7,958 - (1,828) -
Issuance of preferred 1,600 16 - - 38,516 - - -
Preferred dividends and
accretion 26 - - - 708 - - (3,346)
Common dividends - - - - - - - (168)
Net loss - - - - - - - (16,903)
--------- -------- --------- ---------- ---------- ----------- ----------- ------------
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)
========== ======== ========= ========== ========== =========== =========== ============
</TABLE>
The accompanying notes are an integral part of these statements.
F-5
<PAGE>
PATINA OIL & GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------
1996 1997 1998
<S> ---------- ----------- ----------
Operating activities <C> <C> <C>
Net income (loss) $ 3,562 $ (16,903) $ (4,524)
Adjustments to reconcile net income (loss) to net
cash provided by operations
Exploration expense 224 131 59
Depletion, depreciation and amortization 44,822 49,076 41,695
Impairment of oil and gas properties - 26,047 -
Deferred compensation expense - 1,987 1,478
Deferred taxes (394) - -
Amortization of deferred credits (605) - (622)
Gain on sale of other assets - 338 (1,124)
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable (1,057) 4,548 5,354
Inventory and other 338 (213) 63
Increase (decrease) in
Accounts payable (4,249) 5,639 (3,626)
Accrued liabilities 4,844 (1,248) (3,092)
Other assets and liabilities 5,511 (81) (1,330)
---------- ----------- ----------
Net cash provided by operating activities 52,996 68,645 34,331
---------- ----------- ----------
Investing activities
Acquisition, development and exploration (8,532) (19,831) (24,089)
Gerrity Acquisition expenditures, net of cash acquired (2,375) - -
Other 1,111 1,030 944
---------- ----------- ----------
Net cash used by investing activities (9,796) (18,801) (23,145)
---------- ----------- ----------
Financing activities
Increase (decrease) in payable/debt to SOCO (80,466) - -
Increase (decrease) in indebtedness 72,862 (51,159) (4,414)
Deferred credits 814 2,005 1,271
Decrease in investment by SOCO (7,514) - -
Issuance of preferred stock - 39,432 -
Issuance of common stock - 2,795 1,396
Cost of common stock and preferred issuance (11,882) (900) -
Repurchase of common stock and warrants (9,733) (28,946) (7,315)
Repurchase of preferred stock - (3,809) (1,375)
Preferred dividends (2,129) (2,638) (2,615)
Common dividends - (168) (657)
---------- ----------- ----------
Net cash used by financing activities (38,047) (43,388) (13,709)
---------- ----------- ----------
Increase (decrease) in cash 5,153 6,456 (2,523)
Cash and equivalents, beginning of period 1,000 6,153 12,609
---------- ----------- ----------
Cash and equivalents, end of period $ 6,153 $ 12,609 $ 10,086
========== =========== ==========
</TABLE>
The accompanying notes are an integral part of these statements.
F-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 incorporated in early 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 May 1996, SOCO
contributed its Wattenberg assets to the Company in exchange for 14.0 million
common shares and Gerrity merged into a wholly owned subsidiary of the Company
("Gerrity Acquisition"). Gerrity was subsequently merged into the Company. The
Gerrity Acquisition was accounted for as a purchase. The amounts and results of
operations of the Company for periods prior to the Gerrity Acquisition included
in these financial statements reflect the historical amounts and results of
SOCO's Wattenberg operations. The Company's operations currently consist of the
acquisition, development, exploitation and production of oil and natural gas
properties in the Wattenberg Field of Colorado's D-J Basin.
In October 1997, a series of transactions took place that eliminated SOCO's
ownership in the Company. The transactions included: (i) the sale by SOCO of
10.9 million common shares of its Patina stock in a public offering, (ii) the
repurchase by the Company of SOCO's remaining 3.0 million common shares, (iii)
the sale by the Company of $40.0 million of 8.50% convertible preferred stock
and the issuance of 160,000 common shares to certain institutional investors and
(iv) the sale of 303,797 common shares at $9.875 per share and the grant of
496,250 restricted common shares by the Company to certain officers and
managers. As a result of these transactions, SOCO no longer has any ownership
in the Company.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Producing Activities
The Company utilizes the successful efforts method of accounting for its oil
and natural 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. In
applying this statement, the Company determined that 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 the net book value of these assets and accordingly, recorded an
impairment. The impairment primarily resulted from lower year-end oil and
natural gas prices. While no impairments were necessary in 1996 or 1998,
changes in underlying assumptions or the amortization units could result in
additional impairments in the future.
F-7
<PAGE>
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
Prior to December 31, 1997, Other Assets reflected the value assigned to a
noncompete agreement. The value of this noncompete agreement had been fully
amortized at December 31, 1997. Amortization expense for the years ended
December 31, 1996 and 1997 was $2.6 million and $2.5 million, related entirely
to the noncompete agreement. In the fourth quarter of 1997, management
determined that there was no remaining value with respect to this noncompete
agreement, and accordingly, amortized the remaining book value. Included in
Other Assets at December 31, 1997 and 1998 are $850,000 and $1.3 million of
notes receivable from certain officers and key managers of the Company. See
Note (9).
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, $1.8
million and $2.1 million during 1996, 1997 and 1998, 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,
1997 and 1998 were insignificant.
Financial Instruments
The book value and estimated fair value of cash and equivalents was $12.6
million and $10.1 million at December 31, 1997 and 1998. The book value and
estimated fair value of the Company's senior debt was $49.0 million and $68.0
million at December 31, 1997 and 1998. 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 fair value of the Notes is
estimated based on their price on the New York Stock Exchange.
