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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, 1996
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, Suite 2000 80202
Denver, Colorado (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (303) 389-3600
Title of each class Name of each exchange on which registered
------------------------------ ---------------------------------------------
Common Stock, $.01 par value New York Stock Exchange
Convertible Preferred Stock,
$.01 par value New York Stock Exchange
Common Stock Warrants New York Stock Exchange
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 4,816,000 shares of voting stock held by
non-affiliates of the registrant, based upon the closing sale price of the
Common Stock on February 27, 1997 of $9.125 per share as reported on the New
York Stock Exchange, was $43,946,000. 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, 1997, the registrant had 18,816,432 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, 1997
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PATINA OIL & GAS CORPORATION
Annual Report on Form 10-K
December 31, 1996
PART I
ITEM 1. BUSINESS
GENERAL
Patina Oil & Gas Corporation ("Patina" or the "Company") is an independent
oil company engaged in the production, development and acquisition of oil and
gas properties. All of the Company's properties are currently located in the
Wattenberg Field ("Wattenberg" or the "Field") of Colorado's Denver-Julesburg
Basin ("D-J Basin"). Patina was incorporated in early 1996 to hold the
Wattenberg assets and operations of Snyder Oil Corporation ("SOCO") and to
facilitate the acquisition of Gerrity Oil & Gas Corporation ("GOG"). Previously,
SOCO's Wattenberg operations had been conducted through SOCO or its wholly owned
subsidiary, SOCO Wattenberg Corporation ("SWAT"). On May 2, 1996, SOCO
contributed the balance of its Wattenberg assets to SWAT and transferred all of
the shares of SWAT to the Company. Immediately thereafter, GOG merged into
another wholly owned subsidiary of the Company (the "Merger"). As a result of
these transactions, SWAT and GOG became subsidiaries of the Company. As of
December 31, 1996, SOCO owned 14,000,000 or approximately 74% of the Company's
common shares.
During 1996, the Company's revenues were $83.2 million and cash flow (net
income applicable to common stock plus exploration expense, depletion,
depreciation and amortization and deferred taxes) approximated $46.1 million.
At December 31, 1996, Patina held interests in over 3,600 wells in Wattenberg
with net proved reserves of 71.9 million barrels of oil equivalent ("MMBOE"),
approximately 70% of which were attributable to natural gas. Based on
unescalated year-end oil and gas prices, these reserves had a pre-tax present
value of $649 million.
Wattenberg, discovered in 1970, is located approximately 35 miles northeast
of Denver and stretches over Adams, Boulder and Weld Counties in Colorado. One
of the most attractive features of Wattenberg is that there are at least eight
potentially productive formations throughout the Field. Three of the
formations, the Codell, Niobrara and J-sand, are "blanket" zones in the area of
the Company's holdings, while others, such as the Sussex and Shannon are more
localized. In recent years, the Codell and Niobrara formations have been the
primary drilling objective in the Field, although the Company has also
successfully recompleted shallower formations such as the Sussex. Drilling in
Wattenberg is low risk from the perspective of encountering hydrocarbons with
better than 95% of the wells drilled being completed as producers.
Consequently, the Field's economic attractiveness is primarily dependent on
energy prices, the reservoir characteristics of the specific area of the Field
being drilled and the operator's ability to minimize capital and operating
costs.
Over the past five years, the Company, including its predecessors, has
drilled over 1,500 wells in Wattenberg. During 1996, the Company successfully
drilled 12 development wells, was in the process of drilling an additional nine
wells at year end and recompleted a further 61 wells at a total cost of
approximately $8.5 million. Given the Company's experience in drilling and
completing wells of this type, combined with operating over 3,200 wells, Patina
believes it can drill and operate its oil and gas properties in the Field at a
lower cost than its competitors. The Company exploits its oil and gas
properties through the implementation of operational
2
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improvements, workovers, multi-zone recompletions, refracs and the drilling of
new development wells. Furthermore, because virtually all of the wells in which
it holds an interest lie within a 40 mile radius, Patina believes it is one of
the most efficient oil and gas producers in the United States.
The Company's oil and 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. Gas production from Wattenberg is processed in order to
recover natural gas liquids which are comprised of ethane, propane and
butane/gasoline mix. The liquids are then sold separately from the residue gas
but included in the Company's gas revenues to determine its average price per
Mcf. The Company utilizes two separate methodologies to gather, process and
market its natural gas production. Approximately 30% of the Company's gas
production is sold to PanEnergy Field Services, Inc. ("PanEnergy") under several
separate wellhead agreements. Pursuant to these agreements, the Company
receives a fixed percentage of the proceeds of PanEnergy's sale of residue gas
and natural gas liquids. Substantially all of the Company's remaining gas
production is dedicated for gathering to either PanEnergy or KN Front Range
Gathering Company ("KN") and is then processed at plants owned by PanEnergy,
Amoco Production Company ("Amoco") or Vessels Gas Processing, Inc. ("Vessels").
Under this methodology, 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 under
transportation contracts to midwest markets. Natural gas liquids are sold by
the processor and the Company receives payment net of applicable processing
fees.
As of December 31, 1996, the Company had net proved reserves of 22.5
million barrels of oil and 296.7 Bcf of gas attributable to interests in 3,602
wells, 728 proved undeveloped locations and 605 proved behind pipe
recompletions. This inventory of undeveloped locations and recompletions
provides the ability to expand development activities should drilling and
completion technologies improve or the recent recovery in Rocky Mountain natural
gas prices continue. A significant portion of the Company's 728 proved
undeveloped locations are projected to provide rates of return below the level
judged attractive by management based on projected commodity prices and reserve
recoveries. While the sharp increase in oil and gas prices during the fall of
1996 through early 1997 provided substantial encouragement, the Company will
continue to evaluate its drilling results and assess trends in energy prices in
the coming months. The Company, at least for the present, expects to limit its
capital expenditures on existing properties to approximately $14 million. The
capital program is expected to entail the drilling of 35 wells and 75
recompletions, as well as the expansion of recently initiated refrac, workover
and tubing installation efforts to enhance production. As a result, management
believes that funds generated from operations will permit a continued paydown of
debt, additional security repurchases or the aggressive pursuit of further
consolidation or acquisition opportunities. Given Patina's low cost structure
and extensive experience in drilling and efficiently operating large numbers of
wells, management believes the Company is well positioned to pursue further
consolidation in Wattenberg and to take advantage of similar opportunities in
other basins.
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PRODUCTION, REVENUE AND PRICE HISTORY
The following table sets forth information regarding net production of
crude oil and natural gas, revenues and expenses attributable to such
production and certain price and cost information for each of the years in the
five year period ended December 31, 1996. Note: The financial and operating
information reflect the merger of GOG into a subsidiary of the Company in May
1996.
<TABLE>
<CAPTION>
December 31,
-------------------------------------------
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
(Dollars in thousands, except prices and
per barrel equivalent information)
<S> <C> <C> <C> <C> <C>
Production
Oil (Mbbl) 795 1,224 1,829 1,342 1,688
Gas (Mmcf) 12,867 21,706 23,893 20,981 23,947
MBOE (a) 2,940 4,842 5,812 4,839 5,679
Revenues
Oil $15,154 $19,429 $27,151 $22,049 $34,541
Gas (b) 23,419 45,125 40,598 28,024 47,644
------- ------- ------- ------- -------
Subtotal 38,573 64,554 67,749 50,073 82,185
Other 125 311 73 29 1,003
------- ------- ------- ------- -------
Total 38,698 64,865 67,822 50,102 83,188
------- ------- ------- ------- -------
Operating expenses
Production (C) 8,272 8,927 8,110 8,867 14,519
Exploration 17 573 784 416 224
------- ------- ------- ------- -------
8,289 9,500 8,894 9,283 14,743
------- ------- ------- ------- -------
Direct operating margin $30,409 $55,365 $58,928 $40,819 $68,445
======= ======= ======= ======= =======
Average sales price (d)
Oil (Bbl) $ 19.06 $ 15.87 $ 14.84 $ 16.43 $ 20.47
Gas (Mcf) (b) 1.82 2.08 1.70 1.34 1.99
BOE (a) 13.12 13.33 11.66 10.35 14.47
Average production expense/BOE 2.81 1.84 1.40 1.83 2.56
Average production margin/BOE 10.31 11.49 10.26 8.52 11.92
</TABLE>
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(a) Gas production is converted to oil equivalents at the rate of six Mcf per
barrel.
(b) Sales of natural gas liquids are included in gas revenues.
(c) Production expense is comprised of lease operating expenses and production
taxes.
(d) The Company estimates that its composite net wellhead prices at December 31,
1996 were approximately $3.70 per Mcf of gas and $25.20 per barrel of oil.
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DRILLING RESULTS
The following table sets forth information with respect to wells drilled 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>
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Productive
Gross............................ 350.0 25.0 12.0
Net.............................. 305.6 24.1 12.0
Dry
Gross............................ 8.0 0.0 0.0
Net.............................. 7.9 0.0 0.0
</TABLE>
At December 31, 1996, nine gross (eight net) development wells were in
progress.
CUSTOMERS AND MARKETING
The Company's oil and 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 gas can be affected by a number of
factors that are beyond the Company's control and whose future effect 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 from the residue gas
which is sold to utilities, independent marketers and end users through both
intrastate and interstate pipelines. The Company utilizes two separate
methodologies to gather, process and market its natural gas production.
Approximately 30% of the Company's gas production is sold to PanEnergy 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 natural gas liquids by PanEnergy. Substantially all of
the Company's remaining gas production is dedicated for gathering to either
PanEnergy or KN and is then processed at plants owned by PanEnergy, Amoco or
Vessels. Under this methodology, 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. Natural gas liquids are
sold by the processor and the Company receives payment net of applicable
processing fees.
A portion of gas gathered by KN is processed by Amoco at the Wattenberg
Processing Plant under a favorable contract that not only provides payment for a
percentage of the natural gas liquids stripped from the 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.
As a part of an agreement entered into with Vessels, the Company will deliver an
average of 4,000 MMBtu per day to the Vessels' Ft. Lupton gas processing
facility through November 30, 1997 at competitive processing terms.
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 crude oil and is adjusted for
transportation costs and quality. Amoco has the right to purchase oil produced
from certain properties owned by the Company.
5
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COMPETITION
The oil and gas industry is highly competitive in all its phases.
Competition is particularly intense with respect to the acquisition of producing
properties. There is also competition for the acquisition of oil and gas
leases, in the hiring of experienced personnel and from other industries in
supplying alternative sources of energy.
Competitors in acquisitions, exploration, development and production
include the major oil companies in addition to numerous independent oil
companies, individual proprietors, drilling and acquisition programs and others.
Many of these competitors possess financial and personnel resources
substantially in excess of those available to the Company. Such competitors may
be able to pay more for desirable leases and to evaluate, bid for and purchase a
greater number of properties than the financial or personnel resources of the
Company permit. 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 exploration and development.
TITLE TO PROPERTIES
Title to the Company's oil and gas properties is subject to royalty,
overriding royalty, carried and other similar interests and contractual
arrangements customary in the oil and 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 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 on a tract, 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. Oil and gas industry legislation and administrative regulations
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 gas industry, some of which carry substantial
penalties for failure to comply. The regulatory burden on the oil and 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. On the other hand, these laws and regulations also establish the
framework in which the government sanctions and approves the conduct of the
Company's business activities, and can operate to the Company's benefit.
In the past, the federal government has regulated the prices at which oil
and gas could be sold. Prices of oil and 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 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 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.
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State statutes govern exploration and production operations, conservation
of oil and gas resources, protection of the correlative rights of oil and 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 most of the Company's properties are located, amended its
statute concerning oil and gas development in 1994 to provide the state's Oil
and Gas Conservation Commission with enhanced authority to regulate oil and gas
activities to protect public health, safety and welfare, including the
environment. Several rulemakings pursuant to these statutory changes have been
undertaken by the Commission 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 oil and gas operations of
the Company, as the Commission 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 oil and gas operations in the future.
In Colorado, a number of city and county governments have enacted oil and
gas regulations. These ordinances increase the involvement of local governments
in the permitting of oil and 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 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 crude 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, contaminated soil and produced water generated from the Company's
operations. There can be no assurance, however, 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 gas industry in general.
7
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DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information about the executive
officers and directors of Patina:
<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<S> <C> <C>
Thomas J. Edelman.................. 46 Chairman of the Board, President and
Chief Executive Officer
Brian J. Cree...................... 33 Executive Vice President and
Chief Operating Officer, Director
Keith M. Crouch.................... 50 Senior Vice President and General
Counsel
Ronald E. Dashner.................. 44 Senior Vice President, Operations
David J. Kornder................... 36 Vice President and Chief Financial
Officer
David R. Macosko................... 35 Vice President
Terry L. Ruby...................... 38 Vice President
David W. Siple..................... 37 Vice President
Rodney L. Waller................... 47 Vice President
Kenneth A. Wonstolen............... 45 Vice President
Robert J. Clark.................... 52 Director
Jay W. Decker...................... 44 Director
William J. Johnson................. 61 Director
Alexander P. Lynch................. 44 Director
John C. Snyder..................... 54 Director
</TABLE>
THOMAS J. EDELMAN has served as Chairman of the Board, President and Chief
Executive Officer of Patina since its formation. He co-founded SOCO and was the
President and a director of SOCO from 1981 through February 1997. Prior to
1981, he was a Vice President of The First Boston Corporation. From 1975
through 1980, Mr. Edelman was 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 a director of Petroleum Heat & Power
Co., a Connecticut based fuel oil distributor, and its affiliate Star Gas
Corporation, and of Paradise Music & Entertainment, Inc. Mr. Edelman also
serves as Chairman of Lomak Petroleum, Inc.
BRIAN J. CREE has served as Executive Vice President, Chief Operating
Officer and Director of Patina since May 1996. Prior to the Merger, he served
as Chief Operating Officer and Director of GOG since 1993. From 1992 to 1993,
Mr. Cree served as Senior Vice President-Operations and Chief Accounting Officer
of GOG. Prior to that, Mr. Cree served as Vice President and Treasurer of GOG
since its inception in 1990. Mr. Cree served as Vice President and Treasurer of
The Robert Gerrity Company from 1989 to 1990 and served in various accounting
capacities with that company from 1987 to 1990. Prior to that, Mr. Cree was
employed as an accountant at the public accounting firm of Deloitte, Haskins &
Sells.
8
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KEITH M. CROUCH has served as Senior Vice President and General Counsel of
Patina since May 1996. Prior to the Merger, he was a Vice President of GOG
commencing in 1993 and was appointed a Director in 1994. From 1992 to 1993, Mr.
