ITEM 1. BUSINESS
General
Patina Oil & Gas Corporation ("Patina" or the "Company") is an independent energy company engaged in the acquisition, development, exploitation and production of oil and natural gas. The Company's properties and oil and gas reserves are predominantly located in the Wattenberg Field ("Wattenberg" or the "Field") of Colorado's Denver-Julesburg Basin ("D-J Basin"). Patina is one of the largest producers in the Field, currently accounting for over 30% of its production. Wattenberg is one of the ten largest natural gas fields in the U.S. Since its discovery in 1970, cumulative production exceeds three trillion cubic feet of natural gas equivalents. The Field is located approximately 35 miles northeast of Denver and stretches over portions of Adams, Boulder and Weld Counties. One of Wattenberg's most attractive features is that it contains eight potentially productive formations at depths ranging from 2,000 to 8,000 feet. Three of the formations, the Codell, the Niobrara and the J-Sand, are "blanket" zones in the area of the Company's holdings. Other formations, including the Sussex, Shannon and Dakota are more localized. The existence of several pay sands allows for multiple completions within a single wellbore, reducing drilling risks and operating costs.
The Company was formed in 1996 to hold the Wattenberg assets of Snyder Oil Corporation ("SOCO") and to facilitate the acquisition of SOCO's then largest competitor in the Field, Gerrity Oil & Gas Corporation ("Gerrity"). In the Gerrity acquisition, SOCO retained 14.0 million shares of the Company's common stock and Gerrity's shareholders received 6.0 million shares of common stock, $40.0 million of 7.125% convertible preferred stock and 3.0 million $12.50 common stock warrants. In 1997, a series of transactions eliminated SOCO's ownership in the Company. The 7.125% preferred stock was fully retired in January 2000 and the $12.50 warrants will expire on May 2, 2001.
Through Elysium Energy, L.L.C. ("Elysium"), a limited liability company in which the Company holds a 50% interest, Patina acquired various property interests out of bankruptcy in November 2000. Patina invested $21.0 million to acquire 50% of Elysium and provided it with a $60.0 million credit facility, on which $49.0 million was outstanding at year-end. The Company's 50% interest in Elysium's assets, liabilities, revenues and expenses is proportionately consolidated in its financial statements. Elysium's oil and gas properties are located primarily in central Kansas, the Illinois Basin, the San Joaquin Basin of California, and the Lake Washington Field of Louisiana. Approximately 90% of Elysium's production is oil.
At December 31, 2000, the Company had 777.8 Bcfe of proved reserves, of which Wattenberg represented 704.8 Bcfe or 91%. The reserves had an estimated pretax present value of $2.2 billion based on unescalated prices and costs in effect on that date. Approximately 67% of the reserves on a Mcf equivalent basis were natural gas and over 84% of the pretax present value was attributable to proved developed reserves. The Company operates over 95% of the roughly 3,300 producing wells in which it holds a direct working interest in Wattenberg. At December 31, 2000, the Company's inventory of proven development projects included 563 drilling or deepening locations, 291 recompletions and 1,849 restimulation ("refrac") projects in Wattenberg. During 2000, the Company's production averaged 119.0 MMcfe per day, of which 117.7 MMcfe per day or 99% was attributed to Wattenberg. Based on year-end reserves and calculating production as if Elysium had been acquired in January 2000, the Company had a reserve life index of 14.5 years.
From inception, the Company has focused on consolidating ownership of its properties, developing an efficient organization, reducing costs and improving operations. In 2000, revenues and net cash provided from operations totaled $150.3 million and $109.4 million, respectively. This operating cash flow, combined with $45.0 million of bank borrowings, funded $40.3 million of capital expenditures, $21.0 million to acquire 50% of Elysium and $42.1 million of equity repurchases. In addition, the Company loaned $53.0 million to Elysium, an amount that was reduced to $49.0 million by year-end. Capital expenditures funded the drilling or deepening of 57 J-Sand wells, performing 193 refracs, nine recompletions and drilling three Codell wells in Wattenberg. These projects, the Elysium purchase and continued success in production enhancement allowed production to increase 11% over the prior year. Total proved reserves increased 67% or 312 Bcfe, with 270 Bcfe gained through ongoing Wattenberg development, acquisitions net of sales adding 70 Bcfe (largely the Elysium transaction) and upward revisions due to higher prices contributing 16 Bcfe.
Future Wattenberg activity will focus primarily on refracing existing Codell wells and the development of J-Sand reserves through drilling new wells or deepening within existing wellbores. These projects, the still to be realized potential of the Elysium acquisition and continued success in production enhancement should result in additional increases in production and proved reserves in 2001.
The purchase of Elysium in November 2000 marked the beginning of a more aggressive diversification effort. The acquisition provided the Company a presence in several areas believed to have significant growth and consolidation potential, including the Illinois Basin, the San Joaquin Basin of California and central Kansas. The Company is actively accumulating acreage in preparation for launching two grassroots drilling projects in the Rockies, which could have significant long-term potential.
Business Strategy
The Company's sizable asset base and cash flow, along with its low production costs and efficient operating structure, provide it with a competitive advantage in Wattenberg and in certain analogous basins. These advantages, combined with management's operational expertise, positions the Company to increase its reserves, production and cash flows in a cost-efficient manner primarily through: (i) further Wattenberg development; (ii) generation of grassroots drilling prospects, and (iii) selectively pursuing consolidation and acquisition opportunities. The size and timing of such purchases will depend on market conditions. The Company's strong financial position appears to afford it the financial flexibility to execute this strategy.
Production, Revenue and Price History
The following table sets forth information regarding oil and natural gas production, revenues and direct operating expenses attributable to such production, average sales prices and other related data for the last five years. The information reflects the acquisition of Gerrity in May 1996 and the acquisition of 50% of Elysium in November 2000.
- ------------------------------ (a) Oil production is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf. (b) Sales of natural gas liquids are included in gas revenues.
Marketing
The Company's oil and natural gas production is principally sold to end users, marketers, refiners and other purchasers having access to pipeline facilities or the ability to truck oil to local refineries. The marketing of oil and natural gas can be affected by a number of factors that are beyond the Company's control and which cannot be accurately predicted. However, the Company does not believe the loss of any single customer 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 to extract natural gas liquids ("NGL"). Residue gas is sold to utilities, independent marketers and end users through intrastate and interstate pipelines. The Company utilizes two separate arrangements to gather, process and market its natural gas production. Approximately 30% of production is sold to Duke Energy Field Services ("Duke Energy") at the wellhead under percentage of proceeds contracts. Pursuant to this type of contract, the Company receives a fixed percentage of the proceeds from Duke Energy's sale of residue gas and NGL's. Substantially all of the Company's remaining natural gas production is dedicated for gathering to Duke Energy or HS Gathering, LLC ("HSG") and is processed at plants owned by Duke Energy or BP Amoco Production Company ("BP Amoco"). Under this arrangement, the Company retains the right to market its share of residue gas at the tailgate of the plant and sells it under spot market arrangements along the front range of Colorado or transports it to Midwestern markets under transportation agreements. NGL's are sold by the processor and the Company receives payment net of applicable processing fees. A portion of the natural gas processed by BP Amoco at the Wattenberg Processing Plant is under a favorable "keepwhole" contract that not only provides payment for a percentage of the NGL's stripped from the natural gas, but also redelivers at the tailgate the same amount of MMBtu's as was delivered to the plant. This agreement extends through December 2012.
Oil. Oil production is principally sold to refiners, marketers and other purchasers that truck it to local refineries or pipelines. The price is based on a local market posting, which generally approximates a West Texas Intermediate posting, and is adjusted upward to reflect local demand and quality. BP Amoco has the right to purchase oil produced from certain of the Company's properties.
Competition
The oil and natural gas industry is highly competitive. The Company encounters competition in all of its operations, including the acquisition of exploration and development prospects and producing properties. Patina competes for acquisitions of oil and natural gas properties with numerous entities, including major oil companies, other independents, and individual producers and operators. Many competitors have financial and other resources substantially greater than those of the Company. The ability of the Company to increase reserves in the future will be dependent on its ability to select and successfully acquire suitable producing properties and prospects for future development and exploration.
Title to Properties
Title to the Company's oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the industry, to liens incident to operating agreements and for current taxes not yet due and other comparatively minor encumbrances. As is customary in the oil and natural gas industry, only a perfunctory investigation as to ownership is conducted at the time undeveloped properties are acquired. Prior to the commencement of drilling operations, a detailed title examination is conducted and curative work is performed with respect to identified title defects.
Regulation
Regulation of Drilling and Production. The Company's operations are affected by political developments and by federal, state and local laws and regulations. Legislation and administrative regulations relating to the oil and natural gas industry are periodically changed for a variety of political, economic and other reasons. Numerous federal, state and local departments and agencies issue rules and regulations binding on the oil and natural gas industry, some of which carry substantial penalties for failure to comply. The regulatory burden on the industry increases the cost of doing business, decreases flexibility in the timing of operations and may adversely affect the economics of capital projects.
In the past, the federal government has regulated the prices at which oil and natural gas could be sold. Prices of oil and natural gas sold by the Company are not currently regulated. In recent years, the Federal Energy Regulatory Commission ("FERC") has taken significant steps to increase competition in the sale, purchase, storage and transportation of natural gas. FERC's regulatory programs allow more accurate and timely price signals from the consumer to the producer and, on the whole, have helped natural gas become more responsive to changing market conditions. To date, the Company believes it has not experienced any material adverse effect as the result of these initiatives. Nonetheless, increased competition in natural gas markets can and does add to price volatility and inter-fuel competition, which increases the pressure on the Company to manage its exposure to changing conditions and position itself to take advantage of changing markets.