From time to time, the Company enters into commodity derivatives 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 derivatives 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 derivatives
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) during
1997 and 1998. The Company recognized a loss of $(27,000) in 1997 and a gain of
$238,000 in 1998 related to these swap contracts based on settlements during the
respective periods. The Company entered into various CIG and PEPL index based
swap contracts for natural gas during 1997 and 1998. The Company recognized
gains of $1.8 million in 1997 and $1.5 million in 1998 related to these swap
contracts based on settlements during the respective periods.
F-8
<PAGE>
As of December 31, 1998, the Company had entered into CIG index based swap
contracts for natural gas for the period January 1999 through September 1999 and
PEPL index based swap contracts for natural gas for the period January 1999
through March 1999. The weighted average natural gas prices for the CIG index
based contracts are $1.77 for contract volumes of 4,937,000 MMBtu's of natural
gas and for the PEPL index based contracts are $2.40 for contract volumes of
362,000 MMBtu's of natural gas. The unrecognized gains on these contracts
totaled $734,000 based on December 31, 1998 fair market values. Subsequent to
year-end, the Company received cash proceeds of $287,000 for the January and
February 1999 CIG and PEPL index based swap contracts. The Company did not have
any open positions with respect to oil hedging at December 31, 1998.
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 three-month LIBOR
rate on the date the contract was entered into was 5.34%. Accordingly, the
Company received $59,000 in January 1999. The unrecognized gain on this
contract totaled $198,000 based on December 31, 1998 market values.
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 June 15, 1999. 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 $2.0 million and $1.5 million of non-cash general and administrative
expenses in 1997 and 1998. 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.
Risks and Uncertainties
Historically, the market for oil and natural gas has experienced significant
price fluctuations. Prices for natural gas in the Rocky Mountain region have
been particularly volatile in recent years. 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.
F-9
<PAGE>
Supplemental Cash Flow Information
The Company incurred the following significant non-cash items:
<TABLE>
<CAPTION>
Year-Ended December 31,
1997 1998
---- ------
<S> <C> <C>
Stock grant awarded to certain officers and key managers.. $3,821 $ 688
Stock purchase plan....................................... - 173
Dividends and accretion - 8.50% preferred stock........... 708 3,720
401(k) profit sharing in common stock..................... 453 338
</TABLE>
The stock grant award represents 100,000 common shares granted to the new
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 Company recognized $2.0 million
and $1.5 million of non-cash general and administrative expenses related to this
stock grant and the stock grants awarded to certain officers and managers in
1997 and 1998 in conjunction with the redistribution of SOCO's ownership of the
Company. See Note (9).
The Company incurred the following significant non-cash items related to the
Gerrity Acquisition in 1996:
<TABLE>
<CAPTION>
(In thousands)
<S> <C>
Cash payments made for the acquisition.......................................... $ 14,257
Senior debt assumed............................................................. 19,000
Subordinated debt assumed....................................................... 105,805
Minority interest in Gerrity preferred stock not exchanged at acquisition date.. 9,878
Preferred stock issued.......................................................... 30,122
Common stock and warrants issued................................................ 46,750
Other liabilities assumed....................................................... 12,423
--------
Fair value of assets acquired................................................... $238,235
========
</TABLE>
The above cash payments made include approximately $4.9 million of costs
capitalized and allocated to oil and gas properties. The above cash payments
are reduced in the accompanying consolidated statements of cash flows by $2.1
million for cash acquired in the Gerrity Acquisition.
Other
All liquid investments with an original maturity of three months or less are
considered to be cash equivalents. Certain amounts in prior period consolidated
financial statements have been reclassified to conform with the current
classifications.
All cash payments for income taxes were made by SOCO during 1996 and through
May 2, 1996, at which point the Company began paying its own taxes. The Company
was charged interest by SOCO on its debt of $1.6 million through May 2, 1996,
which was reflected as an increase in debt to SOCO.
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.
F-10
<PAGE>
(3) OIL AND GAS PROPERTIES
The cost of oil and gas properties at December 31, 1996 and 1997 includes no
significant unevaluated leasehold costs. As of December 31, 1998 oil and gas
properties included approximately $585,000 in unevaluated leasehold costs
related to a prospect in Wyoming. Acreage is generally held for exploration,
development or resale and its value, if any, is excluded from amortization. The
following table sets forth costs incurred related to oil and gas properties:
<TABLE>
<CAPTION>
1996 1997 1998
-------- ------- -------
<S> <C> <C> <C>
(In thousands)
Acquisition............ $218,380 $ 2,225 $ 2,319
Development............ 8,301 17,013 21,711
Exploration and other.. 224 131 59
-------- ------- -------
$226,905 $19,369 $24,089
======== ======= =======
</TABLE>
In May 1996, the Gerrity Acquisition discussed in Note 1 was consummated.
The following table summarizes the unaudited pro forma effects on the Company's
financial statements assuming that the Gerrity Acquisition and the Original
Exchange Offer (see Note 5) had been consummated on January 1, 1996. Future
results may differ substantially from pro forma results due to changes in these
assumptions, changes in oil and natural gas prices, production declines and
other factors. Therefore, pro forma statements cannot be considered indicative
of future operations (in thousands, except per share data).