Crouch served as Corporate Counsel to GOG. Mr. Crouch was responsible for the
legal aspects of GOG's oil and gas operations. Prior to joining GOG, Mr. Crouch
was in private practice with Pendleton & Sabian, P.C. since 1983.
RONALD E. DASHNER has served as Senior Vice President, Operations of Patina
since its formation. Prior to the Merger, he served as Vice President--Rockies
Group--Rocky Mountain Division of SOCO in late 1995. Prior to that he was
Operations Manager of SOCO's D-J Basin/Greater Green River Unit. He joined SOCO
in 1994. From 1991 to 1994, Mr. Dashner was Onshore Gulf Coast Operations
Manager for Enron Oil & Gas Company. From 1980 through 1990, Mr. Dashner held
various positions with TXO Production Corp., including Drilling & Production
Manager--Rocky Mountain District and Assistant District Manager--East Texas
District. From 1978 to 1980, he was employed by Davis Oil Company in Engineering
and Operations. From 1975 to 1978, he was employed by Chevron in the Drilling,
Production and Construction Department. Mr. Dashner received his Bachelor of
Science Degree in Civil Engineering from Colorado State University in 1974.
DAVID J. KORNDER has served as Vice President and Chief Financial Officer
of Patina since May 1996. Prior to the Merger, he served as a Vice President-
Finance of GOG from 1993. Mr. Kornder is responsible for Patina's financial
reporting, planning, cash management, budgeting, and acquisition evaluation.
Prior to joining GOG, Mr. Kornder was an Assistant Vice President for Gillett
Group Management, Inc. where he was responsible for that firm's financial
planning and budgeting from 1989 to 1993. Prior to that, Mr. Kornder was an
accountant with the independent accounting firm of Deloitte & Touche for five
years.
DAVID R. MACOSKO has served as a Vice President of Patina since May 1996.
Prior to the Merger, he served as a Vice President of GOG from 1994. From 1992
to 1994, Mr. Macosko served as Operations Coordinator and Manager of Accounts
Payable with GOG. Mr. Macosko is responsible for Patina's daily business
operations in the D-J Basin. Mr. Macosko received a bachelor of science degree
in accounting from West Virginia University. Mr. Macosko has been with Patina
and its predecessor entity for seven years serving in various operational,
accounting and analyst positions. Mr. Macosko has eleven years of experience in
the oil and gas industry.
TERRY L. RUBY has served as a Vice President of Patina since May 1996.
Prior to the Merger, he served as a Vice President of GOG from 1995, and was in
charge of land matters for GOG. His current responsibilities include
management of land assets, acquisition and divestiture. Mr. Ruby has been with
Patina and its predecessors's land department from 1992. Previously, Mr. Ruby
worked with Apache Corporation from 1990 to 1992, and with Baker Exploration
Company from 1982 to 1989. Mr. Ruby holds a B.S. in Minerals Land Management
and an M.B.A.
DAVID W. SIPLE has served as a Vice President of Patina since its
formation. Prior to the Merger, he served as a Land Manager with SOCO from
1995. He served in various capacities in the Land Department since joining
SOCO in 1994. From 1990 through 1994, Mr. Siple was the Land Manager of GOG.
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
Mineral Land Management from the University of Colorado.
RODNEY L. WALLER has served as a Vice President of Patina since its
formation. He also serves as Vice President--Special Projects of SOCO. He
joined SOCO in 1977. Previously, Mr. Waller was employed by Arthur Andersen &
Co. Mr. Waller received his Bachelor of Arts Degree from Harding University.
9
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KENNETH A. WONSTOLEN has served as a Vice President of Patina since May
1996. Prior to the Merger, he served as a Vice President of GOG from 1995, and
was in charge of environmental and public affairs. His responsibilities at
Patina include environmental, health and safety matters, as well as government,
community, media and investor relations. Mr. Wonstolen joined GOG in 1992 as
Corporate Counsel after having been in the private practice of law since 1990.
Mr. Wonstolen was Executive Director and General Counsel of the Independent
Petroleum Association of Mountain States from 1985 to 1990. Mr. Wonstolen holds
B.A. and J.D. degrees, as well as a Master of Environmental Policy and
Management degree.
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 Oil Company. 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
Snyder Oil Corporation. 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 affiliates NICOR Exploration, Norther Illinois Gas and
Reliance Pipeline Company. Mr. Clark received his Bachelor of Science Degree
from Bradley University and his Masters Degree in Business Administration from
Northern Illinois University.
JAY W. DECKER has served as a Director of the Company since May 1996. Mr.
Decker has 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 and a Director of the Children's Museum of Denver.
WILLIAM J. JOHNSON has served as a Director of the Company since May 1996.
Mr. Johnson, a Director of SOCO since 1994, is a private consultant to the oil
and gas industry and is President and a Director of JonLoc Inc., an oil and gas
company of which he and his family are the sole shareholders. From 1991 to
1994, Mr. Johnson was President, Chief Operating Officer and a director of
Apache Corporation. Previously, he was a Director, President and Chief
Executive Officer of Tex/Con Oil and Gas, where he served from 1989 to 1991.
Prior thereto, Mr. Johnson served in various capacities with major oil
companies, including director and President USA of BP Exploration Company,
President of Standard Oil Production Company and Senior Vice President of The
Standard Oil Company. Mr. Johnson received a Bachelor of Science degree in
Petroleum Geology from Mississippi State University and completed the Advanced
Management Course at the University of Houston. Mr. Johnson serves as a Director
of Tesoro Petroleum, a refining and marketing company with interests in oil and
gas production and marine services and Camco International, an oilfield
manufacturing company. Mr. Johnson also serves on the advisory board of Texas
Commerce Bank, Houston.
10
<PAGE>
ALEXANDER P. LYNCH has served as a Director of the Company since May 1996.
Mr. Lynch has been Co-President and Co-Chief Executive Officer of The Bridgeford
Group, a financial advisory firm, since 1995. 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 also serves as a Director of Lincoln Snacks Company and Illinois
Central Corporation. Mr. Lynch received his Bachelor of Arts Degree from the
University of Pennsylvania and an M.B.A. from the Wharton School of Business at
the University of Pennsylvania.
JOHN C. SNYDER has served as a Director of the Company since its formation.
Mr. Snyder, the Chairman, President and Chief Executive Officer of SOCO, founded
one of SOCO's predecessors in 1978. From 1973 to 1977, Mr. Snyder was an
independent oil operator in Texas and Oklahoma. Previously, he was a director
and the Executive Vice President of May Petroleum Inc. where he served from 1971
to 1973. Mr. Snyder was the first president of Canadian-American Resources
Fund, Inc., which he founded in 1969. From 1964 to 1966, Mr. Snyder was
employed by Humble Oil and Refining Company (currently Exxon Co., USA) as a
petroleum engineer. Mr. Snyder received his Bachelor of Science Degree in
Petroleum Engineering from the University of Oklahoma and his Masters Degree in
Business Administration from the Harvard University Graduate School of Business
Administration. Mr. Snyder is a director of the Community Enrichment Center,
Inc., Forth Worth, Texas.
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 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 at least 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
<TABLE>
<CAPTION>
Approximate
Depth
Formation (feet)
--------- ----
<S> <C>
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
</TABLE>
11
<PAGE>
At December 31, 1996, the Company had working interests in 3,407 gross
(3,084 net) producing oil and gas wells in the D-J Basin and held royalty
interests in 195 producing wells. As of December 31, 1996, estimated proved
reserves totaled 71.9 million BOE, including 22.5 million barrels of oil and
296.7 Bcf of gas.
PROVED RESERVES
The following table sets forth estimated year end net proved reserves for
the three years ended December 31, 1996.
<TABLE>
<CAPTION>
December 31,
-------------------------
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
Crude oil and liquids (Mbbl)
Developed......................... 8,832 6,955 15,799
Undeveloped....................... 3,386 466 6,676
------- ------- -------
Total........................ 12,218 7,421 22,475
======= ======= =======
Natural gas (Mmcf)
Developed......................... 147,869 133,088 242,777
Undeveloped....................... 30,834 5,769 53,882
------- ------- -------
Total........................ 178,703 138,857 296,659
======= ======= =======
Total MBOE............................. 42,002 30,564 71,918
======= ======= =======
</TABLE>
The following table sets forth pretax future net revenues from the
production of proved reserves and the Pretax PW 10% Value of such revenues, net
of estimated future capital costs, including estimated costs of $14.0 million in
1997.
<TABLE>
<CAPTION>
December 31, 1996
-----------------------------------
Developed Undeveloped Total
--------- ------------ ----------
(In thousands)
<S> <C> <C> <C>
1997.................................... $117,410 $ (2,154) $ 115,256
1998.................................... 101,637 (2,455) 99,182
1999.................................... 92,397 4,235 96,632
Remainder............................... 668,820 188,977 857,797
-------- -------- ----------
Total................................ $980,264 $188,603 $1,168,867
======== ======== ==========
Pretax PW 10% Value (a)................. $582,408 $ 66,389 $ 648,797
======== ======== ==========
</TABLE>
__________________
(a) The after tax PW 10% value of the proved reserves totaled $499.9 million at
year end 1996.
12
<PAGE>
The quantities and values in the preceding tables are based on prices in
effect at December 31, 1996 which averaged $25.20 per barrel of oil and $3.70
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 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 oil and gas prices in effect on December 31, 1996. Those prices
were significantly higher than the prices that prevailed throughout most of 1996
and since year end, prices have fallen from year end levels. The value of the
Company's assets is in part dependent on the prices the Company receives for oil
and 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 gas reserve engineering must be recognized as a subjective
process of estimating underground accumulations of oil and 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 gas that are
ultimately recovered.
All of the proved reserves at year-end were estimated by Netherland, Sewell
& Associates Inc. ("NSAI"). No estimates of the Company's reserves comparable to
those included herein have been included in reports to any federal agency other
than the SEC.
13
<PAGE>
PRODUCING WELLS
The following table sets forth certain information at December 31, 1996
relating to the producing wells in which the Company owned a working interest.
The Company also held royalty interests in 195 producing wells. Wells are
classified as oil or gas wells according to their predominant production stream.
<TABLE>
<CAPTION>
Average
Principal Gross Net Working
Production Stream Wells Wells Interest
----------------- ----- ----- --------
<S> <C> <C> <C>
Crude oil and liquids............. 2,794 2,571 92%
Natural gas....................... 613 513 84%
----- -----
Total.......................... 3,407 3,084 91%
===== =====
</TABLE>
ACREAGE
The following table sets forth certain information at December 31, 1996
relating to Wattenberg 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. The Company also has approximately 60,000 gross undeveloped
acres in the Uinta Basin of Utah. The Company currently plans to divest of this
acreage.
Gross Net
----- ---
Developed........................... 177,548 137,500
======= =======
Undeveloped......................... 160,621 141,713
======= =======
14
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
In August 1995, SOCO was sued in the United States District Court of
Colorado by plaintiffs purporting to represent all persons who, at any time
since January 1, 1960, have had agreements providing for royalties from gas
production in Colorado to be paid by SOCO under various lease provisions. In
January 1997, the judge denied the plaintiffs' motion for class certification.
Substantially all liability under this suit was assumed by the Company upon its
formation. In January 1996, GOG was also sued in a similar but separate action
filed in the Colorado State Court. The plaintiffs, in both suits, allege that
unspecified "post-production" costs incurred prior to calculating royalty
payments were deducted in breach of the relevant lease provisions and that this
fact was fraudulently concealed. The plaintiffs seek unspecified compensatory
and punitive damages and a declaratory judgment prohibiting the deduction of
post-production costs prior to calculating royalties paid to the plaintiffs. The
Company believes that costs deducted in calculating royalties are and have been
proper under the relevant lease provisions, and they intend to defend these and
any similar suits vigorously. At this time, the Company is unable to estimate
the range of potential loss, if any. 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 impact on results for that period.
In March 1996, a complaint was filed in the Court of Chancery for the State
of Delaware against GOG 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 the defendants from consummating a merger
which will benefit the holders of GOG's common stock at the expense of the
holders of the Preferred and (b) to obtain a declaration that the terms of the
proposed merger constitute a breach of the contractual rights of the Preferred."
The complaint seeks, among other things, certification as a class action on
behalf of all holders of GOG'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 Merger and money damages.
Defendants believe that the complaint is without merit and intend to vigorously
defend against the 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 impact 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
No matters were submitted for a vote of security holders during the fourth
quarter of 1996.
15
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER
MATTERS
The Patina Common Stock, the Patina Warrants and the Patina Preferred Stock
are listed on the New York Stock Exchange ("NYSE") under the symbols "POG",
"POGWT" and "POGPr", respectively. Such listings became effective on May 3,
1996. The following table sets forth, for the period since such listing became
effective, the range of high and low closing prices as reported on the NYSE
Composite Tape.
<TABLE>
<CAPTION>
1996
--------------------------------------------------------
Common Stock Warrants Preferred Stock
------------ -------- ----------------
High Low High Low High Low
---- --- ---- --- ---- ---
<S> <C> <C> <C> <C> <C> <C>
Second Quarter (from May 3, 1996) $8 1/4 $6 1/8 $2 3/8 $1 1/4 $24 1/2 $22 1/4
Third Quarter 7 3/8 6 3/4 1 5/8 1 26 23
Fourth Quarter 9 1/2 7 2 3/8 1 30 1/4 25 1/2
</TABLE>
On February 27, 1997, the closing prices of the Common Stock, Warrants and
the Preferred Stock were $9.125, $2.00 and $30.00, respectively. As of
December 31, 1996, there were approximately 110 holders of record of the common
stock and 18.9 million shares outstanding.
Dividend Policy. The Board of Directors of the Company have not declared
cash dividends on its Common Stock and does not currently plan to do so. Under
the terms of its current Bank Credit Agreement, the Company is restricted in its
ability to declare dividends on its Common Stock.
16
<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, 1996. Future results may differ substantially from historical results
because of changes in oil and gas prices, normal production 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.
Note: The financial statements reflect the merger of GOG into a subsidiary of
the Company in May 1996.