State statutes govern exploration and production operations, conservation of oil and natural gas resources, protection of the correlative rights of oil and natural gas owners and environmental standards. State Commissions implement their authority by establishing rules and regulations requiring permits for drilling, reclamation of production sites, plugging bonds, reports and other matters. Colorado, where the Company's producing properties are primarily located, amended its statute concerning oil and natural gas development in 1994 to provide the Colorado Oil & Gas Conservation Commission (the "COGCC") with enhanced authority to regulate oil and natural gas activities to protect public health, safety and welfare, including the environment. The COGCC has implemented several rules pursuant to these statutory changes 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 the operations of the Company, as the COGCC is required to enact cost-effective and technically feasible regulations, and the Company has been an active participant in their development. However, there can be no assurance that, in the aggregate, these and other regulatory developments will not increase the cost of operations in the future.
In Colorado, a number of city and county governments have enacted oil and natural gas regulations. These ordinances increase the involvement of local governments in the permitting of oil and natural gas operations, and require additional restrictions or conditions on the conduct of operations so as to reduce their impact on the surrounding community. Accordingly, these local ordinances have the potential to delay and increase the cost of drilling, refracing and recompletion operations.
Environmental Regulation. The Company's operations 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 oil and natural gas 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 in Colorado, which enable it to treat, bioremediate and otherwise dispose of tank sludges and contaminated soil generated from the Company's Colorado operations. There can be no assurance that these facilities, or other commercial disposal facilities utilized 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. 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 operating costs and the oil and gas industry in general.
Office and Operations Facilities
The Company leases its principal executive offices at 1625 Broadway, Denver, Colorado 80202. The lease covers approximately 29,000 square feet and expires in November 2005. The monthly rent is approximately $43,000, increasing to approximately $60,000 in December 2001. The Company owns a 6,000 square foot production facility in Platteville, Colorado used to support its Wattenberg Field operations.
Elysium leases its principal executive offices at 10077 Grogans Mill Road, The Woodlands, Texas 77380. The lease covers approximately 20,000 square feet of office space and expires in November 2001. The monthly rent is approximately $31,000 ($15,500 net to Patina). Elysium maintains six field offices in the areas of its operations.
Employees
On December 31, 2000, the Company had 160 employees, including 97 that work in its field office. An additional 139 employees work for Elysium. None of these employees are represented by a labor union. The Company believes its relationship with its employees is satisfactory.
Directors and Executive Officers
The following table sets forth-certain information about the officers and directors of the Company:
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Thomas J. Edelman founded the Company and has served as Chairman of the Board and Chief Executive Officer since its formation. He co-founded SOCO and was its President from 1981 through early 1997. From 1980 to 1981, he was with The First Boston Corporation and from 1975 through 1980, with Lehman Brothers Kuhn Loeb Incorporated. Mr. Edelman received his Bachelor of Arts Degree from Princeton University and his Masters Degree in Finance from Harvard University's Graduate School of Business Administration. Mr. Edelman serves as Chairman of Range Resources Corporation and Bear Paw Energy LLC, and is a Director of Star Gas Corporation and Wellogix, Inc.
Jay W. Decker has served as President since March 1998 and as a Director since 1996. He had been the Executive Vice President and a Director of Hugoton Energy Corporation, a public independent oil company since 1995. From 1989 until its merger into Hugoton Energy, Mr. Decker was the President and Chief Executive Officer of Consolidated Oil & Gas, Inc., a private independent oil company 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 with 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.
David J. Kornder has served as Executive Vice President and Chief Financial Officer since 1996. Prior to that time, he served as Vice President - Finance of Gerrity beginning in early 1993. From 1989 through 1992, Mr. Kornder was an Assistant Vice President of Gillett Group Management, Inc. Prior to that, Mr. Kornder was an accountant with the independent accounting firm of Deloitte & Touche for five years. Mr. Kornder received his Bachelor of Arts Degree in Accounting from Montana State University. Mr. Kornder serves as a Director of the Colorado Oil & Gas Association.
John M. Stafford has served as Vice President and General Counsel since February 2001. From 1998 to January 2001, Mr. Stafford was an attorney with Holme Roberts and Owen, LLP. Mr. Stafford worked as an attorney for Holland & Hart, LLP from 1997 to 1998 and for Michael Best & Friedrich, LLP from 1996 to 1997. Prior to becoming an attorney, he was a Senior Geologist with ARCO Oil and Gas Company from 1982 to 1993. Mr. Stafford received his Bachelor of Science Degree in Geology from Syracuse University, his Master of Science Degree in Geological Oceanography from Texas A&M University and his Juris Doctorate Degree from the University of Denver. Mr. Stafford also serves as an ex-officio Director of the Association of International Petroleum Negotiators.
Barton R. Brookman has served as a Vice President of Operations since January 2001. From 1996 to 2000, Mr. Brookman was the District Operations Manager for the Company. From 1988 to 1996, Mr. Brookman was a District Operations Manager for SOCO. From 1986 to 1988, Mr. Brookman was a Petroleum Engineer for Ladd Petroleum Corporation, an affiliate of General Electric. Mr. Brookman received his Bachelor of Science Degree in Petroleum Engineering from the Colorado School of Mines and his Master of Science - Finance Degree from the University of Colorado, Denver.
James A. Lillo has served as a Vice President since 1998. From 1995 to 1998, Mr. Lillo was President of James Engineering, Inc., an independent petroleum engineering consulting firm. Previously, he served as Vice President of Engineering for Consolidated Oil & Gas, Inc., until its merger into Hugoton Energy Corporation, and President of a predecessor operating company since 1989. Prior to 1989, Mr. Lillo worked as an engineering consultant and as Manager of Reservoir Engineering for Hart Exploration and in various engineering capacities with Champlin Petroleum Company and Shell Oil Company. Mr. Lillo received his Bachelor of Science Degree in Chemical and Petroleum Refining Engineering from the Colorado School of Mines and is a Registered Professional Engineer.
Terry L. Ruby has served as a Vice President since 1996. Prior to that time, Mr. Ruby served as a senior landman of Gerrity beginning in 1992 and was appointed Vice President - Land in 1995. From 1990 to 1992, Mr. Ruby worked for Apache Corporation and from 1982 to 1990, he was employed by Baker Exploration Company. Mr. Ruby received his Bachelor of Science Degree in Minerals Land Management from the University of Colorado and his M.B.A. from the University of Denver.
David W. Siple has served as a Vice President since 1996. He joined SOCO's land department in 1994 and was appointed a Land Manager in 1995. From 1990 through May 1994, Mr. Siple was the Land Manager of Gerrity. From 1981 through 1989, Mr. Siple was employed by PanCanadian Petroleum Company in the Land Department. Mr. Siple received his Bachelor of Science Degree in Minerals Land Management from the University of Colorado.
Christopher C. Behrens has served as a Director since 1999. Mr. Behrens has been a general partner at J.P. Morgan Partners (formerly Chase Capital Partners) since 1999 and a principal since 1994. Prior to assuming that position, Mr. Behrens was a Vice President in the Chase Manhattan Corporation's Merchant Banking Group. He received his Bachelor of Arts from the University of California at Berkeley and his M.B.A. from Columbia University. Mr. Behrens also serves as a Director of Portola Packaging, Carrizo Oil and Gas, Domino's Pizza, PDI, as well as other private companies, including Bear Paw Energy LLC.
Robert J. Clark has served as a Director since 1996. Mr. Clark is the President of Bear Paw Energy LLC, a private gas gathering and processing company. Mr. Clark formed a predecessor company, Bear Paw Energy Inc., in 1995. From 1988 to 1995, he was President of SOCO Gas Systems, Inc. and Vice President -Gas Management for SOCO. Mr. Clark was Vice President Gas Gathering, Processing and Marketing of Ladd Petroleum Corporation, an affiliate of General Electric from 1985 to 1988. Prior to 1985, Mr. Clark held various management positions with NICOR, Inc. and its affiliate NICOR Exploration, Northern Illinois Gas and Reliance Pipeline Company. Mr. Clark received his Bachelor of Science Degree from Bradley University and his M.B.A. from Northern Illinois University.
Elizabeth K. Lanier has served as a Director since 1998. Mrs. Lanier has served as Vice President and General Counsel of General Electric Power Systems since 1998. From 1996 to 1998, Mrs. Lanier served as Vice President and Chief of Staff of Cinergy Corp. Mrs. Lanier received her Bachelor of Arts Degree with honors from Smith College and her Juris Doctor from Columbia Law School where she was a Harlan Fiske Stone Scholar. Mrs. Lanier was awarded an Honorary Doctorate of Technical Letters by Cincinnati Technical College and an Honorary Doctorate of Letters from the College of Mt. St. Joseph. From 1982 to 1984 she was an associate with Frost & Jacobs, a law firm in Cincinnati, Ohio and a partner from 1984 to 1996. From 1977 to 1982 she was with the law firm of Davis Polk & Wardwell in New York City. She is immediate past Chair of the Ohio Board of Regents.
Alexander P. Lynch has served as a Director since 1996. Mr. Lynch has been a Managing Director of J.P. Morgan & Company, a subsidiary of JPMorganChase, Inc., since July 2000. From 1997 to July 2000, Mr. Lynch was a General Partner of The Beacon Group, a private investment and financial advisory firm, which was merged with Chase Securities in July 2000. From 1995 to 1997, Mr. Lynch was Co- President and Co-Chief Executive Officer of The Bridgeford Group, a financial advisory firm, which was merged into the Beacon Group. From 1991 to 1994, he served as Senior Managing Director of Bridgeford. From 1985 until 1991, Mr. Lynch was a Managing Director of Lehman Brothers, a division of Shearson Lehman Brothers Inc. Mr. Lynch received his Bachelor of Arts Degree from the University of Pennsylvania and his M.B.A. from the Wharton School of Business at the University of Pennsylvania. Mr. Lynch also serves as a Director of Range Resources Corporation.
ITEM 2.
ITEM 2. PROPERTIES
General
The Company's reserves are concentrated in the Wattenberg Field, which is located in the D-J Basin of north central Colorado. Discovered in 1970, the Field is located approximately 35 miles northeast of Denver and stretches over portions of Adams, Boulder and Weld counties in Colorado. One of the most attractive features of Wattenberg is the presence of several productive formations. In a section only 4,500 feet thick, there are up to eight potentially productive formations. Three of the formations, the Codell, Niobrara and J-Sand, are considered "blanket" zones in the area of the Company's holdings, while others, such as the D-Sand, Dakota and the shallower Shannon, Sussex and Parkman, are more localized.