Year Ended
December 31,
1996
----
Total revenues $100,138
Gross operating margin.................... 82,420
Depletion, depreciation and amortization.. 51,662
Net income (loss)......................... 3,476
Net income (loss) per common share........ $ 0.03
Weighted average shares outstanding....... 19,796
(4) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
December 31,
----------------
1997 1998
------- -------
(In thousands)
Bank facilities....... $49,000 $68,000
Less current portion.. - -
------- -------
Senior debt, net...... $49,000 $68,000
======= =======
Subordinated notes.... $97,435 $74,021
======= =======
In April 1997, the Company entered into an amended bank Credit Agreement (the
"Credit Agreement"). The Credit Agreement is a revolving credit facility in an
aggregate amount up to $140.0 million. The amount available under the facility
is adjusted semiannually, each May 1 and November 1, and equaled $100.0 million
at December 31, 1998 with $68.0 million of debt outstanding at that time.
F-11
<PAGE>
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 nine months (as selected by the Company) are
offered in the interbank Eurodollar market plus a margin which fluctuates from
0.625% to 1.125%, determined by a debt to EBITDA ratio. During 1998, the
average interest rate under the facility approximated 6.6%.
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 three-month LIBOR
rate on the date the contract was entered into was 5.34%. Accordingly, the
Company received $59,000 in January 1999.
The Credit Agreement contains certain financial covenants, including but not
limited to, a maximum total debt to capitalization ratio, 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 2000, 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 $8.4 million as of December 31, 1998, 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 have been reflected in the accompanying financial
statements at a book value of 105.875% of their principal amount, their call
price as of July 15, 1999. Interest is payable each January 15 and July 15. The
Notes are redeemable at the option of the Company, in whole or in part, at any
time on or after July 15, 1999, initially at 105.875%, declining to 102.938% on
July 15, 2000, and declining to 100% on July 15, 2001. Upon a change of control,
as defined in the Notes, the Company is obligated to make an offer to purchase
all outstanding Notes at a price of 101% of the principal amount thereof. In
addition, the Company would be obligated, subject to certain conditions, to make
offers to purchase the Notes with the net cash proceeds of certain asset sales
at a price of 101% of the principal amount thereof. Since the Gerrity
Acquisition, the Company has repurchased $30.1 million principal amount of the
Notes, resulting in $69.9 million of principal amount of Notes outstanding.
These Notes are reflected at a book value of $74.0 million at December 31, 1998
in the accompanying financial statements. The Notes are unsecured general
obligations and are subordinated to all senior indebtedness and to any existing
and future indebtedness of the Company's subsidiaries.
The Notes contain covenants that, among other things, limit the ability of
the Company to incur additional indebtedness, pay dividends, engage in
transactions with shareholders and affiliates, create liens, sell assets, engage
in mergers and consolidations and make investments in unrestricted subsidiaries.
Specifically, the Notes restrict the Company from incurring additional
indebtedness (exclusive of the Notes), if after giving effect to the incurrence
of such additional indebtedness and the receipt and application of the proceeds
therefrom, the Company's interest coverage ratio is less than 2.5:1 or adjusted
consolidated net tangible assets is less than 150% of the aggregate indebtedness
of the Company. The Company currently meets these ratios and accordingly, is
not limited in its ability to incur additional debt.
Scheduled maturities of indebtedness for the next five years are zero for
1999 and $68.0 million in 2000, and zero in 2001, 2002 and 2003. The bank credit
facility is scheduled to expire in 2000. 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 $10.5 million, $16.5 million and $14.0 million during 1996, 1997 and
1998, respectively.
F-12
<PAGE>
(5) STOCKHOLDERS' EQUITY
A total of 100.0 million common shares, $.01 par value, are authorized of
which 15.8 million were issued and outstanding at December 31, 1998. 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
5,554,800 shares of common stock (including the 3.0 million common shares
repurchased from SOCO in conjunction with the redistribution of SOCO's majority
ownership in October 1997), 125,682 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 $51.3 million. The common stock is listed on the New York
Stock Exchange. Prior to December 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
December 31, 1998, the Company had two issues of preferred stock outstanding
consisting of 1,467,926 shares of 7.125% preferred and 1,698,934 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, Gerrity's certificate of incorporation was
amended to provide that all remaining shares of Gerrity's preferred stock be
exchanged for 7.125% preferred shares on the same terms as the Original Exchange
Offer. This exchange resulted in the issuance of an additional 389,000 preferred
shares. 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
redeemable at the option of the Company at any time after May 2, 1998 if the
average closing price of the common stock for 20 of the 30 days prior to not
less than five days preceding the redemption date is greater than $12.92 per
share or at any time after May 2, 1999 at an initial call price of $26.25 per
share. The liquidation preference of the 7.125% preferred stock is $25 per
share, plus accrued and unpaid dividends. As of December 31, 1998, there were
1,467,926 7.125% preferred shares outstanding with an aggregate liquidation
preference of $36.7 million. 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 $2.1 million, $2.6 million and $2.6 million ($.4453 per 7.125% convertible
preferred share each quarter) in preferred dividends during 1996, 1997 and 1998,
and had accrued an additional $327,000 at December 31, 1997 and 1998,
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.
The investors agreed not to sell, transfer or dispose of any shares of the 8.50%
preferred prior to October 1999. 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 December 31, 1998, there were
1,698,934 8.50% preferred shares outstanding with an aggregate liquidation
preference of $42.5 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 $661,000 and $3.5 million in
PIK Dividends (issued an additional 26,437 and 141,240 8.50% preferred shares)
in 1997 and 1998.
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.
F-13
<PAGE>
In accordance with SFAS 128, the Company computed the net income (loss) per
share by dividing the net income (loss), less dividends and accretion on
preferred stock, by the weighted average common shares outstanding during the
period. Net income (loss) applicable to common for 1996, 1997 and 1998, was
$1,433,000, ($20,249,000) and ($10,859,000), respectively.