<TABLE>
<CAPTION>
As of or for the Year Ended December 31,
-----------------------------------------------------
1992 1993 1994 1995 1996
---- ---- ---- ---- ----
(In thousands except per share data)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA
Revenues........................................................ $ 38,698 $ 64,865 $ 67,822 $ 50,102 $ 83,188
Expenses
Direct operating.............................................. 8,272 8,927 8,110 8,867 14,519
Exploration................................................... 17 573 784 416 224
General and administrative.................................... 6,115 6,982 7,484 5,974 6,151
Interest and other............................................ 1,771 2,362 3,869 5,476 14,304
Depletion, depreciation and amortization...................... 11,949 25,190 43,036 32,591 44,822
-------- -------- -------- -------- --------
Total expenses............................................... 28,124 44,034 63,283 53,324 80,020
-------- -------- -------- -------- --------
Income (loss) before taxes...................................... 10,574 20,831 4,539 (3,222) 3,168
Provision (benefit) for income taxes............................ 3,701 7,291 1,589 (1,128) (394)
-------- -------- -------- -------- --------
Net income (loss)............................................... $ 6,873 $ 13,540 $ 2,950 $ (2,094) $ 3,562
======== ======== ======== ======== ========
Per common share............................................. $.49 $.97 $.21 $(.15) $.08
======== ======== ======== ======== ========
Weighted Average Shares Outstanding............................. 14,000 14,000 14,000 14,000 17,796
BALANCE SHEET DATA
Current assets............................................... $ 5,343 $ 14,725 $ 11,083 $ 9,611 $ 27,587
Oil and gas properties, net.................................. 106,251 181,170 234,821 214,594 398,640
Total assets................................................. 113,064 195,895 246,686 224,521 430,233
Current liabilities.......................................... 16,740 23,735 23,838 9,611 26,572
Debt......................................................... 35,537 60,857 79,333 75,000 197,594
Stockholders' equity......................................... 51,278 92,865 115,846 113,663 196,236
CASH FLOW DATA
Net cash provided by operations.............................. $ 27,710 $ 38,882 $ 47,690 $ 18,407 $ 52,996
Net cash used by investing................................... (47,189) (97,573) (96,378) (21,060) (9,796)
Net cash realized (used) by financing........................ 19,479 58,691 48,688 2,653 (38,047)
RATIO OF EARNINGS TO COMBINED FIXED
CHARGES AND PREFERRED DIVIDENDS.............................. 6.97 9.82 2.17 0.40 1.08
</TABLE>
17
<PAGE>
The following table sets forth unaudited summary financial results on a
quarterly basis for the two most recent years.
<TABLE>
<CAPTION>
1995
--------------------------------------------
First Second Third Fourth
----- ------ ----- ------
<S> <C> <C> <C> <C>
(In thousands, except per share data)
Revenues..................................................... $14,287 $12,890 $11,423 $11,502
Direct operating expenses.................................... 2,263 2,503 2,201 1,900
Depletion, depreciation and amortization..................... 8,620 8,331 7,372 8,268
Net income (loss)............................................ (215) (428) (497) (954)
Per common share........................................... (.01) (.03) (.04) (.07)
1996
--------------------------------------------
First Second Third Fourth
----- ------ ----- ------
Revenues..................................................... $10,654 $19,456 $23,097 $29,981
Direct operating expenses.................................... 1,955 3,446 4,161 4,957
Depletion, depreciation and amortization..................... 6,967 11,756 13,232 12,867
Net income (loss)............................................ (732) (1,129) (669) 6,092
Per common share........................................... (.05) (.10) (.07) .28
</TABLE>
18
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
On May 2, 1996, GOG was merged into a wholly owned subsidiary of the
Company (the "Merger"). This transaction was accounted for as a purchase of GOG.
Accordingly, the results of operations since the Merger reflect the impact of
the purchase.
Comparison of 1996 results to 1995. Total revenues for 1996 were $83.2
million, an increase of $33.1 million from 1995. The amount represents an
increase of 66% as compared to the prior year period. The revenue increase is
due to the effect of the Merger and improved product prices in 1996. Net income
for 1996 was $3.6 million compared to a net loss of $2.1 million in 1995. The
increase in net income is primarily attributed to a significant increase in
average oil and gas prices received, offset by an increase in interest expense
and depletion, depreciation and amortization.
Oil and gas sales less direct operating expenses for 1996 were $67.7
million, a 64% increase from the prior year period. Average daily production in
1996 was 4,612 barrels and 65.4 Mmcf, or (15,515 barrels of oil equivalent
("BOE"), increases of 26% and 14%, respectively. The production increases
resulted solely from the Merger. Exclusive of the Merger, production continued
to decline due to the Company's reduced capital expenditures and expected
production declines on the large number of wells drilled and completed in 1994
and early 1995. There were 88 wells placed on production in 1995 compared to 12
wells in 1996. In the future, while production is not expected to continue to
decline at the current rate, a decrease is expected unless development drilling
activity is substantially increased or additional acquisitions are consummated.
The decision to increase development drilling is heavily dependent on the
commodity prices being received for production.
Average oil prices increased to $20.47 per barrel compared to $16.43
received in 1995. Average natural gas prices increased from $1.34 per Mcf in
1995 to $1.99 in 1996. The increase in natural gas prices was primarily the
result of prior year production being marketed under term arrangements which
were based on Rocky Mountain region pricing (which was depressed) whereas the
1996 production benefitted from several factors. A portion of these term
arrangements expired during 1996 which allowed the production to be sold at
local spot prices which had increased as a result of higher demand and declining
production in the D-J Basin. In addition, enhanced marketing efforts combined
with higher natural gas liquids prices contributed to the overall price
increase. Direct operating expenses increased to $2.56 per BOE compared to
$1.83 in 1995. The increase is primarily attributed to the Company's focus on
enhancing production through performing well workovers on existing properties
and the overall increase in production taxes as a result of the higher average
oil and gas prices.
19
<PAGE>
General and administrative expenses, net of third party reimbursements, for
1996 were $6.2 million, a 3% increase over 1995. The increase is the result of
the Merger partially offset by reductions in allocated costs from SOCO during
the first four months of 1996. Prior to the Merger, the Company did not have
its own employees. Employees and certain office space and furniture, fixtures
and equipment were provided by SOCO. SOCO allocated general and administrative
expenses based on estimates of expenditures incurred on behalf of the Company.
Interest and other expense was $14.3 million compared to $5.5 million in
1995. Interest expense increased as a result of higher average outstanding debt
levels as a result of the Merger. The Company's average interest rate climbed
to 9.3% compared to 7.0% in 1995. This increase is due primarily to the
Subordinated Notes.
Depletion, depreciation and amortization expense for 1996 totaled $44.8
million, an increase of $12.2 million, or 38% over 1995. The increase resulted
from the higher production and an increased depletion, depreciation and
amortization rate of $7.89 per BOE compared to $6.74 in 1995. The primary cause
for the increased rate was a downward revision in reserve quantities due to
proved undeveloped reserves being classified as uneconomic at year end 1995
prices and the inclusion of the amortization of a noncompete agreement entered
into in conjunction with the Merger. The amortization of the noncompete
agreement of $2.6 million in 1996 resulted in an increase of $.46 in the
depletion, depreciation and amortization rate per BOE.
Comparison of 1995 results to 1994. Total revenues in 1995 were $50.1
million as compared to $67.8 million in 1994. The 26% decrease was due to both
a drop in production (17%) and in average prices received (11%). The net loss
for 1995 was $2.1 million compared to net income of $3.0 million in 1994. The
decrease was primarily due to the drop in production and average prices
received, higher direct operating expenses and increased interest expense due to
increased average debt payable to parent offset somewhat by a lower depletion
rate.
Average daily production during 1995 was 3,677 barrels and 57.5 Mmcf
(13,257 BOE), a decrease of 27% for oil and 12% for gas, as compared to 1994.
The production declines resulted primarily from the Company's decision to reduce
drilling in 1995 due to the continued decline in gas prices subsequent to year
end 1994. During 1995, the Company placed an additional 88 wells on production
compared to 360 wells during 1994. The direct operating margin (revenues less
direct operating costs) for 1995 was $41.2 million, a 31% decrease from 1994.
Average oil prices increased 11% to $16.43 per barrel. However, that modest
increase was more than offset by the continued sharp decline in gas prices. The
average gas price for 1995 was only $1.34 per Mcf, a 21% decrease from 1994.
Direct operating expenses per equivalent barrel also increased to $1.83 from
$1.40 in 1994 due to decreasing total production with a higher number of wells
and higher well servicing costs in 1995.
General and administrative expenses, net of reimbursements, were $6.0
million in 1995 as compared to $7.5 million in 1994. The Company did not have
its own employees. Employees and certain office space and furniture, fixtures
and equipment have been provided by SOCO. SOCO has allocated general and
administrative expenses based on estimates of actual expenditures incurred on
behalf of Patina. The general and administrative expenses in 1995 were $1.5
million lower than 1994, reflecting the lower overhead associated with the
reduced drilling activity.
20
<PAGE>
Interest paid to parent and other expense was $5.5 million in 1995 as
compared to $3.9 million in 1994. Interest expense represents interest on debt
payable to SOCO. Prior to the Merger, SOCO financed all of the Company's
activities. A portion of such financing was considered to be an investment by
SOCO in the Company and, accordingly, no interest was charged by SOCO to Patina
for this capital. The remaining portion of such financing was considered to be
debt payable to SOCO with interest charged to the Company at a rate which
approximated the average interest rate being paid by SOCO under its revolving
credit facility. The increase in interest expense was primarily due to an
increase in interest rates from 5.5% to 7%.
Depletion, depreciation and amortization expense for 1995 decreased 24%
from 1994. The decrease was primarily attributable to the decreases in
production and a $2.1 million greater impairment in 1994.
DEVELOPMENT, ACQUISITION AND EXPLORATION
During 1996, the Company incurred $226.9 million in capital expenditures.
Of this amount, $218.4 million related to the acquisition of GOG by the issuance
of stock and assumption of debt by the Company. Capital expenditures, exclusive
of acquisitions, totaled only $8.5 million as the Company has continued to limit
its development activity based on Rocky Mountain natural gas prices. The
Company anticipates incurring development capital expenditures of approximately
$14 million during 1997.
FINANCIAL CONDITION AND CAPITAL RESOURCES
At December 31, 1996, the Company had total assets of $430.2 million.
Total capitalization was $393.8 million, of which 50% was represented by
stockholders' equity, 24% by senior debt and 26% by subordinated debt. During
1996, net cash provided by operations was $53.0 million, as compared to $18.4
million in 1995. As of December 31, 1996, there were no significant commitments
for capital expenditures. The Company anticipates that 1997 expenditures for
development drilling and recompletion activity will approximate $14 million,
which will allow for a reduction of indebtedness, provide funds to pursue
acquisitions, or additional security repurchases. 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 using internal
cash flow, proceeds from asset sales and its bank credit facilities. In
addition, joint ventures or future public and private offerings of debt or
equity securities may be utilized. Due to restrictions outlined in GOG's
various credit agreements, cash generated by GOG may need to be retained by GOG
and might therefore not be available to fund the Company's other operations.
Prior to the Merger, SOCO financed all of the Company's activities. A
portion of such financing was considered to be an investment by parent in the
Company with the remaining portion being considered debt payable to SOCO. In
conjunction with the Merger, the $75 million debt payable to SOCO was paid in
full and the Company does not expect SOCO to provide any additional funding.
Simultaneously with the Merger, the Company entered into a bank credit
agreement. The agreement consists of (i) a facility provided to the Company and
SOCO Wattenberg (the "Company Facility") and (ii) a facility provided to GOG
(the "GOG Facility").
21
<PAGE>
The Company Facility is a revolving credit facility in an aggregate amount
up to $102 million. The amount available for borrowing under the Company
Facility is limited to a semiannually adjusted borrowing base that equalled $85
million at December 31, 1996. At December 31, 1996, $67.5 million was
outstanding under the Company Facility. Prior to September 30, 1996, the
Company had a term loan facility in an amount up to $87 million. This term loan
facility was available to fund GOG's repurchases of the Subordinated Notes. At
September 30, 1996, the Company had not utilized the term loan facility and it
was canceled.
The GOG Facility is a revolving credit facility in an aggregate amount up
to $51 million. The amount available for borrowing under the GOG Facility is
limited to a semiannually adjusted borrowing base that equalled $35 million at
December 31, 1996. At December 31, 1996, $27.0 million was outstanding under
the GOG Facility. The GOG Facility was used primarily to refinance GOG's
previous bank credit facility and pay costs associated with the Merger.
As of February 25, 1997, the Company had approximately $185.1 million of
debt outstanding, consisting of $82.0 million of senior debt and $103.1 million
of subordinated notes.
The bank 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 bank 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 clauses; issuance of securities; and commodity
hedging.
The Company from time to time enters into arrangements to monetize its
Section 29 tax credits. These arrangements result in revenue increases of
approximately $.40 per Mcf on production volumes from qualified Section 29
properties. As a result of such arrangements, the Company recognized additional
gas revenues of $2.0 million and $1.5 million during 1995 and 1996,
respectively. These arrangements are expected to increase revenues through
2002.
The Company believes that its capital resources are adequate to meet the
requirements of its business. However, future cash flows are subject to a number
of variables including the level of production and oil and 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.
22
<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 gas industry result in independent price
fluctuations. Over the past five years, significant fluctuations have occurred
in oil and gas prices. Although it is particularly difficult to estimate future
prices of oil and gas, price fluctuations have had, and will continue to have, a
material effect on the Company.
The following table indicates the average oil and gas prices received over
the last five years and highlights the price fluctuations by quarter for 1995
and 1996. Average price computations exclude contract settlements and other
nonrecurring items to provide comparability. Average prices per equivalent
barrel indicate the composite impact of changes in oil and gas prices. Natural
gas production is converted to oil equivalents at the rate of six Mcf per
barrel.
<TABLE>
<CAPTION>
Average Prices
----------------------------------
Natural Equivalent
Crude Oil Gas Barrels
--------- ------- ----------
(Per Bbl) (Per Mcf) (Per BOE)
<S> <C> <C> <C>
Annual
------
1992 $19.06 $1.82 $13.12
1993 15.87 2.08 13.33
1994 14.84 1.70 11.66
1995 16.43 1.34 10.35
1996 20.47 1.99 14.47
Quarterly
---------
1995
----
First $16.37 $1.37 $10.51
Second 17.24 1.19 9.84
Third 15.90 1.27 9.91
Fourth 16.12 1.55 11.27
1996
----
First $18.31 $1.55 $11.73
Second 20.24 1.60 12.75
Third 19.92 1.83 13.72
Fourth 22.35 2.78 18.40
</TABLE>
In December 1996, the Company received an average of $23.15 per barrel and $3.69
per Mcf for its production.