Drilling in Wattenberg is considered low risk from the perspective of finding oil and gas reserves, with better than 95% of the wells drilled being completed as producers. In May 1998, the Colorado Oil & Gas Commission adopted new spacing rules for the Wattenberg Field that greatly enhanced the Company's ability to more efficiently develop its properties. The rule also eliminated costly and time-consuming procedures required for certain development activities. All formations in the Field can now be drilled, produced and commingled from any or all of ten "drilling windows" on a 320 acre parcel.
The Company's current Wattenberg activities are primarily focused on the development of J-Sand reserves through drilling new wells or deepening within existing wellbores and refracing existing Codell wells. A refrac consists of the restimulation of a producing formation within an existing wellbore to enhance production and add incremental reserves. These projects, the benefits of the Elysium acquisition and continued success with the production enhancement program allowed the Company to increase its production and to substantially increase proved reserves in 2000.
During 2000, the Company drilled or deepened 57 wells to the J-Sand or Dakota formation. The cost of drilling and completing a J-Sand well approximates $320,000 while a completed deepening within an existing wellbore costs roughly $230,000. The reserves associated with a typical J-Sand well are more prolific than those of a Codell/Niobrara, with over 95% of such per well reserves comprised of natural gas. Consequently, the economics of a J-Sand project are more dependent on natural gas prices. Finding and development costs for the J- Sand and Dakota drilling and deepening projects for 2000 averaged $0.70 per Mcfe with projected rates of return in excess of over 150% at current commodity prices. At December 31, 2000, the Company had 289 proven J-Sand drilling locations or deepening projects in inventory.
The Company performed 193 Codell refracs during 2000. The refrac program continues to be focused primarily on the Codell formation. A typical refrac costs approximately $124,000. The finding and development costs associated with the 2000 refrac program averaged $0.67 per Mcfe with projected rates of return in excess of 200% at current commodity prices. At December 31, 2000, the Company had over 1,800 proven refrac projects. Given the exceptional results of the refrac program, the budgeted activity has been increased to over 270 refrac projects in 2001.
The Company also recompleted nine wells in 2000. The Company has an additional 291 proven recompletion opportunities at December 31, 2000. During 2000, tubing was installed in 16 wellbores and numerous well workovers, reactivations, and commingling of zones were performed. These projects, combined with the new drills, deepenings and refracs, were an integral part of the 2000 capital development program and helped fuel continued increases in the Company's production. The Company estimates it had over 500 of these minor projects in inventory at year-end 2000.
At December 31, 2000, the Company had working interests in approximately 3,321 gross (3,202 net) producing oil and natural gas wells in the D-J Basin. As of December 31, 2000 estimated proved reserves totaled 704.8 Bcfe, including 31.4 million barrels of oil and 516.2 Bcf of gas.
In November 2000, Patina acquired various property interests out of a bankruptcy proceeding through Elysium Energy, L.L.C., a New York limited liability company, in which Patina holds a 50% interest. The Company proportionately consolidates its 50% interest in Elysium's assets, liabilities, revenues and expenses. Elysium's oil and gas properties are located in central Kansas, the Illinois Basin, the San Joaquin Field in California, and the Lake Washington Field of Louisiana. The Elysium properties primarily produce oil. Patina's working interests in the Elysium properties consisted of 2,610 gross (1,239 net) producing oil and gas wells. As of December 31, 2000, Patina's 50% share of Elysium's estimated proved reserves totaled 73.0 Bcfe, including 11.3 million barrels of oil and 5.3 Bcf of gas.
Proved Reserves
The following table sets forth estimated net proved reserves for the three years ended December 31, 2000. The 2000 estimates include Patina's 50% share of Elysium's net proved reserves:
The following table sets forth the estimated pretax future net revenues as of year-end 2000 from the production of proved reserves and the pretax present value discounted at 10% of such revenues, net of estimated future capital costs, including an estimate of $62.6 million of future development costs in 2001.
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(a) The after tax present value discounted at 10% of the proved reserves totaled $1,438.9 million at year-end 2000. If the reserve estimates were made with future prices in affect at December 31, 2000 resulting in average wellhead prices of $3.57 per Mcf and $20.70 per barrel over the life of the properties, the pretax PW10% value of the reserves would have exceeded $925.0 million.
The Wattenberg field represents 95% of the pre-tax PW10% value and 704.8 Bcfe or 91% of Patina's proved reserves.
The quantities and values in the preceding tables are based on constant prices in effect at December 31, 2000, which averaged $26.07 per barrel of oil and $8.27 per Mcf of gas. Price declines decrease reserve values by lowering the future net revenues attributable to the reserves and reducing the quantities of reserves that are recoverable on an economic basis. Price increases have the opposite effect. A significant decline in the prices of oil or natural gas could have a material adverse effect on the Company's financial condition and results of operations.
Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods under current economic conditions. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a relatively major expenditure is required to establish production.
Future prices received from production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections.
The present values shown should not be construed as the current market value of the reserves. The quantities and values shown in the preceding tables are based on average oil and natural gas prices in effect on December 31, 2000. The value of the Company's assets is in part dependent on the prices the Company receives for oil and natural gas, and a significant decline in the price of oil or gas could have a material adverse effect on the Company's financial condition and results of operations. The 10% discount factor used to calculate present value, which is specified by the Securities and Exchange Commission (the "SEC"), is not necessarily the most appropriate discount rate, and present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For properties operated by the Company, expenses exclude Patina's share of overhead charges. In addition, the calculation of estimated future net revenues does not take into account the effect of various cash outlays, including, among other things general and administrative costs and interest expense.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The data in the above tables represent estimates only. Oil and natural gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown above. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered.
The proved oil and natural gas reserves and future revenues as of December 31, 2000 were audited by Netherland, Sewell & Associates, Inc. ("NSAI"). On an annual basis, the Company files the Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by operators of domestic oil and gas properties. There are differences between the reserves as reported on Form EIA-23 and reserves as reported herein. Form EIA-23 requires that operators report on total proved developed reserves for operated wells only and that the reserves be reported on a gross operated basis rather than on a net interest basis.
Producing Wells
The following table sets forth the producing wells in which the Company owned a working interest at December 31, 2000. Wells are classified as oil or natural gas wells according to their predominant production stream.
The Company had 174 wells (166 net) and 1,275 wells (603 net) shut in the Wattenberg and the Elysium properties at December 31, 2000, respectively. The Company's average working interest in the Wattenberg wells was approximately 95%, while the average working interest in the Elysium wells was approximately 47%.
Drilling Results
The following table sets forth the number of wells drilled or deepened by the Company during the past three years. All the wells were development wells and drilled in the Wattenberg. 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.
At December 31, 2000 no development wells were in progress.
Acreage
The following table sets forth the leasehold acreage held by the Company at December 31, 2000. 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.
* - Patina's interests in the Elysium acreage.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is a party to various lawsuits incidental to its business, none of which are anticipated to have a material adverse impact on its financial position or results of operations.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
The Company's Common Stock and $12.50 Warrants are listed on the New York Stock Exchange ("NYSE") under the symbols "POG" and "POGWT", respectively. Prior to the redemption, the Company's 7.125% Preferred Stock was listed on the NYSE under the symbol "POGPr". All remaining shares of the 7.125% Preferred Stock were redeemed in January 2000. The Company's 8.50% Preferred Stock was privately placed and did not trade publicly. All remaining shares of the 8.50% preferred stock were converted into Common Stock in September 2000. The $12.50 Warrants will expire on May 2, 2001. The following table sets forth the range of high and low closing prices as reported on the NYSE Composite Tape.
On March 8, 2001, the closing prices of the Common Stock and Warrants were $25.95 and $13.47, respectively. As of December 31, 2000, there were approximately 127 holders of record of the common stock and 20.0 million shares outstanding.
Dividend Policy. A quarterly cash dividend of $0.01 per common share was initiated in December 1997 and was continued through the third quarter of 1999. The dividend was increased to $0.02 per common share in the fourth quarter of 1999 and to $0.04 per common share in the fourth quarter of 2000. The Company expects to continue to pay dividends on its common stock. However, continuation of dividends and the amounts thereof will depend upon the Company's earnings, financial condition, capital requirements and other factors. Under the terms of its bank Credit Agreement, the Company had $17.2 million available for dividends as of December 31, 2000.
ITEM 6.
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, 2000. Future results may differ substantially from historical results because of changes in oil and natural gas prices, production increases or declines and other factors. This information should be read in conjunction with the financial statements and notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations, presented elsewhere herein. The financial data reflects the acquisition of Gerrity in May 1996 and the acquisition of 50% of Elysium in November 2000.
The following tables set forth unaudited summary financial results on a quarterly basis for the last two years.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Comparison of 2000 results to 1999. Revenues for 2000 totaled $150.3 million, a 64% increase over 1999. Net income for 2000 totaled $52.4 million compared to $15.0 million in 1999. The increase in revenue and net income was due primarily to increases in production and higher oil and gas prices.
Average daily oil and gas production in 2000 totaled 4,603 barrels and 91.4 MMcf (119.0 MMcfe), an increase of 11% on an equivalent basis from 1999. During 2000, 60 wells were drilled or deepened and 193 refracs and nine recompletions were performed, compared to 36 new wells or deepenings and 113 refracs and three recompletions in 1999. The Company's current development activity, the benefits of the Elysium acquisition and continued success with the production enhancement program have resulted in annual increases in production since 1998. Based upon a $60.0 million development budget for 2001 and an additional $15.0 million to $20.0 million to be spent on various grassroots projects, the Company expects production to continue to increase in the coming year. The decision to increase development activity is heavily dependent on the prices being received for production.