Diluted net income (loss) per share was computed by dividing the net income
(loss), less dividends and accretion on preferred stock, by the weighted average
common shares outstanding during the period plus all dilutive potential shares
outstanding (zero for twelve months ended December 31, 1997 and 1998,
respectively). 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. Net income (loss) per common share and
diluted net income (loss) per common share were the same for all periods
presented.
(6) EMPLOYEE BENEFIT PLANS
401(k) Savings
The Company has a 401(k) profit sharing and savings plan (the "401(k) Plan").
The initial 401(k) Plan was established in May 1996. In conjunction with the
sale of SOCO's ownership of the Company in October 1997, a new plan was adopted
effective January 1, 1997. 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
$281,000, $453,000 and $338,000 for 1996, 1997 and 1998, respectively. The 1997
and 1998 profit sharing contributions were made in shares of the Company's
common stock (59,901 and 138,462 common shares, respectively).
Stock Purchase Plan
In February 1998, the Company adopted and in May 1998 the stockholders
approved, a stock purchase plan ("Stock Purchase Plan"). Pursuant to the Stock
Purchase Plan, certain officers, directors and 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 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 have 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.
The Company recorded non-cash general and administrative expenses of $173,000
associated with these purchases in 1998.
F-14
<PAGE>
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 lesser of up to three million shares of common stock or 10% of
outstanding 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 total of 512,000 options were issued in
May 1996, with an exercise price of $7.75 per common share, 271,000 options were
issued in February 1997, with an exercise price of $9.25 per common share,
485,000 options were issued in February 1998, 96,000 in March 1998, 25,000 in
May 1998, and 8,000 in July 1998 with exercise prices of $7.06, $6.88, $7.19 and
$6.56 per common share, respectively. The options vest over a three-year period
(30%, 60%, 100%) and expire five years from date of grant. In addition, 250,000
fully vested five year options were granted in October 1997 at an exercise price
of $9.875.
In 1996, the shareholders adopted a stock grant and option plan (the
"Directors' Plan") for nonemployee Directors. The Directors' Plan provides for
each eligible 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 and 11,914 shares were
issued in 1998. It also provides for 5,000 options to be granted annually to
each eligible Director. A total of 20,000 options were issued in May 1996, with
an exercise price of $7.75 per common share, 20,000 options were issued in May
1997, with an exercise price of $8.625, and 25,000 options were issued in May
1998, with an exercise price of $7.75. In addition, 10,000 options were issued
in October 1997 with an exercise price of $10.313 and 10,000 options were issued
in January 1998 with an exercise price of $7.19. The options vest over a three-
year period (30%, 60%, 100%) and expire five years from date of grant.
In October 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 of the Company. The plan, which was
amended effective December 31, 1997, provided for the grant of 496,250
restricted common shares, net of forfeitures, to the Management Investors.
These shares will 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).
In conjunction with the appointment of a new President in March 1998, the
President was included in the stock grant and purchase plans. He was granted
100,000 restricted common shares that will 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).
The Company recognized $2.0 million and $1.5 million of non-cash general and
administrative expenses in 1997 and 1998 with respect to the stock grants.
F-15
<PAGE>
At December 31, 1998, the Company had a fixed stock option compensation plan,
which is described above. The Company applies APB Opinion No. 25, "Accounting
for Stock Issued to Employees," and related Interpretations in accounting for
the plans. Accordingly, no compensation cost has been recognized for these
fixed stock option plans. Had compensation cost for the Company's fixed stock
option compensation plans been determined consistent with Statement of Financial
Accounting Standards No. 123 ("SFAS 123"), "Accounting for Stock-Based
Compensation," the Company's net income (in thousands) and earnings per share
would have been reduced to the pro forma amounts indicated below:
<TABLE>
<CAPTION>
1996 1997 1998
---- ---- ----
<S> <C> <C> <C>
Net income (loss) As Reported $ 3,562 $(16,903) $(4,524)
Pro forma 3,281 (18,611) (5,724)
Net income (loss)
per common share As Reported $ 0.08 $ (1.11) $ (0.68)
Pro forma 0.06 (1.20) (0.75)
</TABLE>
The fair value of each option grant is estimated on the date of grant using
the Black-Sholes option-pricing model with the following weighted-average
assumptions used for grants in 1996, 1997 and 1998: dividend yield of 0%, 0% and
0%; expected volatility of 30%, 35% and 46%; risk-free interest rate of 6.4%,
6.0% and 5.5%; and expected life of 4.5 years, 4.5 years and 4.5 years,
respectively.
A summary of the status of the Company's fixed stock option plan as of
December 31, 1996, 1997 and 1998 and changes during the years are presented
below:
<TABLE>
<CAPTION>
1996 1997 1998
---------------------- ----------------------- ----------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
-------- ----- -------- ----- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning
of year............................... - $ - 503,000 $7.75 1,001,000 $ 8.70
Granted................................ 532,000 7.75 551,000 9.53 649,000 7.06
Exercised.............................. - - (12,000) 7.75 - -
Forfeited.............................. (29,000) 7.75 (41,000) 8.38 (124,000) (7.91)
-------- --------- ----------
Outstanding at end of
year.................................. 503,000 $ 7.75 1,001,000 $8.70 1,526,000 $ 8.07
======== ========= ==========
Options exercisable at year-end........ - 389,000 582,000
======== ====== ========== ==========
Weighted-average fair value of options
granted during the year............. $ 2.81 $3.84 $ 3.17
</TABLE>
<TABLE>
<CAPTION>
The following table summarizes information about fixed stock options outstanding
at December 31, 1998:
Options Outstanding Options Exercisable
-------------------------------------------------- --------------------------------
Number Number
Outstanding at Weighted-Avg. Weighted- Exercisable at Weighted-
December 31, Remaining Average December 31, Average
Exercise Price 1998 Contractual Life Exercise Price 1998 Exercise Price
- -------------- --------- ---------------- -------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
$6.56 to 7.06 538,000 4.2 years $ 7.02 - $ -
7.19 to 9.25 733,000 2.8 years 8.21 330,000 8.07
9.88 to 10.31 255,000 3.8 years 9.88 252,000 9.88
--------- --------
$6.56 to 10.31 1,526,000 3.4 years $ 8.07 582,000 $ 8.85
========= ========
</TABLE>
F-16
<PAGE>
(7) FEDERAL INCOME TAXES
Prior to the Gerrity Acquisition, the Company had been included in SOCO's
consolidated tax return. Current and deferred income tax provisions allocated
by SOCO were determined as though the Company filed as an independent company,
making the same tax return elections used in SOCO's consolidated return. Since
the Gerrity Acquisition, the Company has filed its own tax returns.