23
<PAGE>
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
PATINA OIL & GAS CORPORATION
Report of Independent Public Accountants........................F-2
Consolidated Balance Sheets as of December 31, 1995 and 1996....F-3
Consolidated Statements of Operations for the years ended
December 31, 1994, 1995 and 1996.........................F-4
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1994, 1995 and 1996.....F-5
Consolidated Statements of Cash Flows for the years ended
December 31, 1994, 1995 and 1996.........................F-6
Notes to Consolidated Financial Statements......................F-7
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders,
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, 1995
and 1996, 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, 1996. 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, 1995 and 1996, and results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
Fort Worth, Texas, ARTHUR ANDERSEN LLP
February 17, 1997
F-2
<PAGE>
PATINA OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
DECEMBER 31,
----------------------
1995 1996
---------- ----------
ASSETS
Current assets
Cash and equivalents $ 1,000 $ 6,153
Accounts receivable 6,611 19,977
Inventory and other 2,000 1,457
--------- ---------
9,611 27,587
--------- ---------
Oil and gas properties, successful efforts method 333,513 559,072
Accumulated depletion, depreciation and amortization (118,919) (160,432)
--------- ---------
214,594 398,640
--------- ---------
Gas facilities and other 4,775 6,421
Accumulated depreciation (4,459) (4,917)
--------- ---------
316 1,504
--------- ---------
Other assets, net - 2,502
--------- ---------
$ 224,521 $ 430,233
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 3,852 $ 15,063
Accrued liabilities 415 11,509
Payable to parent 5,344 -
--------- ---------
9,611 26,572
--------- ---------
Senior debt - 94,500
Subordinated notes - 103,094
Debt to parent 75,000 -
Other noncurrent liabilities 26,247 9,831
Commitments and contingencies
Stockholders' equity
Preferred stock, $.01 par, 5,000,000 shares
authorized, -0- and 1,593,608 shares issued
and outstanding - 16
Common stock, $.01 par, 40,000,000 shares
authorized, 14,000,000 and 18,886,932 shares
issued and outstanding 140 189
Capital in excess of par value - 194,066
Investment by parent 113,523 -
Retained earnings - 1,965
--------- ---------
113,663 196,236
--------- ---------
$ 224,521 $ 430,233
========= =========
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)
YEAR ENDED DECEMBER 31,
----------------------------
1994 1995 1996
------- ------- -------
Revenues
Oil and gas sales $67,749 $50,073 $82,185
Other 73 29 1,003
------- ------- -------
67,822 50,102 83,188
------- ------- -------
Expenses
Direct operating 8,110 8,867 14,519
Exploration 784 416 224
General and administrative 7,484 5,974 6,151
Interest and other 3,869 5,476 14,304
Depletion, depreciation and amortization 43,036 32,591 44,822
------- ------- -------
Income (loss) before taxes 4,539 (3,222) 3,168
------- ------- -------
Provision (benefit) for income taxes
Current - - -
Deferred 1,589 (1,128) (394)
------- ------- -------
1,589 (1,128) ( 394)
------- ------- -------
Net income (loss) $ 2,950 $(2,094) $ 3,562
======= ======= =======
Net income (loss) per common share $.21 $(.15) $.08
======= ======= =======
Weighted average shares outstanding 14,000 14,000 17,796
======= ======= =======
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>
Capital in Retained
Preferred Stock Common Stock Excess of Investment Earnings
----------------------- --------------------
Shares Amount Shares Amount Par Value By Parent (Deficit)
------- -------- ------- -------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1993 - $ - 14,000 $140 $ - $ 92,725 $ -
Credit in lieu of taxes - - - - - (8,190) -
Change in investment by parent - - - - - 28,221 -
Net income - - - - - 2,950 -
------ ------ ------ ------- --------- --------- --------
Balance, December 31, 1994 - - 14,000 140 - 115,706 -
Credit in lieu of taxes - - - - - 1,107 -
Change in investment by parent - - - - - (1,196) -
Net loss - - - - - (2,094) -
------ ------ ------ ------- --------- --------- --------
Balance, December 31, 1995 - - 14,000 140 - 113,523 -
Credit in lieu of taxes - - - - - 171 -
Change in investment by parent - - - - - (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
====== ====== ====== ======= ========= ========= ========
</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,
-------------------------------
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Operating activities
Net income (loss) $ 2,950 $ (2,094) $ 3,562
Adjustments to reconcile net income (loss) to net
cash provided by operations
Exploration expense 784 416 224
Depletion, depreciation and amortization 43,036 32,591 44,822
Deferred taxes 1,589 (1,128) (394)
Amortization of deferred credits (2,539) (2,025) (605)
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable 3,642 1,472 (1,057)
Inventory and other - - 338
Increase (decrease) in
Accounts payable (1,552) (10,902) (4,249)
Accrued liabilities (220) 77 4,844
Other liabilities - - 5,511
-------- -------- --------
Net cash provided by operations 47,690 18,407 52,996
-------- -------- --------
Investing activities
Acquisition, development and exploration (95,596) (21,842) (8,532)
Merger expenditures, net of cash acquired - - (2,375)
Sale of oil and gas properties ( 782) 782 1,111
-------- -------- --------
Net cash used by investing (96,378) (21,060) (9,796)
-------- -------- --------
Financing activities
Increase (decrease) in payable/debt to parent 18,476 1,011 (80,466)
Increase in indebtedness - - 72,863
Deferred credits 1,991 2,838 814
Increase (decrease) in investment by parent 28,221 (1,196) (7,514)
Cost of common stock issuance - - (11,882)
Repurchase of common stock and warrants - - (9,733)
Preferred dividends - - (2,129)
-------- -------- --------
Net cash realized (used) by financing 48,688 2,653 (38,047)
-------- -------- --------
Increase in cash - - 5,153
Cash and equivalents, beginning of period 1,000 1,000 1,000
-------- -------- --------
Cash and equivalents, end of period $ 1,000 $ 1,000 $ 6,153
======== ======== ========
</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"), a Delaware corporation, was
incorporated in January 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 ("GOG"). Previously, SOCO's Wattenberg
operations had been conducted through SOCO or its wholly owned subsidiary, SOCO
Wattenberg Corporation ("SWAT"). On May 2, 1996, SOCO contributed the balance
of its Wattenberg assets to SWAT and transferred all of the shares of SWAT to
the Company. Immediately thereafter, GOG merged into another wholly owned
subsidiary of the Company (the "Merger"). As a result of these transactions,
SWAT and GOG became subsidiaries of the Company. The Company's operations
currently consist of the acquisition, development, and production of oil and gas
properties in the Wattenberg Field.
SOCO currently owns approximately 74% of the common stock of the Company.
In conjunction with the Merger, the Company offered to exchange the Company's
preferred stock for GOG's preferred stock (the "Original Exchange Offer"). A
total of 1,204,847 shares were issued in exchange for approximately 75% of GOG's
preferred stock. In October 1996, GOG's certificate of incorporation was amended
to provide that all shares of GOG's preferred stock not exchanged in the
Original Exchange Offer be exchanged for the Company's preferred stock on the
same terms as the Original Exchange Offer. Upon consummation of this exchange,
the Company had approximately 1.6 million preferred shares outstanding.
The above transactions were accounted for as a purchase of GOG. The amounts
and results of operations of the Company for periods prior to the Merger
reflected in these financial statements include the historical amounts and
results of SOCO's Wattenberg operations. Certain amounts in the accompanying
financial statements have been allocated in a reasonable and consistent manner
in order to depict the historical financial position, results of operations and
cash flows of the Company on a stand-alone basis prior to the Merger.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Producing Activities
The Company utilizes the successful efforts method of accounting for its
oil and gas properties. Consequently, leasehold costs are capitalized when
incurred. Unproved properties are assessed periodically within specific
geographic areas and impairments in value are charged to expense. Exploratory
expenses, including geological and geophysical expenses and delay rentals, are
charged to expense as incurred. Exploratory drilling costs are initially
capitalized, but charged to expense if and when the well is determined to be
unsuccessful. Costs of productive wells, unsuccessful developmental wells and
productive leases are capitalized and amortized on a unit-of-production basis
over the life of the remaining proved or proved developed reserves, as
applicable. Gas is converted to equivalent barrels at the rate of six Mcf to one
barrel. Amortization of capitalized costs has generally been provided over the
entire D-J Basin as the wells are located in the same reservoir. No accrual has
been provided for estimated future abandonment costs as management estimates
that salvage value will approximate such costs.
F-7
<PAGE>
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 1995 and 1996,
the Company did not provide for any impairments. Changes in the underlying
assumptions or the amortization units could, however, result in impairments in
the future.
Other Assets
Other assets reflect the value assigned to a noncompete agreement entered
into as part of the Merger. The value is being amortized over five years at a
rate intended to approximate the decline in the value of the agreement.
Amortization expense for the year ended December 31, 1996 was $2,632,000.
Scheduled amortization for the next five years is $1,500,000 in 1997, $500,000
in 1998, and $250,000 in each of 1999 and 2000.
Section 29 Tax Credits
The Company from time to time enters into arrangements to monetize its
Section 29 tax credits. These arrangements result in revenue increases of
approximately $.40 per Mcf on production volumes from qualified Section 29
properties. As a result of such arrangements, the Company recognized additional
gas revenues of $2.5 million, $2.0 million and $1.5 million during 1994, 1995
and 1996, 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,
1995 and 1996 were insignificant.
Financial Instruments
The book value and estimated fair value of cash and equivalents was $1.0
million and $6.2 million at December 31, 1995 and 1996. The book value
approximates fair value due to the short maturity of these instruments. The
book value and estimated fair value of the Company's debt to parent and senior
debt was $75.0 million and $94.5 million at December 31, 1995 and 1996. The
fair value is presented at face value given its floating rate structure. The
book value of the Senior Subordinated Notes ("Subordinated Notes" or "Notes")
was $103.1 million and the estimated fair value was $105.6 million at December
31, 1996. The fair value is estimated based on their price on the New York
Stock Exchange.
From time to time, the Company enters into commodity contracts to hedge the
price risk of a portion of its production. Gains and losses on such contracts
are deferred and recognized in income as an adjustment to oil and gas sales
revenues in the period to which the contracts relate.
In the fourth quarter of 1996, the Company entered into various swap sales
contracts with a weighted average oil price (NYMEX based) of $22.19 for contract
volumes of 95,000 barrels of oil for January 1997 through February 1997. The
unrecognized loss on these contracts totaled $350,000 based on December 31, 1996
market values. The Company estimates incurring approximately $200,000 of
losses related to these swap contracts based on settlements after year end and
market values as of February 25, 1997.
F-8
<PAGE>
In the fourth quarter of 1996 and early 1997, the Company entered into
various swap sales contracts with a weighted average natural gas price (CIG-
Inside FERC based) of $3.02 for contract volumes of 2,250,000 MMBtu's of natural
gas for January 1997 through March 1997. The unrecognized loss on these
contracts totaled $10,000 based on December 31, 1996 market values. The Company
estimates realizing $1.4 million of income related to these swap contracts based
on settlements after year end and market values as of February 25, 1997.
Supplemental Cash Flow Information
The Merger involved cash and non-cash consideration as presented below:
(In thousands)
Cash payments made for merger $ 14,257
Senior debt assumed 19,000
Subordinated debt assumed 105,805
Minority interest in GOG preferred stock not exchanged at
merger 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
========
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 of cash acquired in the merger.
Risks and Uncertainties
Historically, the market for oil and gas has experienced significant price
fluctuations. Prices for natural gas in the Rocky Mountain region have
traditionally been particularly volatile and have been depressed since 1994. In
large part, the decreased prices are the result of mild weather, increased
production in the region and limited transportation capacity to other regions of
the country. In the fourth quarter of 1996, both oil and natural gas prices
increased considerably, however, there can be no assurance that these increases
will be sustained. Increases or decreases in prices received could have a
significant impact on the Company's future results of operations. Subsequent to
year end, both oil and gas prices have declined to levels similar to the
Company's realized average prices in 1996.
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 current
classification.
All cash payments for income taxes were made by SOCO during 1994, 1995 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 to SOCO of $3.9 million, $5.4
million and $1.6 million during 1994, 1995 and through May 2, 1996, which was
reflected as an increase in debt to SOCO.
F-9
<PAGE>
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.
(3) OIL AND GAS PROPERTIES
The cost of oil and gas properties at December 31, 1994, 1995 and 1996
includes no significant unevaluated leasehold. 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.
1994 1995 1996
-------- -------- ---------
(IN THOUSANDS)
Acquisition $ 7,556 $ 650 $218,380
Development 88,213 12,141 8,301
Exploration and other 1,693 429 224
------- ------- --------
$97,462 $13,220 $226,905
======= ======= ========
In May 1996, the Merger discussed in Note 1 was consummated. The following
table summarizes the unaudited pro forma effects on the Company's financial
statements assuming that the Merger and the Original Exchange Offer had been
consummated on January 1, 1995 and 1996. Future results may differ substantially
from pro forma results due to changes in these assumptions, changes in oil and
gas prices, production declines and other factors. Therefore, pro forma
statements cannot be considered indicative of future operations.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1995 1996
------- ------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C>
Total revenues $103,962 $100,138
Gross operating margin $ 85,654 $ 82,420
Depletion, depreciation and amortization $ 63,383 $ 51,662
Net income (loss) $( 7,338) $ 3,476
Net income (loss) per common share $(.51) $ .03
Weighted average shares outstanding 20,000 19,796
</TABLE>
F-10
<PAGE>
(4) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
DECEMBER 31,
------------------------
1995 1996
-------- ---------
(IN THOUSANDS)
Bank facilities $ - $ 94,500
Less current portion - -
-------- --------
Senior debt, net $ - $ 94,500
======== ========
Subordinated notes $ - $103,094
======== ========
Debt to parent $75,000 $ -
======== ========
As of February 25, 1997, the Company had approximately $185.1 million of
debt outstanding, consisting of $82.0 million of senior debt and $103.1 million
of Subordinated Notes.
Simultaneously with the Merger, the Company entered into a bank credit
agreement. The agreement consists of (a) a facility provided to the Company and
SOCO Wattenberg (the "Company Facility") and (b) a facility provided to GOG (the
"GOG Facility").
The Company Facility is a revolving credit facility in an aggregate amount
up to $102 million. The amount available for borrowing under the Company
Facility is limited to a semiannually adjusted borrowing base that equalled $85
million at December 31, 1996. At December 31, 1996, $67.5 million was
outstanding under the Company Facility. Prior to September 30, 1996, the Company
had a term loan facility in an amount up to $87 million. This term loan facility
was available to fund GOG's repurchases of the Subordinated Notes. At September
30, 1996, the Company had not utilized the term loan facility and it was
canceled.