Average oil prices increased 45% from $15.86 per barrel in 1999 to $23.00 in 2000. Average natural gas prices increased 50% from $2.18 per Mcf in 1999 to $3.28 in 2000. The average oil prices include hedging losses of $3.1 million or $1.85 per barrel in 1999 and $10.4 million or $6.17 per barrel in 2000. The average natural gas prices include hedging losses of $1.0 million or $0.03 per Mcf in 1999 and $13.5 million or $0.40 per Mcf in 2000. Direct operating expenses, consisting of lease operating and production taxes, totaled $24.1 million or $0.55 per Mcfe for 2000 compared to $18.2 million or $0.46 per Mcfe in the prior year period. The increase in direct operating expenses was primarily attributed to a $4.4 million rise in production taxes as a result of higher average oil and gas prices.
General and administrative expenses, net of third party reimbursements, for 2000 totaled $7.1 million, an increase of $866,000 or 14% from 1999. The increase was primarily due to the Company receiving lower reimbursements from third party working interest owners that are offset against general and administrative expenses. The lower reimbursements were the result of the Company increasing its working interest ownership in its oil and gas properties as a result of a property exchange with HS Resources and other minor interest acquisitions in late 1999. Included in general and administrative expenses is $279,000 and $1.0 million for 2000 and 1999 of non-cash expenses related to the common stock grants awarded to officers and managers of the Company in conjunction with the redistribution of SOCO's ownership of the Company in 1997. These grants were fully amortized in 2000.
Interest and other expenses fell to $10.1 million in 2000, a decrease of $727,000 or 7% from the prior year. Interest expense decreased as a result of lower average debt balances and lower average interest rates on the Company's debt due to the redemption of the 11.75% Subordinated Notes in July 1999. The redemption was financed with borrowings under the bank credit facility. The Company's average interest rate for 2000 was 7.7% compared to 8.1% in 1999.
Depletion, depreciation and amortization expense for 2000 totaled $40.6 million, a decrease of $144,000 from 1999. Depletion expense totaled $39.6 million or $0.91 per Mcfe for 2000 compared to $39.8 million or $1.01 per Mcfe for 1999. The decrease in depletion expense resulted primarily from a lower depletion rate, partially offset by higher oil and gas production. The depletion rate was lowered in the fourth quarter of 1999 and the second quarter of 2000 in conjunction with the completion of the year-end 1999 and mid-year 2000 reserve reports. The reduction reflects additional oil and gas reserves due primarily to the identification of additional refrac projects and drilling locations, upward revisions due to over-performance and the increase in oil and gas prices. Depreciation and amortization expense for 2000 totaled $987,000 or $0.02 per Mcfe compared to $947,000 or $0.02 per Mcfe for 1999.
Comparison of 1999 results to 1998. Revenues in 1999 totaled $91.6 million, a 23% increase over 1998. The increase was due primarily to increases in production and higher oil and gas prices. Net income for 1999 totaled $15.0 million compared to a net loss of $4.5 million in 1998. The increase was attributed to higher production, cost efficiencies and recovering oil and gas prices.
Average daily oil and gas production in 1999 totaled 4,529 barrels and 80.8 MMcf (107.9 MMcfe), an increase of 10% on an equivalent basis from 1998. During 1999, 36 wells were drilled or deepened and 116 refracs and recompletions were performed, compared to 36 new wells or deepenings and 75 refracs and recompletions in 1998.
Average oil prices increased 19% from $13.29 per barrel in 1998 to $15.86 in 1999. Average natural gas prices increased 12% from $1.94 per Mcf for 1998 to $2.18 in 1999. The average oil prices include hedging gains of $285,000 or $0.17 per barrel in 1998 and hedging losses of $3.1 million or $1.85 per barrel in 1999. The average natural gas prices include hedging gains of $1.7 million or $0.06 per Mcf in 1998 and hedging losses of $1.0 million or $0.03 per Mcf in 1999. Direct operating expenses, consisting of lease operating and production taxes, totaled $18.2 million or $0.46 per Mcfe for 1999 compared to $17.3 million or $0.49 per Mcfe in the prior year period. The increase in direct operating expenses in 1999 was attributed to a $1.3 million rise in production taxes as a result of higher average oil and gas prices and production offset by a decrease in lease operating expenses of $497,000.
General and administrative expenses, net of third party reimbursements, for 1999 totaled $6.2 million, a $954,000 or 13% decrease from 1998. The reduction in general and administrative expense was due to a cost reduction program implemented in late 1998. Included in general and administrative expenses is $1.0 million and $1.5 million for 1999 and 1998 of non-cash expenses related to the common stock grants awarded to officers and managers of the Company in conjunction with the redistribution of SOCO's ownership of the Company in 1997.
Interest and other expenses fell to $10.8 million in 1999, a decrease of $2.2 million or 17% from the prior year. Interest expense decreased as a result of lower average debt balances and interest rates on the Company's debt due to the redemption of the 11.75% Subordinated Notes in July 1999. The redemption was financed with borrowings under the bank credit facility. The Company's average interest rate for 1999 was 8.1% compared to 10.0% in 1998.
Depletion, depreciation and amortization expense for 1999 totaled $40.7 million, a decrease of $951,000 or 2% from 1998. Depletion expense totaled $39.8 million or $1.01 per Mcfe for 1999 compared to $40.9 million or $1.14 per Mcfe for 1998. The decrease in depletion expense resulted primarily from a lower depletion rate, partially offset by higher oil and gas production. The depletion rate was lowered in the second and fourth quarters of 1999 in conjunction with the completion of the mid-year and year-end reserve reports reflecting additional oil and gas reserves due primarily to the identification of additional refrac projects and drilling locations, upward revisions due to over-performance and the increase in oil and gas prices. Depreciation and amortization expense for 1999 totaled $947,000 or $0.02 per Mcfe compared to $807,000 or $0.02 per Mcfe for 1998.
Development, Acquisition and Exploration
During 2000, the Company incurred $40.3 million of capital expenditures for Wattenberg projects and $49.0 million of acquisition costs relating primarily to the 50% interest acquired in Elysium Energy, L.L.C in late 2000. Capital expenditures included $40.0 million of development costs in Wattenberg to drill or deepen 57 J-Sand wells, perform 193 refracs and nine recompletions and drill three Codell wells. This development activity, the benefits of the Elysium acquisition and continued success with the production enhancement program allowed the Company to realize an 11% increase in production over 1999. The Company anticipates incurring approximately $60.0 million on the further development of its properties during 2001, with an additional $15.0 million to $20.0 million budgeted for various grassroots projects. The decision to increase or decrease development activity is heavily dependent on the prices being received for production.
Financial Condition and Capital Resources
At December 31, 2000, the Company had $421.3 million of assets. Total capitalization was $353.4 million, of which 50% was represented by stockholders' equity and 50% by bank debt. During 2000, net cash provided by operations totaled $109.4 million, as compared to $49.7 million in 1999 ($108.5 million and $56.4 million prior to changes in working capital, respectively). At December 31, 2000, there were no significant commitments for capital expenditures. Based upon a $60.0 million capital budget for 2000 and an additional $15.0 million to $20.0 million for various grassroots projects, the Company expects production to continue to increase in the coming year. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. The Company plans to finance its ongoing development, acquisition and exploration expenditures and additional equity repurchases using internal cash flow, proceeds from asset sales and bank borrowings. In addition, joint ventures or future public and private offerings of debt or equity securities may be utilized.
During 2000, the Company repurchased 1,638,000 common shares and redeemed 513,800 shares of 7.125% preferred stock for $42.1 million. The repurchases were financed with borrowings under the Company's bank credit facility. On January 29, 2001, the Company repurchased 758,500 shares of its common stock from J.P. Morgan Partners (formerly Chase Capital Partners) for $20.50 a share or $15.8 million. As part of the transaction, the Company received an option to purchase an additional 758,500 shares for the same price through May 1, 2001, which it expects to exercise. The Company also anticipates receiving approximately $36.1 million in proceeds from the exercise of the $12.50 common stock warrants, which expire on May 2, 2001.
In July 1999, in conjunction with the redemption of the 11.75% Senior Subordinated Notes, the Company entered into a Second Amended and Restated Bank Credit Agreement (the "Credit Agreement"). The Credit Agreement is a revolving credit facility in an aggregate amount up to $200.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and equaled $200.0 million at December 31, 2000.
The Credit Agreement contains certain financial covenants, including but not limited to a maximum total debt to EBITDA ratio and a minimum current ratio. The Credit Agreement also contains certain negative covenants, including but not limited to restrictions on indebtedness; certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge causes; issuance of securities; and non-speculative commodity hedging. Borrowings under the Credit Agreement mature in July 2003, but may be prepaid at anytime. The Company has periodically negotiated extensions of the Credit Agreement; however, there is no assurance the Company will be able to do so in the future. The Company had a restricted payment basket, as defined in the Credit Agreement, of $17.2 million as of December 31, 2000, which may be used to repurchase equity securities and pay dividends.
The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the prime rate or (ii) the rate at which Eurodollar deposits for one, two, three or six months (as selected by the Company) are offered in the interbank Eurodollar market plus a margin which fluctuates from 1.00% to 1.50%, determined by a debt to EBITDA ratio. The average interest rate under the facility approximated 7.7% during 2000 and was 7.8% at December 31, 2000.
In October 1998, the Company entered into an interest rate swap contract for a two-year period, extendable for one additional year at the option of the third party. The contract was for $30.0 million principal with a fixed interest rate of 4.57% payable by the Company and the variable interest rate, the three-month LIBOR, payable by the third party. The difference between the Company's fixed rate of 4.57% and the three-month LIBOR rate, which was reset every 90 days, was received or paid by the Company in arrears every 90 days. The Company received $184,000 in 1999 pursuant to this contract and $422,000 in 2000. In October 2000, the swap contract lapsed as the third party elected not to extend it.
The Company had $74.0 million of 11.75% Senior Subordinated Notes due July 15, 2004 outstanding on December 31, 1998. The Notes had been reflected in the financial statements at a book value of 105.875% of their principal amount, the initial call price ($69.9 million of principal amount outstanding as of December 31, 1998). The Notes became redeemable on July 15, 1999. The Company redeemed all of the Notes at the call price of 105.875% on July 15, 1999. The redemption was financed with borrowings under the bank credit facility.