A reconciliation of the federal statutory rate to the Company's effective
rate as they apply to the provision (benefit) for the years ended December 31,
1996, 1997 and 1998 follows:
<TABLE>
<CAPTION>
1996 1997 1998
------- -------- --------
<S> <C> <C> <C>
Federal statutory rate...................................................................... 35% (35%) (35%)
Utilization of net deferred tax asset....................................................... (35%) - -
Increase in valuation allowance against deferred tax asset.................................. - 35% 35%
Tax benefit recognized prior to the Gerrity Acquisition..................................... (12%) - -
------- -------- --------
Effective income tax rate................................................................... (12%) - -
======= ======== ========
</TABLE>
For book purposes the components of the net deferred asset and liability at
December 31, 1997 and 1998 were:
<TABLE>
<CAPTION>
1997 1998
-------- --------
(In thousands)
<S> <C> <C>
Deferred tax assets
NOL carryforwards.......................................................................... $ 30,497 $ 29,080
Deferred deductions........................................................................ 4,517 4,941
------- --------
35,014 34,021
------- --------
Deferred tax liabilities
Depreciable and depletable property........................................................ 23,360 20,582
------- --------
Deferred tax assets......................................................................... 11,654 13,439
------- --------
Valuation allowance......................................................................... (11,654) (13,439)
------- --------
Net deferred tax asset...................................................................... $ - $ -
======= ========
</TABLE>
For tax purposes, the Company had regular net operating loss carryforwards of
approximately $83.0 million and alternative minimum tax ("AMT") loss
carryforwards of approximately $34.6 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 October 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. No cash payments
were made by the Company for federal taxes during 1996 and 1997. The Company
paid $239,000 of federal taxes during 1998.
(8) MAJOR CUSTOMERS
During 1996, 1997 and 1998, Duke Energy Field Services, Inc. accounted for
38%, 41% and 38%, Amoco Production Company accounted for 19%, 16% and 13%, Total
Petroleum accounted for 10%, 8% and 6%, and Enron Capital & Trade Resources
accounted for 0%, 5%, 10% 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.
F-17
<PAGE>
(9) RELATED PARTY
Subsequent to the Gerrity Acquisition, SOCO agreed to provide certain
administrative services to Patina under a corporate services agreement. As of
May 31, 1998, the Company terminated this agreement and no longer utilizes any
corporate services from SOCO. The Company continues to sublease certain office
space from SOCO through 2001. During the 1996, 1997 and 1998, the Company paid
approximately $650,000, $1.5 million and $600,000 to SOCO under the corporate
services and sublease agreements.
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.
In conjunction with the appointment of the new President of the Company in
March 1998, the President purchased 100,000 shares of common stock at $6.875 per
share. The Company loaned the President $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.
(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 from 1999 through 2001.
In March 1996, a complaint was filed in the Court of Chancery for the State
of Delaware against Gerrity and each of its directors, Brickell Partners v.
Gerrity Oil & Gas Corporation, C.A. No. 14888 (Del. Ch.). The complaint alleges
that the "action is brought (a) to restrain defendants from consummating the
Gerrity Acquisition which will benefit the holders of Gerrity's common stock at
the expense of the holders of Gerrity's preferred stock and (b) to obtain a
declaration that the terms of the proposed Gerrity Acquisition constitute a
breach of the contractual rights of the preferred." The complaint sought, among
other things, certification as a class action on behalf of all holders of
Gerrity's preferred stock, a declaration that the defendants have committed an
abuse of trust and have breached their fiduciary and contractual duties, an
injunction enjoining the Gerrity Acquisition and money damages. In April 1996,
the defendants were granted an indefinite extension of time in which to answer
the complaint and no answer had been filed by February 1997. In February 1997,
the attorney for the plaintiff filed a Status Report with the court stating
"Case has been mooted. Plaintiff is preparing an application for counsel fees."
No fee application was filed. In November 1997, the plaintiff filed an amended
complaint. The amended complaint realleges the substance of the original
complaint and includes an allegation that the defendants coerced the holders of
the Gerrity preferred stock into exchanging their stock for the 7.125% Preferred
Stock of the Company. The amended complaint also alleges the defendants
participated in a scheme to eliminate the outstanding Gerrity preferred by
forcing the exchange of those shares for shares of the Company's preferred in
October 1996. The amended complaint seeks rescission of the transactions
described in the complaint or money damages if rescission is impractical. On
January 5, 1998, defendants filed a motion to dismiss the amended complaint. A
brief in support of the motion to dismiss was filed in August 1998 and there has
been no response from the plaintiffs. Defendants believe that the amended
complaint is without merit and intend to vigorously defend against this action.