The GOG Facility is a revolving credit facility in an aggregate amount up
to $51 million. The amount available for borrowing under the GOG Facility is
limited to a semiannually adjusted borrowing base that equalled $35 million at
December 31, 1996. At December 31, 1996, $27.0 million was outstanding under the
GOG Facility. The GOG Facility was used primarily to refinance GOG's previous
bank credit facility and pay costs associated with the Merger.
The borrowers may elect that all or a portion of the credit facilities bear
interest at a rate per annum equal to: (i) the higher of (a) prime rate plus a
margin equal to .25% (the "Applicable Margin") or (b) the Federal Funds
Effective Rate plus .5% plus the Applicable Margin, or (ii) the rate at which
eurodollar deposits for one, two, three or six months (as selected by the
applicable borrower) are offered in the interbank eurodollar market in the
approximated amount of the requested borrowing (the "Eurodollar Rate") plus
1.25% (the "Eurodollar Margin"). During the period subsequent to the Merger
through December 31, 1996, the average interest rate under the facilities
approximated 6.9%.
The bank 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 bank 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
F-11
<PAGE>
transactions; sale of receivables; prepayment of other indebtedness; amendments
to principal documents; negative pledge clauses; issuance of securities; and
commodity hedging.
Simultaneously with the Merger, the Company recorded $100 million of 11.75%
Senior Subordinated Notes due July 15, 2004 issued by GOG on July 1, 1994. In
connection with the Merger, the Company repurchased $1.2 million of the Notes.
The Company has also repurchased an additional $1.4 million of the Notes. As
part of the purchase accounting, the remaining Notes have been reflected in the
accompanying financial statements at $103.1 million or 105.875% of their
principal amount. Interest is payable each January 15 and July 15. The Notes
are redeemable at the option of GOG, in whole or in part, at any time on or
after July 15, 1999, initially at 105.875% of their principal amount, declining
to 100% on or after July 15, 2001. Upon the occurrence of a change of control,
as defined in the Notes, GOG would be obligated to make an offer to purchase all
outstanding Notes at a price of 101% of the principal amount thereof. In
addition, GOG would be obligated, subject to certain conditions, to make offers
to purchase Notes with the net cash proceeds of certain asset sales or other
dispositions of assets at a price of 101% of the principal amount thereof. The
Notes are unsecured general obligations of GOG and are subordinated to all
senior indebtedness of GOG and to any existing and future indebtedness of GOG's
subsidiaries.
The Notes contain covenants that, among other things, limit the ability of
GOG 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 GOG from incurring indebtedness (exclusive of the Notes) in
excess of approximately $51 million, if after giving effect to the incurrence of
such additional indebtedness and the receipt and application of the proceeds
therefrom, GOG'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 GOG. GOG currently does not meet the interest coverage ratio necessary to
incur indebtedness in excess of approximately $51 million.
Prior to the Merger, SOCO financed all of the Company's activities. A
portion of such financing was considered to be an investment by parent in the
Company with the remaining portion being considered Debt to parent. The portion
considered to be Debt to parent versus an investment by parent was a
discretionary percentage determined by SOCO after consideration of the Company's
internally generated cash flows and level of capital expenditures. Subsequent
to the Merger, the $75 million debt to parent was paid in full and the Company
does not expect SOCO to provide any additional funding.
On the portion of such financing which was considered to be Debt to parent,
SOCO charged interest at a rate which approximated the average interest rate
being paid by SOCO under its revolving credit facility (5.5%, 7.0% and 6.9% for
1994, 1995 and the four month period ended May 2, 1996, respectively).
Scheduled maturities of indebtedness for the next five years are zero for
1997 and 1998, $94.5 million in 1999, zero in 2000 and 2001. The long-term
portions of the credit facilities are scheduled to expire in 1999; however, it
is management's intent to review both the short-term and long-term facilities
and extend the maturities on a regular basis.
There were no cash payments for interest expense in 1994, 1995 or in the
first four months of 1996. Cash payments for interest totaled $10.5 million in
the eight months ended December 31, 1996.
F-12
<PAGE>
(5) STOCKHOLDERS' EQUITY
A total of 40 million common shares, $.01 par value, are authorized of
which 18.9 million were issued and outstanding at December 31, 1996. The Company
issued 6.0 million common shares and 3.0 million warrants exercisable at $12.50
in exchange for all of the outstanding stock of GOG upon consummation of the
Merger. Of the 18.9 million shares outstanding, 2 million are designated as
Series A Common Stock. The Series A Common Stock is identical to the common
shares except that the Series A Common Stock is entitled to three votes per
share rather than one vote per share. The Series A Common Stock is owned by SOCO
and reverts to regular common shares upon certain conditions. Subsequent to the
merger date, the Company repurchased 1,116,700 shares of common stock, 500,000
warrants issued to GOG's former chief executive officer, and 80,549 warrants for
total consideration of $9.7 million. No dividends have been paid on common stock
as of December 31, 1996.
A total of 5 million preferred shares, $.01 par value, are authorized of
which 1.6 million were issued and outstanding at December 31, 1996. In May 1996,
1.2 million shares of 7.125% preferred stock were issued to certain GOG
preferred shareholders electing to exchange their preferred shares in the
Original Exchange Offer. Thus there were no proceeds received related to this
issuance. In October 1996, GOG's certificate of incorporation was amended to
provide that all shares of GOG's preferred stock not exchanged in the Original
Exchange Offer be exchanged for the Company's preferred shares on the same terms
as the Original Exchange Offer. This exchange resulted in the issuance of an
additional 389,000 preferred shares. The stock is convertible into common stock
at any time at $8.61 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 Patina 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. The liquidation preference is $25 per share, plus
accrued and unpaid dividends. The Company paid $2.1 million ($1.78 per 7.125%
convertible share per annum) in preferred dividends during the year ended
December 31, 1996 and had accrued an additional $354,000 at December 31, 1996
for dividends.
Earnings per share are computed by dividing net income, less dividends on
preferred stock, by weighted average common shares outstanding. Net income
(loss) applicable to common for 1994, 1995 and 1996, was $2,950,000,
($2,094,000) and $1,433,000, respectively. Differences between primary and
fully diluted earnings per share were insignificant for all periods presented.
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 up to three million shares of common stock 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. The options vest over a three-year period (30%, 60%, 100%) and expire
five years from date of grant.
In 1996, the shareholders adopted a stock grant and option plan (the
"Directors' Plan") for nonemployee Directors of the Company. The Directors'
Plan provides for each nonemployee Director to receive common shares having a
market value equal to $2,250 quarterly in payment of one-half their retainer. A
total of 3,632 shares were issued in 1996. It also provides for 5,000 options
to be granted annually to each nonemployee Director. A total of 20,000 options
were issued in May 1996 with an exercise price of $7.75 per common share. The
options vest over a three-year period (30%, 60%, 100%) and expire five years
from date of grant.
F-13
<PAGE>
At December 31, 1996, 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:
1996
----
Net income (loss) As Reported $3,562
Pro forma $3,281
Income (loss) per common share As Reported $ 0.08
Pro forma $ 0.06
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: dividend yield of 0%; expected volatility
of 30%; risk-free interest rate of 6.4%; and expected life of 4.5 years.
A summary of the status of the Company's fixed stock option plan as of
December 31, 1996 and changes during the year is presented below (shares are in
thousands):
1996
----
Weighted-Average
Exercise
Shares Price
------ -----
Outstanding at beginning of year - $ -
Granted` 532 7.75
Exercised - -
Forfeited (29) 7.75
----
Outstanding at end of year 503 7.75
----
Options exercisable at year end - -
Weighted-average fair value of options granted during the year $2.81
The following table summarizes information about fixed stock options
outstanding at December 31, 1996:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
------------------------------------------------- -------------------------------
Number Number
Outstanding at Weighted-Avg. Weighted- Exercisable at Weighted-
December 31, Remaining Average December 31, Average
Exercise Price 1996 Contractual Life Exercise Price 1996 Exercise Price
- -------------- ---- ---------------- -------------- ---- --------------
<S> <C> <C> <C> <C> <C>
$ 7.75 503,000 4.3 years $7.75 - -
</TABLE>
F-14
<PAGE>
(6) FEDERAL INCOME TAXES
Prior to the Merger, the Company had been included in the tax return of
SOCO. 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. Subsequent to the
Merger, the Company will not be included in the tax return of SOCO.
A reconciliation of the statutory rate to the Company's effective rate as
they apply to the provision (benefit) for the years ended December 31, 1994,
1995 and 1996 follows:
1994 1995 1996
------ ------ ------
Federal statutory rate 35% (35%) 35%
Utilization of net deferred tax asset - - (35%)
Tax benefit recognized prior to Merger - - (12%)
----- ----- -----
Effective income tax rate 35% (35%) (12%)
===== ===== =====
For book purposes the components of the net deferred asset and liability at
December 31, 1995 and 1996, respectively, were:
1995 1996
------- ------
(IN THOUSANDS)
Deferred tax assets
NOL carryforwards $ 15,716 $24,586
Production payment receivables and other 128 27,382
-------- -------
15,844 51,968
-------- -------
Deferred tax liabilities
Depreciable and depletable property 41,169 48,145
Investments and other - -
-------- -------
41,169 48,145
-------- -------
Deferred tax assets (liability) (25,325) 3,823
-------- -------
Valuation allowance - (3,823)
-------- -------
Net deferred tax asset (liability) $(25,325) $ -
======== =======
For tax purposes, the Company had regular net operating loss carryforwards
of $70.2 million and alternative minimum tax ("AMT") loss carryforwards of $35.1
million at December 31, 1996. 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 merger of GOG and SOCO
Wattenberg Corporation on May 2, 1996. These carryforwards expire from 2006
through 2011. At December 31, 1996, the Company had alternative minimum tax
credit carryforwards of $478,000 which are available indefinitely. No cash
payments were made by the Company for federal taxes during 1995 and 1996. As
discussed in Note 1, the accompanying financial statements include certain
Wattenberg operations previously owned directly by SOCO. Accordingly, certain
operating losses generated by these properties were retained by SOCO. In
addition, certain taxable income generated by SOCO did not offset the Company's
net operating loss carryforwards. Prior to the Merger, the effect of such items
has been reflected as a charge or credit in lieu of taxes in the Company's
consolidated statement of changes in stockholders' equity.
F-15
<PAGE>
(7) MAJOR CUSTOMERS
During 1996, PanEnergy, Inc. accounted for 38% of revenues. During 1994,
1995 and 1996, Amoco Production Company accounted for 25%, 22% and 19%,
subsidiaries of SOCO accounted for 59%, 46% and 0%, and Total Petroleum
accounted for 15%, 20% and 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.
(8) RELATED PARTY
Prior to the Merger, the Company did not have its own employees.
Employees, certain office space and furniture, fixtures and equipment were
provided by SOCO. SOCO allocated general and administrative expenses to the
Company based on its estimate of expenditures incurred on behalf of the Company.
Subsequent to the Merger, certain field, administrative and executive employees
of SOCO and GOG became employees of the Company. SOCO will continue to provide
certain services to Patina under a corporate services agreement. During 1996,
the Company paid approximately $650,000 to SOCO under the corporate services
agreement.
(9) 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 1997 through 2001.
In August 1995, SOCO was sued in the United States District Court of
Colorado by plaintiffs purporting to represent all persons who, at any time
since January 1, 1960, have had agreements providing for royalties from gas
production in Colorado to be paid by SOCO under various lease provisions. In
January 1997, the judge denied the plaintiffs' motion for class certification.
Substantially all liability under this suit was assumed by the Company upon its
formation. In January 1996, GOG was also sued in a similar but separate action
filed in the Colorado State Court. The plaintiffs, in both suits, allege that
unspecified "post-production" costs incurred prior to calculating royalty
payments were deducted in breach of the relevant lease provisions and that this
fact was fraudulently concealed. The plaintiffs seek unspecified compensatory
and punitive damages and a declaratory judgment prohibiting the deduction of
post-production costs prior to calculating royalties paid to the plaintiffs. The
Company believes that costs deducted in calculating royalties are and have been
proper under the relevant lease provisions, and they intend to defend these and
any similar suits vigorously. At this time, the Company is unable to estimate
the range of potential loss, if any. 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 impact on results for that period.
In March 1996, a complaint was filed in the Court of Chancery for the State
of Delaware against GOG 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 the defendants from consummating a merger
which will benefit the holders of GOG's common stock at the expense of the
holders of the Preferred and (b) to obtain a declaration that the terms of the
proposed merger constitute a breach of the contractual rights of the Preferred."
The complaint seeks, among other things, certification as a class action on
behalf of all holders of GOG'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 Merger and money damages.
Defendants believe that the complaint is without merit and intend to vigorously
defend against the 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
F-16
<PAGE>
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 impact 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.