In conjunction with his appointment in March 1998, the Company's President purchased 100,000 shares of common stock at $6.875 per share. The Company loaned him $584,000, or 85% of the purchase price, represented by a recourse promissory note that bears interest at 8.50% per annum payable each March 31 until the note is paid. The note matures in March 2001 and is secured by the shares purchased and granted to him. As approved by the Board of Directors, the President sold 50,000 common shares to the Company at $23.50 per share, utilizing a portion of these proceeds to repay the note in March 2001.
The Company has entered into arrangements to monetize its Section 29 tax credits. These arrangements result in revenue increases of approximately $0.40 per Mcf on production volumes from qualified Section 29 properties. As a result, additional gas revenues of $2.1 million, $2.9 million and $3.5 million were recognized during 1998, 1999 and 2000, respectively. The Company expects to exercise its option to terminate these arrangements in March 2001.
The Company's primary cash requirements will be to finance acquisitions, fund development expenditures, repurchase equity securities, repay indebtedness, and general working capital needs. However, future cash flows are subject to a number of variables, including the level of production and oil and natural gas prices, and there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken.
The Company believes that borrowings available under its Credit Agreement, projected operating cash flows and the cash on hand will be sufficient to cover its working capital, capital expenditures, planned development activities and debt service requirements for the next 12 months. In connection with consummating any significant acquisition, additional debt or equity financing will be required, which may or may not be available on terms that are acceptable to the Company.
Certain Factors That May Affect Future Results
Statements that are not historical facts contained in this report are forward-looking statements that involve risks and uncertainties that could cause actual results to differ from projected results. Such statements address activities, events or developments that the Company expects, believes, projects, intends or anticipates will or may occur, including such matters as future capital, development and exploration expenditures (including the amount and nature thereof), drilling, deepening or refracing of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and natural gas, business strategies, expansion and growth of the Company's operations, cash flow and anticipated liquidity, prospect development and property acquisition, obtaining financial or industry partners for prospect or program development, or marketing of oil and natural gas. Factors that could cause actual results to differ materially ("Cautionary Disclosures") are described, among other places, in the Marketing, Competition, and Regulation sections in this Form 10-K and under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations." Without limiting the Cautionary Disclosures so described, Cautionary Disclosures include, among others: general economic conditions, the market price of oil and natural gas, the risks associated with exploration, the Company's ability to find, acquire, market, develop and produce new properties, operating hazards attendant to the oil and natural gas business, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, the strength and financial resources of the Company's competitors, the Company's ability to find and retain skilled personnel, climatic conditions, labor relations, availability and cost of material and equipment, environmental risks, the results of financing efforts, and regulatory developments. All written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Disclosures. The Company disclaims any obligation to update or revise any forward-looking statement to reflect events or circumstances occurring hereafter or to reflect the occurrence of anticipated or unanticipated events.
Market Risk Disclosures
Commodity Price Risk
The Company's major market risk exposure is in the pricing applicable to its oil and natural gas production. Realized pricing is primarily driven by the prevailing domestic price for oil and spot prices applicable to the Rocky Mountain and Mid-Continent regions for its natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Natural gas price realizations during 2000, exclusive of any hedges, ranged from a monthly low of $2.41 per Mcf to a monthly high of $6.20 per Mcf. Oil prices, exclusive of any hedges, ranged from a monthly low of $24.36 per barrel to a monthly high of $33.85 per barrel during 2000. Oil and natural gas prices increased significantly during 1999 and 2000. A significant decline in prices of oil or natural gas could have a material adverse effect on the Company's financial condition and results of operations.
From time to time, the Company enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. The Company uses futures contracts, swaps, options and fixed-price physical contracts to hedge its commodity prices. Realized gains or losses from price risk management activities are recognized in oil and gas sales in the period in which the associated production occurs.
As of December 31, 2000, the Company had entered into swap contracts for oil (NYMEX based) for approximately 4,300 barrels of oil per day for 2001 at fixed prices ranging from $23.05 to $34.43 per barrel and 750 barrels of oil per day for January 2002 through April 2002 at fixed prices ranging from $26.10 to $26.92 per barrel. Certain 2001 swap contracts for oil (NYMEX based) contain "knock-out" provisions. If the average price of NYMEX WTI crude oil falls below the "knock-out" price for the contract month, the swaps will be considered "knocked-out" and no payment will be made to the Company for the applicable month. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $27.07 per barrel for 2001 and $26.51 per barrel for the first four months of 2002. The unrecognized gains on these contracts totaled $3.0 million and $18,000 based on estimated market values at December 31, 2000 and March 1, 2001, respectively.
As of December 31, 2000, the Company had entered into natural gas swap contracts for approximately 50,400 MMBtu's per day for 2001 at fixed prices ranging from $2.55 to $5.05 per MMBtu on CIG index based swap contracts. The Company also has entered into physical natural gas sale contracts for the delivery of approximately 2,500 MMBtu's per day for the first quarter of 2001 at prices ranging from $2.67 to $3.08 per MMBtu. The weighted average daily volumes and prices for these natural gas swaps and physical contracts are 51,000 MMBtu's per day at $3.58 per MMBtu for 2001. The unrecognized losses on the swap contracts totaled $42.2 million and $29.5 million based on estimated market values at December 31, 2000 and March 1, 2001, respectively.
As of March 1, 2001, the Company was a party to the following fixed price swap and physical arrangements summarized below:
Interest Rate Risk
At December 31, 2000, the Company had $177.0 million outstanding under its credit facility with an average interest rate of 7.8%. The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the prime rate or (ii) the rate at which Eurodollar deposits for one, two, three or six months (as selected by the Company) are offered in the interbank Eurodollar market plus a margin which fluctuates from 1.00% to 1.50%, determined by a debt to EBITDA ratio. The average interest rate under the facility approximated 7.7% during 2000. Assuming no change in the amount outstanding during 2001, the impact on interest expense of a ten percent change in the average interest rate would be approximately $1.4 million. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair value.
Inflation and Changes in Prices
While certain costs are affected by the general level of inflation, factors unique to the oil and natural gas industry result in independent price fluctuations. Over the past five years, significant fluctuations have occurred in oil and natural gas prices. Although it is particularly difficult to estimate future prices of oil and natural gas, price fluctuations have had, and will continue to have, a material effect on the Company.
The following table indicates the average oil and natural gas prices received over the last five years and highlights the price fluctuations by quarter for 1999 and 2000. Average price computations exclude hedging gains and losses and other nonrecurring items to provide comparability. Average prices per Mcfe indicate the composite impact of changes in oil and natural gas prices. Oil production is converted to natural gas equivalents at the rate of one barrel per six Mcf.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page ----
PATINA OIL & GAS CORPORATION
Report of Independent Public Accountants.................................
Consolidated Balance Sheets as of December 31, 1999 and 2000.............
Consolidated Statements of Operations for the years ended December 31, 1998, 1999 and 2000......................................
Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1998, 1999 and 2000..................
Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1999 and 2000......................................
Notes to Consolidated Financial Statements...............................
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of Patina Oil & Gas Corporation:
We have audited the accompanying consolidated balance sheets of Patina Oil & Gas Corporation (a Delaware corporation) and subsidiaries as of December 31, 1999 and 2000, 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, 2000. 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 auditing standards generally accepted in the United States. 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, 1999 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
Denver, Colorado, ARTHUR ANDERSEN LLP March 5, 2001
PATINA OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEETS (In thousands except share data)
PATINA OIL & GAS CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands except per share data)
The accompanying notes are an integral part of these statements.
PATINA OIL & GAS CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (In thousands)
The accompanying notes are an integral part of these statements.
PATINA OIL & GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
The accompanying notes are an integral part of these statements
PATINA OIL & GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Patina Oil & Gas Corporation (the "Company" or "Patina"), a Delaware corporation, was formed in 1996 to hold the assets of Snyder Oil Corporation ("SOCO") in the Wattenberg Field and to facilitate the acquisition of Gerrity Oil & Gas Corporation ("Gerrity"). In conjunction with the Gerrity acquisition, SOCO received 14.0 million common shares of Patina. In 1997, a series of transactions eliminated SOCO's ownership in the Company.
In November 2000, Patina completed an acquisition of various property interests out of a bankruptcy proceeding. The assets were acquired through Elysium Energy, L.L.C. ("Elysium"), a New York limited liability company, in which Patina holds a 50% interest. Patina invested $21.0 million and provided a $60.0 million credit facility to Elysium, on which $53.0 million was drawn at closing. See Note (9). The accompanying consolidated financial statements were prepared on a proportionate consolidation basis, including Patina's 50% interest in Elysium's assets, liabilities, revenues and expenses. All significant intercompany balances and transactions have been eliminated in consolidation.
The Company's operations currently consist of the acquisition, development, exploitation and production of oil and natural gas properties. Historically, Patina's properties were primarily in the Wattenberg Field of Colorado's D-J Basin. With the recent acquisition of Elysium, the Company now has additional oil and natural gas properties located in central Kansas, the Illinois Basin, the San Joaquin Field of California, and the Lake Washington Field of Louisiana.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Producing Activities
The Company utilizes the successful efforts method of accounting for its oil and gas properties. Consequently, leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments in value are charged to expense. Exploratory expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. Costs of productive wells, unsuccessful developmental wells and productive leases are capitalized and amortized on a unit-of-production basis over the life of the remaining proved or proved developed reserves, as applicable. Oil is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf. Amortization of capitalized costs has generally been provided on a field-by-field basis. An accrual of approximately $1.0 million has been provided for estimated future abandonment costs on certain Elysium properties as of December 31, 2000. No accrual has been provided for the Wattenberg properties as management estimates that salvage value will approximate or exceed such costs.