At this time, the Company is unable to estimate the range of potential loss, if
any, from this uncertainty. However, the Company believes the resolution of
this uncertainty should not have a material adverse effect upon the Company's
financial position, although an unfavorable outcome in any reporting period
could have a material adverse effect on results for that period.
The Company is a party to various other lawsuits incidental to its business,
none of which are anticipated to have a material adverse impact on its financial
position or results of operations.
F-18
<PAGE>
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Independent petroleum consultants directly evaluated total proved reserves at
December 31, 1996 and audited total proved reserves at December 31, 1997 and
1998. All reserve estimates are based on economic and operating conditions at
that time. Future net cash flows as of each year-end were computed by applying
then current prices to estimated future production less estimated future
expenditures (based on current costs) to be incurred in producing and developing
the reserves. All reserves are located onshore in the United States.
Future prices received for production and future production costs may vary,
perhaps significantly, from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that prices and costs will remain constant.
With respect to certain properties that historically have experienced seasonal
curtailment, the reserve estimates assume that the seasonal pattern of such
curtailment will continue in the future. There can be no assurance that actual
production will equal the estimated amounts used in the preparation of reserve
projections.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development
expenditures. The data in the tables below represent estimates only. Oil and
gas reserve engineering must be recognized as a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact way, and estimates of other engineers might differ materially from those
shown below. The accuracy of any reserve estimate is a function of the quality
of available data and engineering and geological interpretation and judgement.
Results in drilling, testing and production after the date of the estimate may
justify revisions. Accordingly, reserve estimates are often materially
different from the quantities of oil and gas that are ultimately recovered.
F-19
<PAGE>
<TABLE>
<CAPTION>
Quantities of Proved Reserves
Oil Natural Gas
--- -----------
(MBbl) (MMcf)
<S> <C> <C>
Balance, December 31, 1995.............. 7,421 138,857
Revisions.............................. 720 (1,314)
Extensions, discoveries and additions.. 194 1,342
Production............................. (1,688) (23,947)
Purchases.............................. 15,834 183,729
Sales.................................. (6) (2,008)
------ -------
Balance, December 31, 1996.............. 22,475 296,659
Revisions (a).......................... (4,418) (27,671)
Extensions, discoveries and additions.. 784 11,162
Production............................. (1,889) (26,863)
Purchases.............................. 101 3,193
Sales.................................. (77) (845)
------ -------
Balance, December 31, 1997.............. 16,976 255,635
Revisions (a).......................... (3,033) (23,084)
Extensions, discoveries and additions.. 1,890 77,120
Production............................. (1,699) (25,522)
Purchases.............................. 108 2,465
Sales.................................. (2) (19)
------ -------
Balance, December 31, 1998.............. 14,240 286,595
====== =======
Proved Developed Reserves
Oil Natural Gas
--- -----------
(MBbl) (MMcf)
December 31, 1995........................ 6,955 133,088
====== =======
December 31, 1996........................ 15,799 242,777
====== =======
December 31, 1997........................ 14,594 232,058
====== =======
December 31, 1998........................ 13,655 244,736
====== =======
</TABLE>
(a) Revisions are primarily attributable to proved undeveloped drilling
locations and proved developed non-producing zones (behind-pipe
recompletions) determined to be uneconomic using the lower oil and natural
gas prices in effect at December 31, 1997 and 1998 (4,060 MBbl's and 31,232
MMcf's in 1997 and 3,468 MBbl's and 31,622 MMcf's in 1998).
F-20
<PAGE>
<TABLE>
<CAPTION>
Standardized Measure
December 31,
-----------------------------------
1996 1997 1998
---------- ---------- ---------
(In thousands)
<S> <C> <C> <C>
Future cash inflows...................... $1,668,475 $ 894,390 $ 692,747
Future costs
Production.............................. (338,752) (255,599) (220,846)
Development............................. (160,856) (87,414) (68,125)
---------- --------- ---------
Future net cash flows.................... 1,168,867 551,377 403,776
Undiscounted income taxes................ (294,407) (89,094) (41,977)
---------- --------- ---------
After tax net cash flows................. 874,460 462,283 361,799
10% discount factor...................... (374,524) (185,953) (156,395)
---------- --------- ---------
Standardized measure..................... $ 499,936 $ 276,330 $ 205,404
========== ========= =========
Changes in Standardized Measure
<CAPTION>
December 31,
-----------------------------------
1996 1997 1998
---------- ---------- ---------
(In thousands)
<S> <C> <C> <C>
Standardized measure, beginning of year.. $ 127,516 $ 499,936 $ 276,330
Revisions:
Prices and costs....................... 351,724 (312,526) (124,977)
Quantities............................. 501 6,134 8,396
Development costs...................... (11,024) (14,783) (3,310)
Accretion of discount.................. 27,619 49,994 27,633
Income taxes........................... (129,612) 105,189 23,944
Production rates and other............. (3,706) (8,433) (5,449)
---------- --------- ---------
Net revisions.......................... 235,502 (174,425) (73,763)
Extensions, discoveries and additions.... 3,791 11,756 33,910
Production............................... (67,666) (81,149) (54,837)
Future development costs incurred........ 7,906 17,013 21,711
Purchases (a)............................ 193,998 3,900 2,068
Sales (b)................................ (1,111) (701) (15)
---------- --------- ---------
Standardized measure, end of year........ $ 449,936 $ 276,330 $ 205,404
========== ========= =========
</TABLE>
(a) "Purchases" includes the present value at the end of the period acquired
during the year plus cash flow received on such properties during the
period, rather than their estimated present value at the time of the
acquisition.