(10) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Independent petroleum consultants directly evaluated 89%, 100% and 100% of
proved reserves at December 31, 1994, 1995 and 1996, respectively. All reserve
estimates are based on economic and operating conditions at that time. Future
net cash flows as of each year and 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 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 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-17
<PAGE>
<TABLE>
<CAPTION>
QUANTITIES OF PROVED RESERVES ---
CRUDE OIL NATURAL GAS
---------- ------------
(MBBL) (MMCF)
<S> <C> <C>
Balance, December 31, 1993 16,928 229,862
Revisions (4,450) (50,021)
Extensions, discoveries and additions 1,372 20,900
Production (1,829) (23,893)
Purchases 197 1,855
Sales - -
------ -------
Balance, December 31, 1994 12,218 178,703
Revisions (3,609) (19,618)
Extensions, discoveries and additions 154 785
Production (1,342) (20,981)
Purchases - -
Sales - (32)
------ -------
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
====== =======
PROVED DEVELOPED RESERVES ---
CRUDE OIL NATURAL GAS
---------- ------------
(MBBL) (MMCF)
December 31, 1993 7,365 136,765
====== =======
December 31, 1994 8,832 147,869
====== =======
December 31, 1995 6,955 133,088
====== =======
December 31, 1996 15,799 242,777
====== =======
</TABLE>
F-18
<PAGE>
<TABLE>
<CAPTION>
STANDARDIZED MEASURE ---
DECEMBER 31,
-----------------------------------
1995 1996
--------------- ----------------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows $ 356,224 $1,668,475
Future costs:
Production (100,505) (338,752)
Development (13,428) (160,856)
--------- ----------
Future net cash flows 242,291 1,168,867
Undiscounted income taxes (29,873) (294,407)
--------- ----------
After tax net cash flows 212,418 874,460
10% discount factor (84,902) (374,524)
--------- ----------
Standardized measure $ 127,516 $ 499,936
========= ==========
</TABLE>
CHANGES IN STANDARDIZED MEASURE ---
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1994 1995 1996
--------- ---------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of year $ 191,011 $ 161,481 $ 127,516
Revisions:
Prices and costs (56,928) 2,240 351,724
Quantities (29,498) (14,230) 501
Development costs (8,044) (1,182) (11,024)
Accretion of discount 19,101 16,148 27,619
Income taxes 23,121 10,963 (129,612)
Production rates and other (8,422) (21,265) (3,706)
--------- ---------- ----------
Net revisions (60,670) (7,326) 235,502
Extensions, discoveries and additions 19,583 2,064 3,791
Production (58,099) (40,877) (67,666)
Future development costs incurred 67,484 12,192 7,906
Purchases (a) 2,172 - 193,998
Sales (b) - (18) (1,111)
--------- ---------- ----------
Standardized measure, end of year $ 161,481 $ 127,516 $ 499,936
========= ========== ==========
</TABLE>
(a) "Purchases" includes the present value at the end of the period acquired
during the year plus the 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-19
<PAGE>
PART IV. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 10-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)
2.2 Business Opportunity Agreement -- incorporated herein by
reference to Exhibit 2.2 to the Company's Form 8-K dated May 2,
1996 (Commission file number 1-14344)
2.3 Corporate Services Agreement -- incorporated by reference to
Exhibit 2.3 to the Registration Statement on Form S-4 of Patina
Oil & Gas Corporation (Registration No. 333-572)
2.4 Registration Rights Agreement -- incorporated herein by reference
to Exhibit 2.4 to the Company's Form 8-K dated May 2, 1996
(Commission file number 1-4344)
2.5 Cross Indemnification Agreement -- incorporated herein by
reference to Exhibit 2.5 to the Company's Form 8-K dated May 2,
1996 (Commission file number 1-14344)
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)
10.1.1 Credit Agreement dated as of May 2, 1996 among the Company,
Gerrity Oil & Gas Corporation and SOCO Wattenberg Corporation, as
Borrowers, certain financial institutions, and Texas Commerce
Bank National Association, as Administrative Agent, and certain
commercial lending institutions -- incorporated herein by
reference to Exhibit 10.1 to the Company's Form 8-K dated May 2,
1996 (Commission file number 1-4344)
10.1.2 First Amendment to Credit Agreement dated June 28, 1996 by and
among the Company, Gerrity Oil & Gas Corporation and SOCO
Wattenberg Corporation, as Borrowers, and Texas Commerce Bank
National Association, as Administrative Agent, and certain
commercial lending institutions --incorporated herein by
reference to Exhibit 10.1.1 to the Company's Form 10-Q for the
quarter ending June 30, 1996 (Commission file number 1-14344)
10.1.3 Second Amendment to Credit Agreement effective October 8, 1996 by
and among the Company, Gerrity Oil & Gas Corporation and SOCO
Wattenberg Corporation, as Borrowers, and Texas Commerce Bank
National Association, as Administrative Agent, and certain
commercial lending institutions --incorporated herein by
reference to Exhibit 10.74 of the Company's Form 10-Q for the
quarter ending September 30, 1996 (Commission file number 1-4344)
F-20
<PAGE>
10.1.4 Third Amendment to Credit Agreement effective November 1, 1996 by
and among the Company, Gerrity Oil & Gas Corporation and SOCO
Wattenberg Corporation, as Borrowers, and Texas Commerce Bank
National Association, as Administrative Agent, and certain
commercial lending institutions --incorporated herein by
reference to Exhibit 10.75 of the Company's Form 10-Q for the
quarter ending September 30, 1996 (Commission file number 1-
14344)
10.3 Agreement dated July 16, 1996 by and between F. H. Smith,
employee, and the Company --incorporated herein by reference to
Exhibit 10.3 of the Company's Form 10-Q for the quarter ending
June 30, 1996 (Commission file number 1-14344)
10.3.1 Deferred Compensation Plan for Selected Employees adopted by the
Company effective May 1, 1996.*
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 ending June 30, 1996 (Commission file
number 1-14344)
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 10.76 of the Company's Form 10-Q for the quarter ending
September 30, 1996 (Commission file number 1-14344)
11.1 Computation of Per Share Earnings.*
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.*
99 Reserve letter from Netherland, Sewell & Associates, Inc. Dated
February 5, 1997 to the Patina Oil & Gas Corporation interest as
of December 31, 1996.*
*Filed herewith
(b) Reports on Form 8-K -
On May 17, 1996, the Company filed with the Securities and Exchange
Commission a Current Report on Form 8-K. The Report disclosed under Item 1
information regarding the approval of the Amended Agreement and Plan of
Merger among Snyder Oil Corporation, the Company, Patina Merger Corporation
and Gerrity Oil & Gas Corporation.
F-21
<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.
<TABLE>
<CAPTION>
<S> <C> <C>
/s/ Thomas J. Edelman Chairman of the Board and President March 4, 1997
- ----------------------------
Thomas J. Edelman (Principal Executive Officer)
/s/ Brian J. Cree Director, Executive Vice President March 4, 1997
- ----------------------------
Brian J. Cree and Chief Operating Officer
/s/ Robert J. Clark Director March 4, 1997
- ----------------------------
Robert J. Clark
/s/Jay W. Decker Director March 4, 1997
- ----------------------------
Jay W. Decker
/s/ William J. Johnson Director March 4, 1997
- ----------------------------
William J. Johnson
/s/ Alexander P. Lynch Director March 4, 1997
- ----------------------------
Alexander P. Lynch
/s/ John C. Snyder Director March 4, 1997
- ----------------------------
John C. Snyder
/s/ David J. Kornder Vice President and Chief Financial
- ----------------------------
David J. Kornder Officer March 4, 1997
</TABLE>
F-22
<PAGE>
Exhibit 10.3.1
PATINA OIL & GAS CORPORATION
DEFERRED COMPENSATION PLAN
FOR SELECT EMPLOYEES
AS ADOPTED MAY 1, 1996
ARTICLE 1 -- INTRODUCTION
1.1 PURPOSE OF THE PLAN
The Employer has adopted the Plan set forth herein to provide a means by which
certain employees may elect to defer receipt of designated percentages or
amounts of their Compensation and to provide a means for certain other deferrals
of compensation.
1.2 STATUS OF PLAN
The Plan is intended to be a "plan which is unfunded and is maintained by an
employer primarily for the purpose of providing deferred compensation for a
select group of management or highly compensated employees" within the meaning
of Sections 201(2) and 301(a)(3) of the Employee Retirement Income Security Act
of 1974 ("ERISA"), and shall be interpreted and administered to the extent
possible in a manner consistent with that intent.
ARTICLE 2 -- DEFINITIONS
Whenever used herein, the following terms have the meanings set forth below,
unless a different meaning is clearly required by the context:
2.1 ACCOUNT means, for each Participant, the account established for his or her
benefit under Section 5.1.
2.2 CHANGE OF CONTROL means (a) the purchase or other acquisition in one or
more transactions other than from the Employer, by any individual, entity or
group of persons within the meaning of Section 13(d)(3) or 14(d) of the
Securities Exchange Act of 1934 or any comparable successor provisions, of
beneficial ownership (within the meaning of Rule 13d-3 of the Securities
Exchange Act) of 50 percent or more of either that outstanding shares of common
stock or the combined voting power of Employer's then outstanding voting
securities entitled to vote generally or (b) in connection or as a result of any
tender offer, exchange offer, merger or other business combination or proxy
contest the directors prior to such event no longer constitute a majority of the
directors of Employer, or (c) the approval by stockholders of the Employer of a
reorganization, merger, consolidation or other business combination, in each
case, with respect to which persons who were stockholders of the Employer
immediately prior to such event do not immediately thereafter own more than 50%
of the combined voting power of the reorganized, merged, consolidated or
combined Employer's then outstanding securities that are entitled to vote
generally in the election of directors or (d) the liquidiation or dissolution of
Employer or sale of all or substantially all of the Employer's assets.
2.3 CODE means the Internal Revenue Code of 1986, as amended, from time to
time. Reference to any section or subsection of the Code included reference to
any comparable or succeeding provisions of any legislation which amends,
<PAGE>
supplements or replaces such section or subsection.
2.4 COMPENSATION means the regular or base salary and cash bonuses payable by
the Employer or an Affiliate to an individual. For purposes of the Plan,
Compensation will be determined before giving effect to Elective Deferrals and
other salary reduction amounts which are not included in the Participant's gross
income under Sections 125, 401(k), 402(h) or 403(b) of the Code.
For purposes of the Plan, bonuses shall be deemed to have been earned during the
Plan Year in which the Employer accrues such bonuses for federal income tax
reporting purposes. Under the Employer's present method of federal income tax
reporting, regular bonuses paid in March of a given year are accrued ratably
during the prior year. Regular salary and special bonuses, as designated by the
Board of Directors or the Compensation Committee of the Board of Directors of
Employer, are included in Compensation at the time paid to the employee. Thus,
for example, Compensation for the Plan Year ending December 31, 1995 includes
regular salary paid during 1995 and any regular bonus paid during March 1996. As
a result an Elective Deferral to defer, say, 10% of a Participant's 1995
Compensation will result in the deferral hereunder of 10% of the Participant's
1995 salary and 10% of any regular bonus paid to the Participant in March 1996
(any regular bonus payable in March 1995 would not be affected to an election to
defer a portion of 1995 Compensation, since such bonus would be included in 1994
Compensation).
2.5 DISABILITY means a Participant's total and permanent mental or physical
disability resulting in termination of employment as evidenced by presentation
of medical evidence satisfactory to the Administrator.
2.6 EFFECTIVE DATE means July 1, 1996.
2.7 ELECTION FORM means the participation election form as approved and
prescribed by the Plan Administrator.
2.8 ELECTIVE DEFERRAL means the portion of Compensation during a Plan Year
which is deferred by a Participant under Section 4.1.
2.9 ELIGIBLE EMPLOYEE means, on the Effective Date or on any Entry Date
thereafter, those employees of the Employer selected by the Compensation
Committee of the Board of Directors of Employer or by such persons as the
Compensation Committee may authorize to select employees entitled to participate
in the Plan.
2.10 ENTRY DATE means, for each Participant, the date deferrals commence in
accordance with Section 4.1.
2.11 EMPLOYER means Patina Oil & Gas Corporation, any successor to all or a
major portion of its assets or business which assumes the obligations of
Employer, and each other entity that is affiliated with the Employer that adopts
the Plan with the consent of the Employer, provided that Patina Oil & Gas
Corporation shall have the sole power to amend this Plan and shall be the Plan
Administrator if no other person or entity is so serving at any time.
2.12 ERISA means the Employee Retirement Income Security Act of 1974, as amended
from time to time. Reference to any section or subsection of ERISA includes
<PAGE>
reference to any comparable or succeeding provisions of any legislation which
amends, supplements or replaces such section or subsection.
2.13 INCENTIVE CONTRIBUTION means a discretionary additional contribution made
by Employer as described in Section 4.3.
2.14 INSOLVENT means either (1) the Employer is unable to pay its debts as they
become due or (2) the Employer is subject to a pending proceeding as a debtor
under the United States Bankruptcy Code.
2.15 MATCHING DEFERRAL means a deferral for the benefit of a Participant as
described in Section 4.2.
2.16 MATCHING DEFERRAL LIMITATION means, with respect to Elective Deferrals of
Compensation for any Plan Year made by any Participant, 10% of such
Participant's base salary during such Plan Year. The Compensation Committee may
change the Matching Deferral Limitation for any Participant or all Participants
at any time, provided that the Matching Deferral Limitation applicable to
Elective Deferrals of Compensation for any Plan Year made by any Participant may
not be reduced unless the Plan Administrator has given written notice of such
reduction to the Participant not less than 10 days prior to the commencement of
such Plan Year. The foregoing shall not limit the Employer's rights to decrease
the salary or Compensation of, or terminate the employment of, any Participant
at any time, with or without cause and with or without prior notice, without
regard to the effect such discharge would have on the Participant's interest in
the Plan.
2.17 MATCHING DEFERRAL RATE means, with respect to Elective Deferrals of
Compensation for any Plan Year made by any Participant, 100%. The Compensation
Committee may change the Matching Deferral Rate for any Participant or all
Participants at any time, provided that the Matching Deferral Rate applicable to
Elective Deferrals of Compensation for any Plan Year made by any Participant may
not be reduced unless the Plan Administrator has given written notice of such
reduction to the Participant not less than 10 days prior to the commencement of
such Plan Year.
2.18 PARTICIPANT means any individual who participates in the Plan in accordance
with Article 3.
2.19 PLAN means the Patina Oil & Gas Corporation Deferred Compensation Plan for
Select Employees as amended from time to time.
2.20 PLAN ADMINISTRATOR means the person, persons or entity designated by the
Employer to administer the Plan and to serve as agent for the Employer with
respect to the Trust. If no such person or entity is serving as Plan
Administrator at any time, the Employer shall be Plan Administrator.
2.21 PLAN YEAR means, in the case of the first Plan Year, the period from the
Effective Date through December 31, 1996 and, for each Plan Year thereafter, the
12-month period ending December 31.
2.22 RETIREMENT AGE means the age of 55 or such other age as shall be determined
as the normal retirement age for purposes of the Employer's welfare and
retirement plans as determined by the Employer's Board of Directors or the
Compensation Committee thereof. No determination to increase the Retirement Age
shall be effective with respect to amounts credited to the Account of a
<PAGE>
Participant with respect to Plan Years commencing prior to the time of such
determination.
2.22 TRUST means the Rabbi Trust established by the Employer that identifies the
Plan as a plan with respect to which assets are to be held by the Trustee.
2.23 TRUSTEE means the trustee or trustees under the Trust.
ARTICLE 3 -- PARTICIPATION
3.1 COMMENCEMENT OF PARTICIPATION
Any Eligible Employee who elects to defer part of his or her Compensation in
accordance with Section 4.1 shall become a participant in the Plan as of the
date such deferrals commence in accordance with Section 4.1. Any individual who
is not already a Participant and whose account is credited with an Incentive
Contribution shall become a Participant as of the date such amount is credited.
3.2 CONTINUED PARTICIPATION
A Participant in the Plan shall continue to be a Participant so long as any
amount remains credited to his or her Account.