The Company follows the provisions of Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets." SFAS 121 requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a field-by-field basis. During 1997, the Company recorded an impairment of $26.0 million to oil and gas properties as the estimated undiscounted future cash flows expected to result from these assets and their disposition, largely proven undeveloped drilling locations, was less than their net book value. The impairment primarily resulted from low year-end oil and natural gas prices. While no impairments have been necessary since 1997, changes in underlying assumptions or the amortization units could result in impairments in the future.
Gas facilities and other
Depreciation of gas gathering and transportation facilities is provided using the straight-line method over an estimated useful life of five years. Equipment is depreciated using the straight-line method with estimated useful lives, generally ranging from three to five years.
Other Assets
Other Assets at December 31, 1999 were comprised of $988,000 of notes receivable from certain officers and key managers of the Company. See Note (9). At December 31, 2000, the remaining notes receivable balance of $690,000 was classified as a current asset and included in Inventory and other, as these notes are due in 2001. At December 31, 1999, the balance also included net loan origination fees of $303,000. These fees were fully amortized in 2000. At December 31, 2000, Other Assets was comprised of $24.5 million advanced under a revolving credit facility to Elysium by Patina. Patina provided Elysium a $60.0 million non-recourse revolving credit facility, on which $49.0 million was outstanding at December 31, 2000. The facility provides for a borrowing base, which is subject to adjustment semi-annually. At February 22, 2001 the borrowing base was $60.0 million of which $13.0 million was available. The loan matures in July 2003. The interest rate is generally based on the Eurodollar rate plus a margin, which fluctuates from 1.50% to 2.00%, depending upon the utilization of the borrowing base. See Note (9).
Section 29 Tax Credits
The Company has entered into arrangements to monetize its Section 29 tax credits. These arrangements result in revenue increases of approximately $0.40 per Mcf on production volumes from qualified Section 29 properties. As a result, additional gas revenues of $2.1 million, $2.9 million and $3.5 million were recognized during 1998, 1999 and 2000, respectively. The Company expects to exercise its option to terminate these arrangements in March 2001.
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, 1999 and December 31, 2000 were insignificant.
Comprehensive Income
The Company follows the provisions of SFAS No. 130, "Reporting Comprehensive Income." SFAS No. 130 establishes standards for reporting and display of comprehensive income and its components in a full set of general- purpose financial statements. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to the owners of the Company. The Company had no such changes in 1998, 1999 or 2000, respectively.
Financial Instruments
The book value and estimated fair value of cash and equivalents was $626,000 and $2.7 million at December 31, 1999 and December 31, 2000, respectively. The book value and estimated fair value of the senior debt was $132.0 million and $177.0 million at December 31, 1999 and December 31, 2000, respectively. The book value of these assets and liabilities approximates fair value due to the short maturity or floating rate structure of these instruments.
From time to time, the Company enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and natural gas price volatility. Commodity derivative contracts, which are generally placed with major financial institutions or with counter parties of high credit quality that the Company believes are minimal credit risks, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these commodity derivative contracts are based upon oil and natural gas futures which have a high degree of historical
correlation with actual prices received by the Company. The Company accounts for its commodity derivative contracts using the hedge (deferral) method of accounting. Under this method, realized gains and losses on such contracts are deferred and recognized as an adjustment to oil and gas sales in the period in which the physical product to which the contracts relate, is actually sold. Gains and losses on commodity derivative contracts that are closed before the hedged production occurs are deferred until the production month originally hedged.
The Company entered into various swap contracts for oil (NYMEX based) during 1998, 1999 and 2000. The Company recognized a gain of $238,000 in 1998 and losses of $3.1 million and $10.4 million in 1999 and 2000, respectively, related to these swap contracts.
The Company entered into various CIG and PEPL index based swap contracts for natural gas during 1998, 1999, and 2000. The Company recognized a gain of $1.5 million in 1998 and losses of $1.0 million and $13.5 million in 1999 and 2000, respectively, related to these swap contracts.
As of December 31, 2000, the Company had entered into swap contracts for oil (NYMEX based) for approximately 4,300 barrels of oil per day for 2001 at fixed prices ranging from $23.05 to $34.43 per barrel and 750 barrels of oil per day for January 2002 through April 2002 at fixed prices ranging from $26.10 to $26.92 per barrel. Certain 2001 swap contracts for oil (NYMEX based) contain "knock-out" provisions. If the average price of NYMEX WTI crude oil falls below the "knock-out" price for the contract month, the swaps will be considered "knocked-out" and no payment will be made to the Company for the applicable month. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $27.07 per barrel for 2001 and $26.51 per barrel for the first four months of 2002. The unrecognized gains on these contracts totaled $3.0 million and $18,000 based on estimated market values at December 31, 2000 and March 1, 2001, respectively.
As of December 31, 2000, the Company had entered into natural gas swap contracts for approximately 50,400 MMBtu's per day for 2001 at fixed prices ranging from $2.55 to $5.05 per MMBtu on CIG index based swap contracts. The Company also has entered into physical natural gas sale contracts for the delivery of approximately 2,500 MMBtu's per day for the first quarter of 2001 at prices ranging from $2.67 to $3.08 per MMBtu. The weighted average daily volumes and prices for these natural gas swaps and physical contracts are 51,000 MMBtu's per day at $3.58 per MMBtu for 2001. The unrecognized losses on the swap contracts totaled $42.2 million and $29.5 million based on estimated market values at December 31, 2000 and March 1, 2001, respectively.
As of March 1, 2001, the Company was a party to the following fixed price swap and physical arrangements summarized below:
In 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS 133 is effective for fiscal years beginning after June 15, 2000.
The financial statement impact of recording derivative instruments designated as hedges and derivative instruments not designated as hedges upon adoption of SFAS 133 on January 1, 2001 is as follows (in millions):
In October 1998, the Company entered into an interest rate swap contract for a two-year period, extendable for one additional year at the option of the third party. The contract was for $30.0 million principal with a fixed interest rate of 4.57% payable by the Company and the variable interest rate, the three- month LIBOR, payable by the third party. The difference between the Company's fixed rate of 4.57% and the three-month LIBOR rate, which was reset every 90 days, was received or paid by the Company in arrears every 90 days. The Company received $184,000 in 1999 pursuant to this contract and $422,000 in 2000. In October 2000, the swap contract lapsed as the third party elected not to extend it.
Stock Options and Awards
The Company accounts for its stock-based compensation plans under the principles prescribed by the Accounting Principles Board's Opinion No. 25 ("APB No. 25"), "Accounting for Stock Issued to Employees." Accordingly, stock options awarded under the Employee Plan and the non-employee Directors Plan are considered to be "noncompensatory" and do not result in recognition of compensation expense. However, the restricted stock awarded under the Restricted Stock Plan is considered to be "compensatory" and the Company recognized $1.5 million, $1.0 million and $279,000 of non-cash general and administrative expenses for 1998, 1999 and 2000, respectively. These costs were fully amortized at year-end 2000. See Note (6).
Per Share Data
The Company uses the weighted average number of shares outstanding in calculating earnings per share data. When dilutive, options and warrants are included as share equivalents using the treasury stock method and are included in the calculation of diluted per share data. Common stock issuable upon conversion of convertible preferred securities is also included in the calculation of diluted per share data if their effect is dilutive.
Risks and Uncertainties
Historically, the market for oil and natural gas has experienced significant price fluctuations. Prices for oil and natural gas in the United States have been particularly volatile in recent years. The price fluctuations can result from variations in weather, levels of regional or national production, availability of transportation capacity to other regions of the country and various other factors. Increases or decreases in prices received could have a significant impact on future results.
Supplemental Cash Flow Information
The 1998 stock grant award represents 100,000 common shares granted to the President in conjunction with his appointment in the first quarter of 1998 and was recorded as Deferred Compensation in the equity section of the accompanying consolidated balance sheets. The 1999 stock grant award represents 100,000 common shares granted to the Chief Executive Officer in conjunction with his voluntary reduction in cash salary, waiver of any 1998 bonus and other compensation arrangements in the second quarter of 1999. The Company recognized $1.5 million, $1.0 million and $279,000 of non-cash general and administrative expenses for 1998, 1999 and 2000, respectively, related to these stock grants and the stock grants awarded to officers and managers in conjunction with the redistribution of SOCO's ownership of the Company. See Note (9).
Other
All liquid investments with an original maturity of three months or less are considered to be cash equivalents. Certain amounts in prior period consolidated financial statements have been reclassified to conform with the current classifications. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries and 50% of the accounts of Elysium.
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, 1999 and 2000 included approximately $225,000 and $1.1 million in net unevaluated leasehold costs. The value of acreage held for exploration, development or resale and its value, is excluded from amortization. The following table sets forth costs incurred related to oil and gas properties:
(4) INDEBTEDNESS
The following indebtedness was outstanding on the respective dates:
In July 1999 the Company entered into a Second Amended and Restated Bank Credit Agreement (the "Credit Agreement"). The Credit Agreement is a revolving credit facility in an aggregate amount up to $200.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and equaled $200.0 million at December 31, 2000.
The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the prime rate or (ii) the rate at which Eurodollar deposits for one, two, three or six months (as selected by the Company) are offered in the interbank Eurodollar market plus a margin which fluctuates from 1.00% to 1.50%, determined by a debt to EBITDA ratio. The average interest rate under the facility approximated 7.7% during 2000 and was 7.8% at December 31, 2000.
The Credit Agreement contains certain financial covenants, including but not limited to a maximum total debt to EBITDA ratio and a minimum current ratio. The Credit Agreement also contains certain negative covenants, including but not limited to restrictions on indebtedness; certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge causes; issuance of securities; and non-speculative commodity hedging. Borrowings under the Credit Agreement mature in July 2003, but may be prepaid at anytime. The Company has periodically negotiated extensions of the Credit Agreement; however, there is no assurance the Company will be able to do so in the future. The Company had a restricted payment basket, as defined in the Credit Agreement, of $17.2 million as of December 31, 2000, which may be used to repurchase equity securities and pay dividends.