(b) "Sales" represents the present value at the beginning of the period of
properties sold, less the cash flow received on such properties during the
period.
F-21
<PAGE>
PART IV. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Exhibits -
2.1 Amended and Restated Agreement and Plan of Merger dated as of January
16, 1996 as amended and restated as of March 20, 1996 -- incorporated
by reference to Exhibit 2.1 to Amendment No. 1 to the Registration
Statement on Form S-4 of Patina Oil & Gas Corporation. (Registration
No. 333-572)
4.1 Certificate of Incorporation -- incorporated herein by reference to
the Exhibit 3.1 to the Company's Registration Statement on Form S-4
(Registration No. 333-572)
4.2 Bylaws -- incorporated herein by reference to Exhibit 3.3 to the
Company's Registration Statement on Form S-4 (Registration No. 333-
572)
4.3 Certificate of Ownership and Merger of Gerrity Oil & Gas Corporation
with and into the Company, effective March 21, 1997. (Incorporated
herein by reference to Exhibit 4.3 of the Company's Form 10-Q for the
quarter ended March 31, 1997.)
10.1.1 Amended and Restated Credit Agreement dated April 1, 1997 by and
among the Company, as Borrower, and Texas Commerce Bank National
Association, as Administrative Agent, and certain commercial lending
institutions. (Incorporated herein by reference to Exhibit 10.1.5 of
the Company's Form 10-Q for the quarter ended March 31, 1997.)
10.1.2 First Amendment to the Amended and Restated Credit Agreement
effective May 1, 1997 by and among the Company, as Borrower, and Texas
Commerce Bank National Association, as Administrative Agent, and
certain commercial lending institutions. (Incorporated herein by
reference to Exhibit 10.1.6 of the Company's Form 10-Q for the quarter
ended March 31, 1997.)
10.1.3 Second Amendment to Amended and Restated Credit Agreement dated as
of September 15, 1997 by and among the Company and Texas Commerce Bank
National Association, as Administrative Agent, NationsBank of Texas,
N.A. as Documentary Agent, Wells Fargo Bank, N.A., CIBC, Inc. and
Credit Lyonnais New York Branch, as Co-Agents and the financial
institutions a party to the Credit Agreement. (Incorporated herein by
reference to Exhibit 10.1.8 of the Company's Form 10-Q for the quarter
ended September 30, 1997.)
10.2.1 Supplemental Indenture dated as of March 31, 1997 among Gerrity Oil
& Gas Corporation, the Company and The Chase Manhattan Bank (formerly
known as Chemical Bank) as Trustee. (Incorporated herein by reference
to Exhibit 10.1.7 of the Company's Form 10-Q for the quarter ended
March 31, 1997.)
10.3 Patina Oil & Gas Corporation Profit Sharing and Savings Plan and
Trust, effective January 1, 1997 (Incorporated herein by reference to
Exhibit 10.3 of the Company's Form 10-K for the year ended, December
31, 1997).
10.3.1 Deferred Compensation Plan for Selected Employees adopted by the
Company effective May 1, 1996. (Incorporated herein by reference to
Exhibit 10.3.1 of the Company's Form 10-K for the year ended December
31, 1996)
F-22
<PAGE>
10.3.2 Amended and Restated Patina Oil & Gas Corporation Deferred
Compensation Plan for Select Employees as adopted May 1, 1996 and
amended as of September 30, 1997 (Incorporated herein by reference to
Exhibit 10.3.2 of the Company's Form 10-K for the year ended December
31, 1997).
10.3.3 Patina Oil & Gas Corporation 1998 Stock Purchase Plan (Incorporated
herein by reference to Exhibit 10.3.3 of the Company's Form 10-K for
the year ended December 31, 1997).
10.4 Sublease Agreement dated as of May 1, 1996 by and between Snyder Oil
Corporation, as Sublandlord, and the Company, as Subtenant.
(Incorporated herein by reference to Exhibit 10.4 of the Company's
Form 10-Q for the quarter ended June 30, 1996.)
10.4.1 Sublease Agreement dated as of October 7, 1996 by and between
Gerrity Oil & Gas Corporation, as Sublandlord, and Shadownet
Technologies, L.L.C. (Incorporated herein by reference to Exhibit
10.4 of the Company's Form 10-Q for the quarter ended September 30,
1996.)
10.5 Stock Purchase Agreement dated as of July 31, 1997 by and among the
Company and the Investors named therein as amended on September 19,
1997. (Incorporated herein by reference to Exhibit 10.5 of the
Company's Form 10-Q for the quarter ended September 30, 1997.)
10.6 Share Repurchase Agreement dated as of July 31, 1997 by and between
the Company and Snyder Oil Corporation as amended and restated on
September 19, 1997 and as amended as of October 15, 1997 and amended
by letter agreement dated October 21, 1997. (Incorporated herein by
reference to Exhibit 10.6 of the Company's Form 10-Q for the quarter
ended September 30, 1997.)
10.7 Employment Agreement dated July 31, 1997 by and between the Company
and Thomas J. Edelman. (Incorporated herein by reference to Exhibit
10.7 of the Company's Form 10-Q for the quarter ended September 30,
1997.)
10.8 Management Stock Purchase Agreement dated as of September 4, 1997 by
and among the Company and certain Management Investors. (Incorporated
herein by reference to Exhibit 10.8 of the Company's Form 10-Q for the
quarter ended September 30, 1997.)
10.9 Restricted Stock Agreement dated as of September 4, 1997 by and among
the Company and certain Management Investors. (Incorporated herein by
reference to Exhibit 10.9 of the Company's Form 10-Q for the quarter
ended September 30, 1997.)