ARTICLE 4 -- DEFERRALS AND INCENTIVE CONTRIBUTIONS
4.1 ELECTIVE DEFERRALS.
Any Eligible Employee may elect to defer a percentage or dollar amount of one or
more payments of Compensation for the next succeeding Plan Year, on such terms
as the Plan Administrator may permit, by completing an Election Form and filing
it with the Plan Administrator prior to the first day of such succeeding Plan
Year (or any such earlier date as the Plan Administrator may prescribe),
provided that (1) an individual who is an Eligible Employee on the Effective
Date may, by completing an Election Form and filing it with the Plan
Administrator within 30 days following the Effective Date, elect to defer a
percentage or dollar amount of one or more payments of Compensation for the 1996
Plan Year, on such terms as the Plan Administrator may permit, which are payable
to the Participant after the date on which the Eligible Employee files the
Election Form and (2) an Eligible Employee who is a new employee of Employer
may, by completing an Election Form and filing it with the Plan Administrator
within 30 days of the date such employment commences, elect to defer a
percentage or dollar amount of one or more payments of Compensation for the Plan
Year in which such employment commences, on such terms as the Plan Administrator
may permit, which are payable to the Participant after the date on which the
Eligible Employee files the Election Form.
An election to defer a percentage or dollar amount of Compensation for any Plan
Year shall apply only to that Plan Year, unless the Participant elects otherwise
on the Election Form.
A Participant's Compensation shall be reduced in accordance with the
Participant's election hereunder and amounts deferred hereunder shall be paid by
the Employer to the Trust as soon as administratively feasible and credited to
<PAGE>
the Participant's Accounts as of the date the amounts are received by the
Trustee.
4.2 MATCHING DEFERRALS
After each payroll period, the Employer shall contribute to the Trust Matching
Deferrals equal to the Matching Deferral Rate multiplied by the amount of the
Elective Deferrals credited to the Participants' Accounts for such period under
Section 4.1. Each Matching Deferral will be credited as of the date it is
received by the Trustee pro rata in accordance with the amount of Elective
Deferrals of each Participant which are taken into account in calculating the
Matching Deferral. The amount of Matching Contributions credited to the Account
of any Participant with respect to Elective Deferrals of Compensation for any
Plan Year may not exceed the Matching Deferral Limitation applicable to that
Participant for such Plan Year.
Notwithstanding the foregoing or anything in Section 7.1, if the amount of
"Employee Deferral Contributions" (as defined in the Employer's 401(k) Plan)
made by a Participant during a Plan Year is less than the maximum amount of
Employee Elective Deferrals the Participant is permitted to make to the
Employer's 401(k) Plan (after taking into account the employer's contribution
allocated to the Participant's account and any limitations imposed by the 401(k)
Plan or the Code), all Matching Deferrals, and any income and gain thereon,
credited to the Account of the Participant with respect to Elective Deferrals of
Compensation for such Plan Year shall be forfeited and applied as provided in
Section 7.7, unless the Plan Administrator, in its sole discretion determines
that the failure to contribute such maximum amount to the Employer's 401(k) Plan
is the result of an administrative error by the Employer or other reasons beyond
the Control of the Participant.
4.3 INCENTIVE CONTRIBUTIONS
In addition to other contributions provided for under the Plan, the Employer
may, in its sole discretion, select one or more Eligible Employees to receive an
Incentive Contribution to his or her account on such terms as the Employer shall
specify at the time it makes the contribution. For example, the Employer may
contribute an amount to the Participant's Account and condition the payment of
such amount and accrued earnings thereon upon the Participant's remaining
employed by the Employer for an additional specified period of time. The terms
specified by the Employer shall supersede any other provision of this Plan as
regards Incentive Contributions and earnings with respect thereto, provided that
if the Employer does not specify (a) the terms on which such Incentive
Contribution will vest, the Incentive Contribution and earnings thereon will
vest in the same manner as Matching Deferrals or (b) a method of distribution,
the Incentive Contribution and earnings thereon will be distributed in a manner
consistent with the election last made by the Participant prior to the Plan Year
in which the Incentive Contribution is made. The Employer, in its discretion,
may permit the Participant to designate a distribution schedule for a particular
Incentive Contribution provided the designation is made before the Employer
finally determines that the Participant will receive the Incentive Contribution.
ARTICLE 5 -- ACCOUNTS
5.1 ACCOUNTS
<PAGE>
The Plan Administrator shall establish an Account for each Participant
reflecting Elective Deferrals, Matching Deferrals and Incentive Contributions
made for the Participant's benefit together with any adjustments for income,
gain or loss and any payments from the Account. The Plan Administrator shall
establish sub-accounts for each Participant that has more than one election in
effect under Section 7.1 and such other sub-accounts as are necessary for the
proper administration of the Plan. As of the last business day of each calendar
quarter, the Plan Administrator shall provide the Participant with a statement
of his or her Account reflecting the income, gains and losses (realized and
unrealized), amounts of deferrals and distributions of such Account since the
prior statement.
5.2 INVESTMENTS
The assets of the Trust shall be invested in investment options similar to the
options available under the Employer's 401(k) Plan as directed by the Plan
Administrator, except that no portion of Trust assets may be invested in
securities issued by the Employer. Unless the Plan Administrator, in its sole
discretion, determines otherwise, each Participant may designate the investments
in which amounts credited to such Participant's Account are invested.
ARTICLE 6 -- VESTING
6.1 GENERAL
A Participant will be immediately vested in, i.e., shall have a nonforfeitable
right to, all Elective Deferrals, and to all income and gain attributable
thereto, credited to his or her Account. Subject to earlier vesting in
accordance with this Article 6, a Participant shall become vested in the portion
of his or her Account attributable to Matching Deferrals made with respect to
Elective Deferrals of Compensation for a given Plan Year as follows:
(a) 33-1/3% at the end of the Plan Year with respect to which the Matching
Deferrals are made;
(b) 33-1/3% at the end of the first Plan Year following the Plan Year with
respect to which the Matching Deferrals are made; and
(c) 33-1/3% at the end of the second Plan Year following the Plan Year with
respect to which the Matching Deferrals are made.
Any portion of a Participant's Account that have not vested on the date that a
Participant's employment with Employer terminates shall, except as provided in
this Article 6, shall be forfeited and applied as provided in Section 7.7.
6.2 CHANGE OF CONTROL
A Participant shall become fully vested in his or her Account immediately prior
to a Change of Control of the Employer.
6.3 DEATH, RETIREMENT OR DISABILITIY
A Participant shall become fully vested in his or her Account immediately prior
to termination of the Participant's employment by reason of Participant's death,
retirement at or after the attainment of the Retirement Age or Disability.
<PAGE>
Whether a Participant's termination of employment is by reason of Participant's
Disability or retirement shall be determined by the Plan Administrator in its
sole discretion.
6.4 DISCRETIONARY VESTING
The Employer may, in its sole discretion, accelerate the vesting of all or any
portion of the Accounts of any Participant or all Participants.
6.5 INSOLVENCY
A Participant shall become fully vested in his or her Account immediately prior
to the Employer's becoming Insolvent, in which case the Participant will have
the same rights as a general creditor of the Employer with respect to his or her
Account Balance.
ARTICLE 7 - PAYMENTS
7.1 ELECTION AS TO TIME AND FORM OF PAYMENT
A Participant shall elect (on the Election Form used to elect to defer
Compensation under Section 4.1) the date at which the Elective Deferrals and
vested Matching Deferrals (including any earnings attributable thereto) will
commence to be paid to the Participant. The Participant shall also elect
thereon for payments to be paid in either:
a: a single lump-sum payment; or
b. annual or monthly installments over a period elected by the Participant up
to 10 years, the amount of each installment to equal the balance of his or
her Account immediately prior to the installment divided by the number of
installments remaining to be paid.
Each such election will be effective for the Plan Year for which it is made and
succeeding Plan Years, unless changed by the Participant. Any change will be
effective only for Elective Deferrals and Matching Deferrals made for the first
Plan Year beginning after the date on which the Election Form containing the
change is filed with the Plan Administrator. Except as provided in Sections
7.2, 7.3, 7.4, or 7.5, payment of a Participant's Account shall be made in
accordance with the Participant's elections under this Section 7.1.
7.2 CHANGE OF CONTROL
A Participant may elect on the Election Form that, in the event of a Change of
Control, the Participant's entire Account balance (including any amount vested
pursuant to Section 6.2) will either (a) be paid to the Participant in a single
lump sum as soon as possible following any Change of Control of the Employer or
(b) be paid to the Participant in a single lump sum as soon as possible
following a Change of Control of the Employer unless, prior to the Change of
Control, a majority of the members of the Board of Directors of the Employer who
are not Participants in the Plan determines that the Change of Control would not
reasonably be expected to increase materially the economic risk of Participants
who remain in the Plan or (c) be paid in accordance with the other provisions of
<PAGE>
the Plan without regard to any Change of Control. Unless the Participant shall
have elected otherwise on the Election Form, as soon as possible following a
Change of Control of the Employer, each Participant shall be paid his or her
entire Account balance (including any amount vested pursuant to Section 6.2) in
a single lump sum.
7.3 TERMINATION OF EMPLOYMENT
Unless the Plan Administrator, in its sole discretion, determines otherwise,
upon termination of a Participant's employment for any reason other than death,
Disability and retirement after attainment of the Retirement Age, the vested
portion of the Participant's Account shall be paid to the Participant in a
single lump sum as soon as practicable following the date of such termination.
If the Plan Administrator does determine not to make a lump sum payment to a
Participant under this Section, the Plan Administrator may, in its sole
discretion, determine to pay the vested portion of such Participant's Account in
a single lump sum at any time thereafter.
7.4 DISABILITY
If the Participant's employment terminates by the reason of the Participant's
Disability, the amounts credited to a Participant's Account with respect to any
Plan Year shall be paid out in accordance with the election made in accordance
with Section 7.1 unless the Plan Administrator, in its sole discretion,
determines to pay such amounts in one lump sum or the Participant shall have
elected in such Election Form to receive payment of the remaining balance of
such amounts in one lump sum if his or her employment terminates by reason of
Disability.
7.5 DEATH
If a Participant dies prior to the complete distribution of his or her Account,
the balance of the Account shall be paid as soon as practicable to the
Participant's designated beneficiary or beneficiaries, in the form elected by
the Participant under either of the following options:
a. a single lump-sum payment; or
b. annual or monthly installments over a period elected by the
Participant up to 10 years, the amount of each installment to equal
the balance of the Account immediately prior to the installment
divided by the number of installments remaining to be paid.
Any designation of beneficiary and form of payment to such beneficiary shall be
made by the Participant on an Election Form filed with the Plan Administrator
and may be changed by the Participant at any time by filing another Election
Form containing the revised instructions. If no beneficiary is designated or no
designated beneficiary survives the Participant, payment shall be made to the
Participant's surviving spouse or, if none, to his or her issue per stirpes, in
a single payment. If no spouse or issue survives the Participant, payment shall
be made in a single lump sum to the Participant's estate.
7.6 UNFORESEEN EMERGENCY
<PAGE>
If a Participant suffers an unforeseen emergency, as defined herein, the Plan
Administrator, in its sole discretion, may pay to the Participant only that
portion, if any, of the vested portion of his or her Account which the Plan
Administrator determines is necessary to satisfy the emergency need, including
any amounts necessary to pay any federal, state or local income taxes reasonably
anticipated to result from the distribution. A Participant requesting an
emergency payment shall apply for the payment in writing in a form approved by
the Plan Administrator and shall provide such additional information as the Plan
Administrator may require. For purposes of this paragraph, "unforeseen
emergency" means an immediate and heavy financial need resulting from either of
the following:
a. expenses which are not covered by insurance and which the Participant or
his or her spouse or dependent has incurred as a result of, or is required
to incur in order to receive, medical care; or
b. any circumstance that is determined by the Plan Administrator in its sole
discretion to constitute an unforeseen emergency which is not covered by
insurance and which cannot reasonably be relieved by the liquidation of the
Participant's assets.
7.7 FORFEITURE OF NON-VESTED AMOUNTS
To the extent that any amounts credited to a Participant's Account are not
vested at the time such amounts are otherwise payable under Sections 7.1 or 7.3,
such amounts shall be forfeited and shall, at the option of the Employer, either
be paid to the Employer or used to satisfy the Employer's obligation to make
contributions to the Trust under the Plan.
7.8 TAXES
All federal, state or local taxes that the Plan Administrator determines are
required to be withheld from any payments made pursuant to this Article 7
shall be withheld.
ARTICLE 8 - PLAN ADMINISTRATOR
8.1 PLAN ADMINISTRATION AND INTERPRETATION
The Plan Administrator shall oversee the administration of the Plan. The Plan
Administrator shall have complete control and authority to determine the rights
and benefits and all claims, demands and actions arising out of the provisions
of the Plan of any Participant, beneficiary, deceased Participant, or other
person having or claiming to have any interest under the Plan. The Plan
Administrator shall have complete discretion to interpret the Plan to decide all
matters under the Plan. Such interpretation and decision shall be final,
conclusive and binding on all Participants and any person claiming under or
through any Participant, in the absence of clear and convincing evidence that
the Plan Administrator acted arbitrarily and capriciously. Any individual(s)
serving as Plan Administrator who is a Participant will not vote or act on any
matter relating solely to himself or herself. When making a determination or
<PAGE>
calculation, the Plan Administrator shall be entitled to rely on information
furnished by a Participant, a beneficiary, the Employer or the Trustee. The
Plan Administrator shall have the responsibility for complying with any
reporting and disclosure requirements or ERISA.
8.2 POWERS, DUTIES, PROCEDURES, ETC.
The Plan Administrator shall have such powers and duties, may adopt such rules
and tables, may act in accordance with such procedures, may appoint such
officers or agents, may delegate such powers and duties, may receive such
reimbursements and compensation, and shall follow such claims and appeal
procedures with respect to the Plan as it may establish.
8.3 INFORMATION
To enable the Plan Administrator to perform its functions, the Employer shall
supply full and timely information to the Plan Administrator on all matters
relating to the compensation of Participants, their employment, retirement,
death, termination or employment, and such other pertinent facts as the Plan
Administrator may require.
8.4 INDEMNIFICATION OF PLAN ADMINISTRATOR
The Employer agrees to indemnify and to defend to the fullest extent permitted
by law any officer(s) or employee(s) who serve as Plan Administrator (including
any such individual who formerly served as Plan Administrator) against all
liabilities, damages, costs and expenses (including attorneys' fees and amounts
paid in settlement of any claims approved by the Employer) occasioned by any act
or omission to act in connection with the Plan, if such act or omission is in
good faith.
ARTICLE 9 - AMENDMENT AND TERMINATION
9.1 AMENDMENTS
The Employer, upon action of its Board of Directors or an authorized committee
thereof, shall have the right to amend the Plan from time to time, subject to
Section 9.3, by an instrument in writing which has been executed on the
Employer's behalf by its duly authorized officer.