Scheduled maturities of indebtedness for the next five years are zero for 2001 and 2002, and $177.0 million in 2003. Management intends to review the facility and extend the maturity on a regular basis; however, there can be no assurance that the Company will be able to do so. Cash payments for interest totaled $14.0 million, $14.3 million and $10.0 million during 1998, 1999 and 2000, respectively.
(5) STOCKHOLDERS' EQUITY
A total of 100,000,000 common shares, $0.01 par value, are authorized of which 20,043,859 were issued and outstanding at December 31, 2000. The common stock is listed on the New York Stock Exchange. Prior to December 1997, no dividends had been paid on common stock. A quarterly cash dividend of $0.01 per common share was initiated in December 1997. The dividend was increased to $0.02 per common share in the fourth quarter of 1999 and to $0.04 per common share in the fourth quarter of 2000. The following is a schedule of the changes in the Company's shares of common stock:
On January 29, 2001, the Company repurchased 758,500 shares of its common stock from J.P. Morgan Partners (formerly Chase Capital Partners) for $20.50 a share or $15.8 million. As part of the transaction, the Company received an option to purchase an additional 758,500 shares at the same price through May 1, 2001.
At December 31, 2000, the Company had 2,917,090 $12.50 common stock warrants outstanding. These warrants are exercisable at $12.50 for one share of common stock and expire on May 2, 2001. The common stock warrants are listed on the New York Stock Exchange.
A total of 5,000,000 preferred shares, $0.01 par value, are authorized with no shares issued and outstanding at December 31, 2000.
In December 1999, the Company called for redemption all remaining 7.125% preferred stock. The effective date of the redemption was January 21, 2000. Of the 564,800 preferred shares called, 51,000 were converted into 148,000 shares of common stock and the remaining 513,800 were redeemed for $13.4 million in cash. The cash redemption was financed with borrowings under the bank credit facility. The Company paid $2.6 million, $2.7 million and $600,000 in preferred dividends during 1998, 1999 and 2000, respectively. Included in the $2.7 million and $600,000 of preferred stock dividends paid in 1999 and 2000 was $489,000 and $549,000 of redemption premiums paid to shareholders that elected to redeem their preferred stock for cash in the fourth quarter of 1999 and the first quarter of 2000.
In August 2000, the Company called for redemption all remaining 1,618,500 shares of the 8.50% preferred stock outstanding. The issue was converted into 4.8 million shares of common stock, including more than 500,000 shares of common stock issued upon conversion in June 2000. The Company paid $3.5 million, $3.7 million and $2.6 million in dividends during 1998, 1999 and 2000, respectively. Dividends through October 21, 1999 were paid in kind. As such, the Company issued 141,240 and 119,577 of additional 8.50% preferred shares as dividends in 1998 and 1999, respectively. Dividends subsequent to October 1999 were paid in cash.
The Company follows the provisions of Statement of Financial Accounting Standards No. 128 ("SFAS 128"), "Earnings per Share." SFAS 128 specifies computation, presentation and disclosure requirements for earnings per share for entities with publicly held common stock or potential common stock.
The potential common stock equivalents of the 7.125% and 8.50% preferred stock, and $12.50 common stock warrants were anti-dilutive in 1998 and 1999. The stock options were anti-dilutive in 1998.
(6) EMPLOYEE BENEFIT PLANS
401(k) Savings
The Company has a 401(k) profit sharing and savings plan (the "401(k) Plan"). Eligible employees may make voluntary contributions to the 401(k) Plan. The amount of employee contributions is limited as specified in the 401(k) Plan. The Company may, at its discretion, make additional matching or profit sharing contributions to the 401(k) Plan. The Company made profit sharing contributions to the 401(k) Plan of $338,000, $483,000 and $589,000 for 1998, 1999 and 2000, respectively. The profit sharing contributions were made in common stock in each of the last three years. A total of 138,500, 61,300 and 29,600 common shares were contributed in 1998, 1999 and 2000, respectively.
Stock Purchase Plan
The Company maintains a shareholder approved stock purchase plan ("Stock Purchase Plan"). Pursuant to the Stock Purchase Plan, officers, directors and certain managers are eligible to purchase shares of common stock at prices ranging from 50% to 85% of the closing price of the stock on the trading day prior to the date of purchase ("Closing Price"). In addition, employee participants may be granted the right to purchase shares pursuant to the Stock Purchase Plan with all or a part of their salary and bonus. A total of 500,000 shares of common stock are reserved for possible purchase under the Stock Purchase Plan. In May 1999, an amendment to the Stock Purchase Plan was approved by the stockholders allowing for the annual renewal of the 500,000 shares of common stock reserved for possible purchase under the Plan. In 1998, the Board of Directors approved 291,300 common shares (exclusive of shares available for purchase with participants' salaries and bonuses) for possible purchase by participants at 75% of the Closing Price during the current Plan Year as defined in the Stock Purchase Plan. As of December 31, 1998, participants had purchased 257,600 shares of common stock, including 76,700 shares purchased
with participant's 1997 bonuses, at prices ranging from $3.69 to $7.31 per share ($2.77 to $5.48 net price per share), resulting in cash proceeds to the Company of $1.3 million. In 1999, the Board of Directors approved 136,300 common shares (exclusive of shares available for purchase with participants' salaries and bonuses) for possible purchase by participants at 75% of the Closing Price during the current Plan Year as defined in the Stock Purchase Plan. As of December 31, 1999, participants had purchased 92,900 shares of common stock at prices ranging from $5.06 to $8.63 per share ($3.80 to $6.47 net price per share), resulting in cash proceeds to the Company of $395,000. In 2000, the Board of Directors approved 116,300 common shares (exclusive of shares available for purchase with participants' salaries and bonuses) for possible purchase by participants at 75% of the Closing Price during the current Plan Year as defined in the Stock Purchase Plan. As of December 31, 2000, participants had purchased 138,200 shares of common stock, including 85,800 shares purchased with participant's 1999 bonuses, at prices ranging from $9.19 to $17.31 per share ($6.89 to $12.98 net price per share), resulting in cash proceeds to the Company of $665,000. The Company recorded non-cash general and administrative expenses of $173,000, $53,000 and $89,000 associated with these purchases for 1998, 1999 and 2000, respectively.
Stock Option and Award Plans
The Company maintains a shareholder approved stock option plan for employees (the "Employee Plan") providing for the issuance of options at prices not less than fair market value. Options to acquire the greater of three million shares of common stock or 10% of outstanding diluted common shares may be outstanding at any given time. The specific terms of grant and exercise are determinable by a committee of independent members of the Board of Directors. A summary by year of stock options granted under the plan for employees is summarized below:
Weighted Range Average of Exercise Exercise Options Price Per Price Per Year Granted Common Share Common Share ---- ------- ------------ ------------ 1996....................... 512,000 $7.75 $7.75 1997....................... 521,000 $8.75 - $9.88 $9.75 1998....................... 614,000 $6.56 - $7.19 $7.03 1999....................... 630,000 $2.94 - $9.13 $3.54 2000....................... 505,000 $9.19 - $21.94 $9.34
The options generally vest over a three-year period (30%, 60%, 100%) and expire five years from the date of grant, except for 250,000 five-year options which were fully vested at the date of grant in October 1997 at an exercise price of $9.88.
The Company also maintains a shareholder approved stock grant and option plan (the "Directors' Plan") for non-employee Directors. The Directors' Plan provides for each non-employee Director to receive common shares having a market value equal to $2,500 quarterly in payment of one-half their retainer. A total of 3,600 shares were issued in 1996, 4,500 shares were issued in 1997, 11,900 shares were issued in 1998, 8,600 were issued in 1999 and 2,800 were issued in 2000. It also provides for 5,000 options to be granted annually to each non-employee Director. A summary by year of stock options granted under the Directors' Plan is summarized below:
Weighted Range Average of Exercise Exercise Options Price Per Price Per Year Granted Common Share Common Share ---- ------- ------------ ------------ 1996....................... 20,000 $7.75 $7.75 1997....................... 30,000 $8.63 - $10.31 $9.19 1998....................... 35,000 $7.19 - $7.75 $7.59 1999....................... 30,000 $2.94 - $5.13 $4.76 2000....................... 25,000 $17.44 $17.44
The options generally vest over a three-year period (30%, 60%, 100%) and expire five years from the date of grant.
In 1997, the shareholders approved a special stock grant and purchase plan for certain officers and managers ("Management Investors") in conjunction with the redistribution of SOCO's ownership in the Company. The plan, which was amended effective December 31, 1997, provided for the grant of certain restricted common shares to the Management Investors. These shares vested at 25% per year on January 1, 1998, 1999, 2000 and 2001. The non-vested granted common shares were recorded as Deferred Compensation in the equity section of the accompanying consolidated balance sheets. The Management Investors simultaneously purchased additional common shares from the Company at $9.875 per share. A portion of the purchase was financed by the Company, all of which was repaid in January 2001. See Note (9). In conjunction with his appointment in March 1998, the Company's President was granted 100,000 restricted common shares that vest at 33% per year in March 1999, 2000 and 2001. The non-vested granted common shares have been recorded as Deferred Compensation in the equity section of the accompanying consolidated balance sheets. The President simultaneously purchased 100,000 common shares from the Company at $6.875 per share. A portion of this purchase ($584,000) was financed by the Company. As approved by the Board of Directors, the President sold 50,000 common shares to the Company at $23.50 per share, utilizing a portion of these proceeds to repay the note in March 2001. See Note (9). In April 1999, the Chief Executive Officer was granted 100,000 restricted shares of common stock in consideration of his voluntary reduction in cash salary, waiver of any 1998 bonus and other compensation arrangements. The shares vested ratably throughout 1999. The Company recognized $1.5 million, $1.0 million and $279,000 of non-cash general and administrative expenses for 1998, 1999 and 2000 with respect to these stock grants.