10.10 Transition Agreement dated as of October 21, 1997 by and between the
Company and Snyder Oil Corporation. (Incorporated herein by reference
to Exhibit 10.10 of the Company's Form 10-Q for the quarter ended
September 30, 1997.)
10.11 Stock Purchase Agreement dated March 16, 1998 by and between the
Company and Jay W. Decker (Incorporated herein by reference to Exhibit
10.11 of the Company's Form 10-K for the year ended December 31,
1997).
10.12 Restricted Stock Agreement dated March 16, 1998 by and between the
Company and Jay W. Decker (Incorporated herein by reference to Exhibit
10.11 of the Company's Form 10-K for the year ended December 31,
1997).
11.1 Computation of Per Share Earnings.*
F-23
<PAGE>
12 Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings
to Combined Fixed Charges and Preferred Stock Dividends.*
27 Financial Data Schedule.*
*Filed herewith
(b) No reports on Form 8-K were filed by Registrant during the quarter ended
December 31, 1998.
F-24
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
/s/ Thomas J. Edelman Chairman of the Board March 5, 1999
- ----------------------------- (Principal Executive Officer)
Thomas J. Edelman
/s/ Jay W. Decker President and Director March 5, 1999
- -----------------------------
Jay W. Decker
/s/ Brian J. Cree Director, Executive Vice March 5, 1999
- ----------------------------- President and Chief Operating
Brian J. Cree Officer
/s/ David J. Kornder Vice President and March 5, 1999
- ----------------------------- Chief Financial Officer
David J. Kornder
/s/ Christopher C. Behrens Director March 5, 1999
- -----------------------------
Christopher C. Behrens
/s/ Robert J. Clark Director March 5, 1999
- -----------------------------
Robert J. Clark
/s/ Thomas R. Denison Director March 5, 1999
- -----------------------------
Thomas R. Denison
/s/ Elizabeth K. Lanier Director March 5, 1999
- -----------------------------
Elizabeth K. Lanier
/s/ Alexander P. Lynch Director March 5, 1999
- -----------------------------
Alexander P. Lynch
F-25
<PAGE>
EXHIBIT 11
COMPUTATION OF NET INCOME PER SHARE
FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
(dollars in thousands, except ratio's)
1996 1997 1998
---- ---- ----
Basic net income (loss) per share:
Net income (loss) $ 3,562 $(16,903) $ (4,524)
Dividends on preferred stock (2,129) (3,346) (6,335)
------- -------- --------
Net income (loss) available common $ 1,433 $(20,249) $(10,859)
Weighted average shares outstanding 17,796 18,324 16,025
Net income (loss) per share $ 0.08 $ (1.11) $ (0.68)
======= ======== ========
Diluted net income (loss) per share:
Net income (loss) $ 3,562 $(16,903) $ (4,524)
Dividends on preferred stock (2,129) (3,346) (6,335)
------- -------- --------
Net income (loss) available common $ 1,433 $(20,249) $(10,859)
Weighted average shares outstanding 17,796 18,324 16,025
Net income (loss) per share $ 0.08 $ (1.11) $ (0.68)
======= ======== ========
Note: The common stock options, common stock grants, $12.50 common stock
warrants, 7.125% convertible preferred stock and 8.50% convertible preferred
stock were anti-dilutive for all periods presented.
<PAGE>
EXHIBIT 12
COMPUTATION OF RATIO OF EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS
(UNAUDITED)
(dollars in thousands, except ratio's)
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998
------ -------- ------- --------- --------
<S> <C> <C> <C> <C> <C>
Net income (loss) before taxes $4,539 $(3,222) $ 3,168 $(16,903) $(4,524)
Interest expense 3,869 5,409 14,275 15,939 12,867
------ ------- ------- -------- -------
Earning before fixed charges 8,408 2,187 17,443 (964) 8,343
====== ======= ======= ======== =======
Preferred dividends - - 2,129 3,346 6,335
Ratio of pretax income to net income 1.54 1.54 0.89 1.00 1.00
------ ------- ------- -------- -------
Preferred dividend factor - - 1,895 3,346 6,335
Fixed charges:
Interest expense 3,869 5,409 14,275 15,939 12,867
Preferred dividend factor - - 1,895 3,346 6,335
------ ------- ------- -------- -------
Total fixed charges and preferred
dividends 3,869 5,409 16,170 19,285 19,202
====== ======= ======= ======== =======
Ratio of earning to combined fixed
charges and preferred dividend 2.17 0.40 1.08 (0.05) 0.43
====== ======= ======= ======== =======
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 10,086
<SECURITIES> 0
<RECEIVABLES> 10,331
<ALLOWANCES> (378)
<INVENTORY> 2,827
<CURRENT-ASSETS> 23,325
<PP&E> 605,404
<DEPRECIATION> (278,525)
<TOTAL-ASSETS> 351,533
<CURRENT-LIABILITIES> 23,579
<BONDS> 142,021
0
32
<COMMON> 158
<OTHER-SE> 175,786
<TOTAL-LIABILITY-AND-EQUITY> 351,533
<SALES> 72,177
<TOTAL-REVENUES> 74,710
<CGS> 54,094
<TOTAL-COSTS> 66,174
<OTHER-EXPENSES> 193
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 12,867
<INCOME-PRETAX> (4,524)
<INCOME-TAX> 0
<INCOME-CONTINUING> (4,524)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (4,524)
<EPS-PRIMARY> (0.68)
<EPS-DILUTED> (0.68)
</TABLE>