9.2 TERMINATION OF PLAN
This Plan is strictly a voluntary undertaking on the part of the Employer and
shall not be deemed to constitute a contract between the Employer and any
Eligible Employee (or any other employee) or a consideration for, or an
inducement or condition of employment for, the performance of the services by
any Eligible Employee (or other employee). The Employer reserves the right to
terminate the Plan at any time, subject to Section 9.3, by an instrument in
writing which has been executed on the Employer's behalf by its duly authorized
officer. Upon termination, the Employer may (a) elect to continue to maintain
the Trust to pay benefits hereunder as they become due as if the Plan had not
terminated or (b) direct the Trustee to pay promptly to Participants (or their
beneficiaries) the vested balance of their Accounts. For purposes of the
preceding sentence, in the event the Employer chooses to implement clause (b),
<PAGE>
the Account balances of all Participants who are in the employ of the Employer
at the time the Trustee is directed to pay such balances shall become fully
vested and nonforfeitable. After Participants and their beneficiaries are paid
all Plan benefits to which they are entitled, all remaining assets of the Trust
attributable to Participants who terminated employment with the Employer prior
to termination of the Plan who were not fully vested in their Accounts under
Article 6 at that time, shall be returned to the Employer.
9.3 EXISTING RIGHTS
No amendment or termination of the Plan shall adversely affect the rights of any
Participant with respect to amounts that have been credited to his or her
Account prior to the date of such amendment or termination.
ARTICLE 10 - MISCELLANEOUS
10.1 NO FUNDING
The Plan constitutes a mere promise by the Employer to make payments in
accordance with the terms of the Plan and Participants and beneficiaries shall
have the status of general unsecured creditors of the Employer. Nothing in the
Plan will be construed to give any employee or any other person rights to any
specific assets of the Employer or of any other person. In all events, it is
the intent of the Employer that the Plan be treated as unfunded for tax purposes
and for purposes of Title 1 of ERISA.
10.2 NON-ASSIGNABILITY
None of the benefits, payments, proceeds or claims of any Participant or
beneficiary shall be subject to any claim of any creditor of any Participant or
beneficiary and, in particular, the same shall not be subject to attachment or
garnishment or other legal process by any creditor of such Participant or
beneficiary, nor shall any Participant or beneficiary have any right to
alienate, anticipate, commute, pledge, encumber or assign any of the benefits or
payments or proceeds which he or she may expect to receive, contingently or
otherwise, under the Plan.
10.3 LIMITATION OF PARTICIPANTS' RIGHTS
Nothing contained in the Plan shall confer upon any person a right to be
employed or to continue in the employ of the Employer, or interfere in any way
with the right of the Employer to terminate the employment of an Participant in
the Plan any time, with or without cause.
10.4 PARTICIPANTS BOUNG
Any action with respect to the Plan taken by the Plan Administrator or the
Employer or the Trustee or any action authorized by or taken at the direction of
the Plan Administrator, the Employer or the Trustee shall be conclusive upon all
Participants and beneficiaries entitled to benefits under the Plan.
10.5 RECEIPT AND RELEASE
Any payment to any Participant or beneficiary in accordance with the provisions
<PAGE>
of the Plan shall, to the extent thereof, be in full satisfaction of all claims
against the Employer, the Plan Administrator and the Trustee under the Plan, and
the Plan Administrator amy require such Participant or beneficiary, as a
condition precedent to such payment, to execute a receipt and release to such
effect. If any Participant or beneficiary is determined by the Plan
Administrator to be incompetent by reason or physical or mental disability
(including minority) to give a valid receipt and release, the Plan Administrator
may cause the payment or payments becoming due to such person to be made to
another person for his or her benefit without responsibility on the part of the
Plan Administrator, the Employer or the Trustee to follow the application of
such funds.
10.6 PLAN DOES NOT AFFECT EMPLOYMENT RIGHTS
The Plan does not provide any employment rights to any Eligible Employee or
Participant. The Employer expressly reserves the right to discharge an Employee
or to increase or decrease the salary or Compensation of an Employee at any
time, with or without cause and with or without prior notice, without regard to
the effect such discharge would have on the Employee's interest in the Plan.
10.7 GOVERNING LAW
The Plan shall be construed, administered, and governed in all respects under
and by the laws of the state of Colorado. If any provision shall be held by a
court of competent jurisdiction to be invalid or unenforceable, the remaining
provisions hereof shall continue to be fully effective.
10.8 HEADINGS AND SUBHEADINGS
Headings and subheadings in this Plan are inserted for convenience only and are
not to be considered in the construction of the provisions hereof.
<PAGE>
EXHIBIT 11
PATINA OIL & GAS CORPORATION
COMPUTATION OF NET INCOME PER SHARE
FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
1994 1995 1996
------- --------- --------
<S> <C> <C> <C>
PRIMARY NET INCOME (LOSS) PER SHARE:
Net income (loss) $ 2,950 $(2,094) $ 3,562
Dividends on preferred stock - - (2,129)
------- ------- -------
Net income (loss) available to common $ 2,950 $(2,094) $ 1,433
======= ======= =======
Weighted average shares outstanding 14,000 14,000 17,787
Add common stock equivalents - - 9
------- ------- -------
Weighted average common stock and
equivalents outstanding 14,000 14,000 17,796
Net income (loss) applicable to common $ 0.21 $ (0.15) $0.08
======= ======= =======
FULLY DILUTED NET INCOME (LOSS) PER SHARE:
Net income (loss) $ 2,950 $(2,094) $ 3,562
Dividends on preferred stock - - -
------- ------- -------
Net income (loss) available to common $ 2,950 $(2,094) $ 3,562
======= ======= =======
Weighted average shares outstanding 14,000 14,000 17,787
Add common stock equivalents - - 9
Other potentially dilutive securities - - 3,085
------- ------- -------
Weighted average common stock
and equivalents outstanding 14,000 14,000 20,881
Net income (loss) applicable to common $ 0.21 $ (0.15) $0.17
======= ======= =======
</TABLE>
Note: Fully diluted net income (loss) per share for 1994, 1995 and 1996 are not
shown in the financial statements as the fully diluted net income (loss) per
share equaled primary earnings per share in 1994 and 1995 and the fully diluted
net income (loss) per share in 1996 was anti-dulutive. Therefore, only primary
net income per share is disclosed in the financial statements.
<PAGE>
EXHIBIT 12
PATINA OIL & GAS CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO
COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS
(UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1992 1993 1994 1995 1996
------- ------- ------ --------- -------
(dollars in thousands, except ratios)
<S> <C> <C> <C> <C> <C>
Net income (loss) before taxes $10,574 $20,831 $4,539 $(3,222) $ 3,168
Interest expense 1,771 2,362 3,869 5,409 14,275
------- ------- ------ ------- -------
Earnings before fixed charges $12,345 $23,193 $8,408 $ 2,187 $17,443
======= ======= ====== ======= =======
Preferred dividends - - - - $ 2,129
Ratio of pretax income to net income 1.54 1.54 1.54 1.54 0.89
------- ------- ------ ------- -------
Preferred dividend factor - - - - $ 1,895
Fixed charges:
Interest expense 1,771 2,362 3,869 5,409 14,275
Preferred dividend factor - - - - 1,895
------- ------- ------ ------- -------
Total fixed charges and
Preferred dividend $ 1,771 $ 2,362 $3,869 $ 5,409 $16,170
======= ======= ====== ======= =======
Ratio of earnings to combined fixed
charges and preferred dividends 6.97 9.82 2.17 0.40 1.08
======= ======= ====== ======= =======
</TABLE>
<PAGE>
EXHIBIT 12.1
PATINA OIL & GAS CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO
FIXED CHARGES
(UNAUDITED)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1992 1993 1994 1995 1996
------- ------- ------ --------- -------
(dollars in thousands, except ratios)
<S> <C> <C> <C> <C> <C>
Net income (loss) before taxes $10,574 $20,831 $4,539 $(3,222) $ 3,168
Interest expense 1,771 2,362 3,869 5,409 14,275
------- ------- ------ ------- -------
Earnings before fixed charges $12,345 $23,193 $8,408 $ 2,187 $17,443
======= ======= ====== ======= =======
Fixed charges:
Interest expense 1,771 2,362 3,869 5,409 14,275
------- ------- ------ ------- -------
Total fixed charges $ 1,771 $ 2,362 $3,869 $ 5,409 $14,275
======= ======= ====== ======= =======
Ratio of earnings to fixed charges 6.97 9.82 2.17 0.40 1.22
======= ======= ====== ======= =======
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 6,153
<SECURITIES> 0
<RECEIVABLES> 19,977
<ALLOWANCES> 0
<INVENTORY> 1,324
<CURRENT-ASSETS> 27,587
<PP&E> 565,493
<DEPRECIATION> 165,349
<TOTAL-ASSETS> 430,233
<CURRENT-LIABILITIES> 26,572
<BONDS> 197,594
0
16
<COMMON> 189
<OTHER-SE> 196,031
<TOTAL-LIABILITY-AND-EQUITY> 430,233
<SALES> 82,185
<TOTAL-REVENUES> 83,188
<CGS> 53,689
<TOTAL-COSTS> 65,492
<OTHER-EXPENSES> 224
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 14,275
<INCOME-PRETAX> 3,168
<INCOME-TAX> (394)
<INCOME-CONTINUING> 3,562
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,562
<EPS-PRIMARY> .08
<EPS-DILUTED> .08
</TABLE>
<PAGE>
EXHIBIT 99
February 5, 1997
Patina Oil & Gas Corporation
1625 Broadway, Suite 2000
Denver, Colorado 80202
Gentlemen:
In accordance with your request, we have estimated the proved reserves and
future revenue, as of December 31, 1996, to the Patina Oil & Gas Corporation
(Patina) interest in certain oil and gas properties located in Colorado. As
requested, lease and well operating costs do not include the per-well overhead
expenses allowed under joint operating agreements for those properties operated
by Patina. This report has been prepared using constant prices and costs and
conforms to the guidelines of the Securities and Exchange Commission (SEC).
As presented in the accompanying summary projections, Tables I through IV,
we estimate the net reserves and future net revenue to the Patina interest, as
of December 31, 1996, to be:
Net Reserves Future Net Reserves
------------------------ -------------------------------
Oil Gas Present Worth
Category (Barrels) (MCF) Total at 10%
- ---------------- ---------- ----------- -------------- ------------
Proved Developed
Producing 12,971,418 206,872,544 $ 824,044,600 $500,440,700
Non-Producing 2,827,690 35,904,440 156,219,400 81,966,600
Proved Undeveloped 6,676,152 53,882,147 188,602,900 66,389,200
---------- ----------- -------------- ------------
Total Proved 22,475,260 296,659,131 $1,168,866,900 $648,796,500
The oil reserves shown include crude oil and condensate. Oil volumes are
expressed in barrels which are equivalent to 42 United States gallons. Gas
volumes are expressed in thousands of standard cubic feet (MCF) at the contract
temperature and pressure bases.
As shown in the Table of Contents, this report includes summary projections
of reserves and revenue for each reserve category along with one-line summaries
of reserves, economics, and basic data by lease. For the purposes of this
report, the term "lease" refers to a single economic projection.
The estimated reserves and future revenue shown in this report are for
proved developed producing, proved developed non-producing, and proved
undeveloped reserves. In accordance with SEC guidelines, our estimates do not
include any value for probable or possible reserves which may exist for these
properties. This report does not include any value which could be attributed to
interests in undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated.
Future gross revenue to the Patina interest is prior to deducting state
production taxes and ad valorem taxes. Future net revenue is after deducting
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these taxes, future capital costs, and operating expenses, but before
consideration of federal income taxes. In accordance with SEC guidelines, the
future net revenue has been discounted at an annual rate of 10 percent to
determine its "present worth." The present worth is shown to indicate the
effect of time on the value of money and should not be construed as being the
fair market value of the properties.
For the purposes of this report, a field inspection of the properties has
not been performed nor has the mechanical operation or condition of the wells
and their related facilities been examined. We have not investigated possible
environmental liability related to the properties; therefore, our estimates do
not include any costs which may be incurred due to such possible liability.
Also, our estimates do not include any salvage value for the lease and well
equipment nor the cost of abandoning the properties.
Oil prices used in this report are based on a December 31, 1996 West Texas
Intermediate posted price of $24.25 per barrel, adjusted by lease for gravity,
transportation fees, and regional posted price differentials. Gas prices used
in this report are the average December 1996 prices for each pipeline. Oil and
gas prices are held constant in accordance with SEC guidelines.
Lease and well operating costs are based on operating expense records of
Patina. For non-operated properties, these costs include the per-well overhead
expenses allowed under joint operating agreements along with costs estimated to
be incurred at and below the district and field levels. As requested, lease and
well operating costs for the operated properties include only direct lease and
field level costs. Headquarters general and administrative overhead expenses of
Patina are not included. Lease and well operating costs are held constant in
accordance with SEC guidelines. Capital costs are included as required for
workovers, new development wells, and production equipment.
We have made no investigation of potential gas volume and value imbalances
which may have resulted from overdelivery or underdelivery to the Patina
interest. Therefore, our estimates of reserves and future revenue do not
include adjustments for the settlement of any such imbalances; our projections
are based on Patina receiving its net revenue interest share of estimated future
gross gas production.
The reserves included in this report are estimates only and should not be
construed as exact quantities. They may or may not be recovered; if recovered,
the revenues therefrom and the costs related thereto could be more or less than
the estimated amounts. The sales rates, prices received for the reserves, and
costs incurred in recovering such reserves may vary from assumptions included in
this report due to governmental policies and uncertainties of supply and demand.
Also, estimates of reserves may increase or decrease as a result of future
operations.
In evaluating the information at our disposal concerning this report, we
have excluded from our consideration all matters as to which legal or
accounting, rather than engineering and geological, interpretation may be
controlling. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and geological data;
therefore, our conclusions necessarily represent only informed professional
judgements.
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The titles to the properties have not been examined by Netherland, Sewell &
Associates, Inc., nor has the actual degree or type of interest owned been
independently confirmed. The data used in our estimates were obtained from
Patina Oil & Gas Corporation and the nonconfidential files of Netherland, Sewell
& Associates, Inc. and were accepted as accurate. We are independent petroleum
engineers, geologists, and geophysicists; we do not own an interest in these
properties and are not employed on a contingent basis. Basic geologic and field
performance data together with our engineering work sheets are maintained on
file in our office.
Very truly yours,
/s/ Frederic D. Sewell