At December 31, 2000, 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:
1998 1999 2000 ---- ---- ----
Net income (loss) As Reported $(4,524) $14,959 $52,441 Pro forma (5,724) 13,954 50,948 Basic net income (loss) per common share As Reported $(0.68) $ 0.52 $ 2.81 Pro forma (0.75) 0.45 2.72 Diluted net income (loss) per common share As Reported $(0.68) $ 0.50 $ 2.28 Pro forma (0.75) 0.44 2.24
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 1998, 1999 and 2000: dividend yield of 0%, 1% and 1%; expected volatility of 46%, 47% and 49%; risk-free interest rate of 5.5%, 5.2% and 6.6%; and expected life of 4.5 years, 4.5 years and 4.0 years, respectively.
A summary of the status of the Company's fixed stock option plans as of December 31, 1998, 1999 and 2000 and changes during the years are presented below:
The following table summarizes information about fixed stock options outstanding at December 31, 2000:
(7) FEDERAL INCOME TAXES
A reconciliation of the federal statutory rate to the Company's effective rate as it applies to the tax provision for the years ended December 31, 1998, 1999 and 2000 follows:
For book purposes the components of the net deferred tax asset and liability at December 31, 1999 and 2000 were:
For tax purposes, the Company had regular net operating loss carryforwards of approximately $49.0 million and alternative minimum tax ("AMT") loss carryforwards of approximately $7.5 million at December 31, 2000. Utilization of $42.8 million of the regular net operating loss carryforwards will be limited to approximately $12.5 million per year as a result of the redistribution of SOCO's majority ownership in the Company in October 1997. In addition, utilization of $25.9 million regular net operating loss carryforwards will be limited to $4.2 million per year as a result of the Gerrity acquisition in 1996. These carryforwards expire from 2008 through 2018. At December 31, 2000, the Company had AMT credit carryforwards of $1.4 million that are available indefinitely. No cash payments were made by the Company for federal taxes during 1999 and 2000. The Company paid $239,000 of federal taxes during 1998.
(8) MAJOR CUSTOMERS
During 1998, 1999 and 2000, Duke Energy Field Services, Inc. accounted for 38%, 37% and 32%, BP Amoco Production Company accounted for 13%, 24% and 19%, Enron North America accounted for 10%, 4%, and 3% and Aurora Natural Gas, LLC accounted for 0%, 10% and 1% of revenues, respectively. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.
(9) RELATED PARTY
In October 1997, certain officers and managers purchased common shares at $9.875 per share from the Company. A portion of this purchase was financed by the Company through the issuance of 8.50% recourse promissory notes. The remaining notes balance at December 31, 2000 of $106,000 was repaid in January 2001. These notes have been reflected as Other Assets in the accompanying consolidated balance sheets at December 31, 1999 and in Inventory and other at December 31, 2000. In conjunction with his appointment in March 1998, the President purchased 100,000 shares of common stock at $6.875 per share and was granted 100,000 shares. The Company loaned him $584,000, or 85% of the purchase price, represented by a recourse promissory note that bears interest at 8.50% per annum payable each March 31. The note matures in March 2001 and is secured by all of the shares purchased and granted to him. As approved by the Board of Directors, the President sold 50,000 common shares to the Company at $23.50 per share, utilizing a portion of these proceeds to repay the note in March 2001. The note has been reflected as Other Assets in the accompanying consolidated balance sheets at December 31, 1999 and in Inventory and other at December 31, 2000. In consideration of the then depressed stock price and overall lower 1998 bonuses, the interest due as of March 31, 1999 under the Management Investors' and President's notes was forgiven.
Patina provided Elysium a $60.0 million non-recourse revolving credit facility, on which $49.0 million was outstanding at December 31, 2000. The facility provides for a borrowing base, which is subject to adjustment semi- annually. At February 22, 2001 the borrowing base was $60.0 million of which $13.0 million was available. The loan matures in July 2003. The interest rate is generally based on the Eurodollar rate plus a margin, which fluctuates from 1.50% to 2.00%, depending upon the utilization of the borrowing base. In 2000, Elysium paid $371,000 of interest to Patina under the revolving credit facility.
Patina provides certain administrative services to Elysium under an operating agreement. During 2000, the Company was paid $36,000 for these services.
(10) COMMITMENTS AND CONTINGENCIES
The Company leases office space and certain equipment under non-cancelable operating leases. Future minimum lease payments under such leases approximate $750,000 per year from 2001 through 2005.
The Company is a party to various lawsuits incidental to its business, none of which are anticipated to have a material adverse impact on its financial position or results of operations.
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
Independent petroleum consultants audited the Company's total proved reserves at December 31, 1998, 1999 and 2000. All reserve estimates are based on economic and operating conditions at that time. Future net cash flows as of each year-end were computed by applying then current prices to estimated future production less estimated future expenditures (based on current costs) to be incurred in producing and developing the reserves. All reserves are located onshore in the United States.
Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. With respect to certain properties that historically have experienced seasonal curtailment, the reserve estimates assume that the seasonal pattern of such curtailment will continue in the future. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The data in the tables below represent estimates only. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown below. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. Results in drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered.
Quantities of Proved Reserves
(a) "Purchases" includes the present value at the end of the period acquired during the year plus cash flow received on such properties during the period, rather than their estimated present value at the time of the acquisition.
(b) "Sales" represents the present value at the beginning of the period of properties sold, less the cash flow received on such properties during the period.
PART IV. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Exhibits -
2.1 Amended and Restated Agreement and Plan of Merger dated as of January 16, 1996 as amended and restated as of March 20, 1996 -- incorporated by reference to Exhibit 2.1 to Amendment No. 1 to the Registration Statement on Form S-4 of Patina Oil & Gas Corporation. (Registration No. 333-572)
3.1 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)
3.2 Bylaws -- incorporated herein by reference to Exhibit 3.3 to the Company's Registration Statement on Form S-4. (Registration No. 333-572)
3.3 Certificate of Ownership and Merger of Gerrity Oil & Gas Corporation with and into the Company, effective March 21, 1997 (Incorporated herein by reference to Exhibit 4.3 of the Company's Form 10-Q for the quarter ended March 31, 1997)
10.1.1 Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions. (Incorporated herein by reference to Exhibit 10.1 of the Company's Form 10-Q for the quarter ended June 30, 1999)
10.1.2 First Amendment to the Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions. (Incorporated herein by reference to Exhibit 10.1.2 of the Company's Form 10-K for the year ended December 31, 1999)
10.1.3 Second Amendment to the Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions. (Incorporated herein by reference to Exhibit 10.1.2 of the Company's Form 10-K for the year ended December 31, 1999)
10.1.4 Third Amendment to the Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions. (Incorporated herein by reference to Exhibit 10.1 of the Company's Form 10-Q for the quarter ended June 30, 2000)
10.1.5 Fourth Amendment to the Second Amended and Restated Credit Agreement dated July 15, 1999 by and among the Company, as Borrower, and Chase Bank of Texas, National Association, as Administrative Agent, Bank of America, N.A., as Syndication Agent, Bank One, Texas, N.A., as Documentation and certain commercial lending institutions.*
10.2 Patina Oil & Gas Corporation Profit Sharing and Savings Plan and Trust, effective January 1, 1997. (Incorporated herein by reference to Exhibit 10.3 of the Company's Form 10-K for the year ended, December 31, 1997)
10.3.1 Deferred Compensation Plan for Selected Employees adopted by the Company effective May 1, 1996. (Incorporated herein by reference to Exhibit 10.3.1 of the Company's Form 10-K for the year ended December 31, 1996)
10.3.2 Amended and Restated Patina Oil & Gas Corporation Deferred Compensation Plan for Select Employees as adopted May 1, 1996 and amended as of September 30, 1997. (Incorporated herein by reference to Exhibit 10.3.2 of the Company's Form 10-K for the year ended December 31, 1997)
10.4.1 Patina Oil & Gas Corporation 1998 Stock Purchase Plan. (Incorporated herein by reference to Exhibit of the Company's Form 10-K for the year ended December 31, 1997)
10.4.2 Amendment No. 1 to the Patina Oil & Gas Corporation 1998 Stock Purchase Plan. (Incorporated herein by reference to Exhibit 10.3 of the Company's Form 10-Q for the quarter ended June 30, 1999)
10.5.1 Lease Agreement dated as of December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant.*
10.6 Stock Purchase Agreement dated as of July 31, 1997 by and among the Company and the Investors named therein as amended on September 19, 1997. (Incorporated herein by reference to Exhibit 10.5 of the Company's Form 10-Q for the quarter ended September 30, 1997)
10.7 Employment Agreement dated July 31, 1997 by and between the Company and Thomas J. Edelman. (Incorporated herein by reference to Exhibit 10.7 of the Company's Form 10-Q for the quarter ended September 30, 1997)
10.8 Management Stock Purchase Agreement dated as of September 4, 1997 by and among the Company and certain Management Investors. (Incorporated herein by reference to Exhibit 10.8 of the Company's Form 10-Q for the quarter ended September 30, 1997)
10.9 Restricted Stock Agreement dated as of September 4, 1997 by and among the Company and certain Management Investors. (Incorporated herein by reference to Exhibit 10.9 of the Company's Form 10-Q for the quarter ended September 30, 1997)
10.10 Stock Purchase Agreement dated March 16, 1998 by and between the Company and Jay W. Decker. (Incorporated herein by reference to Exhibit 10.11 of the Company's Form 10-K for the year ended December 31, 1997)
10.11 Restricted Stock Agreement dated March 16, 1998 by and between the Company and Jay W. Decker. (Incorporated herein by reference to Exhibit 10.11 of the Company's Form 10-K for the year ended December 31, 1997)
10.12 Standstill Agreement dated April 12, 2000 between Patina Oil & Gas Corporation and Southwestern Eagle L.L.C. (Incorporated herein by reference to Exhibit 10.1.1 of the Company's Form 10-Q for the quarter ended March 31, 2000)
10.13 First Amended and Restated Operating Agreement of Elysium Energy, L.L.C., a New York limited liability company, dated November 27, 2000. *
12 Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.*
23 Consent of independent public accountants. *
27 Financial Data Schedule.*
*Filed herewith
(b) No reports on Form 8-K were filed by Registrant during the quarter ended December 31, 2000.
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.