-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Px8nkWigWmuqICDyTLyJJnUz8GjVPDheR7+KOA4vjUB4uUSJsN6lzB7/5BuGaGX5 DaQ90XRQ1LJhFCJSFjRmGw== 0000927356-00-000336.txt : 20000228 0000927356-00-000336.hdr.sgml : 20000228 ACCESSION NUMBER: 0000927356-00-000336 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000225 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PATINA OIL & GAS CORP CENTRAL INDEX KEY: 0001006264 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752629477 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-14344 FILM NUMBER: 553833 BUSINESS ADDRESS: STREET 1: 1625 BROADWAY STREET 2: STE 2000 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3035928500 MAIL ADDRESS: STREET 1: 777 MAIN ST STREET 2: STE 2500 CITY: FORT WORTH STATE: TX ZIP: 76102 10-K405 1 FORM 10-K 405 ================================================================================ SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ---------------------- FORM 10-K (Mark one) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transaction period from________ to_________ Commission file number 1-14344 --------------------------- PATINA OIL & GAS CORPORATION (Exact name of registrant as specified in its charter) Delaware 75-2629477 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 1625 Broadway 80202 Denver, Colorado (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code (303) 389-3600 Title of each class Name of each exchange on which registered -------------------------------------------------- ------------------------------------------ Common Stock, $.01 par value New York Stock Exchange 7.125% Convertible Preferred Stock, $.01 par value New York Stock Exchange Common Stock Warrants New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [X] Yes [ ] No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of the 11,285,000 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the common stock on February 23, 2000 of $9.13 per share as reported on the New York Stock Exchange, was $102,976,000. Shares of common stock held by each officer and director and by each person who owns 5% or more of the outstanding common stock have been excluded in that such persons may be deemed affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes. As of February 17, 2000, the registrant had 16,285,770 shares of common stock outstanding. DOCUMENT INCORPORATED BY REFERENCE Part III of the report is incorporated by reference to the Registrant's definitive Proxy Statement relating to its Annual Meeting of Stockholders, which will be filed with the Commission no later than April 30, 2000. ================================================================================ PATINA OIL & GAS CORPORATION Annual Report on Form 10-K December 31, 1999 PART I ITEM 1. BUSINESS General Patina Oil & Gas Corporation ("Patina" or the "Company") is an independent energy company engaged in the acquisition, development, exploitation and production of oil and natural gas in the Wattenberg Field ("Wattenberg" or the "Field") of Colorado's Denver-Julesburg Basin ("D-J Basin"). The Company was formed in 1996 to hold the Wattenberg assets of Snyder Oil Corporation ("SOCO") and to facilitate the acquisition of Gerrity Oil & Gas Corporation ("Gerrity" or the "Gerrity Acquisition"). In conjunction with the Gerrity Acquisition, SOCO received 14.0 million of the Company's common shares. In 1997, a series of transactions eliminated SOCO's ownership in the Company. Patina is one of the largest producers in Wattenberg and currently accounts for over 30% of the total production from the Field. Wattenberg is one of the ten largest natural gas fields in the U.S. with total cumulative production in excess of three trillion cubic feet of natural gas equivalents since its discovery 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 that there are up to eight potentially productive formations throughout the field ranging in depths from 2,000 to 8,000 feet. Three of the formations, the Codell, the Niobrara and the J-Sand, are "blanket" zones in the area of the Company's holdings, while other formations, such as the Sussex, Shannon and Dakota are more localized. The existence of several pay sands within the geological structure allows for multiple completions within a single wellbore, reducing drilling risks and operating costs. At December 31, 1999, the Company had $330.2 million of assets and 465.8 Bcfe of proved reserves. The reserves had an estimated pretax present value of $457.5 million based on unescalated prices and costs in effect on that date. Approximately 78% of the reserves on an Mcf equivalent basis were natural gas and over 94% of the pretax present value was attributable to proved developed reserves. The Company operates almost 97% of the roughly 3,400 producing wells in which it holds a working interest, representing 99% of its producing reserve value. At December 31, 1999, the Company had 153 proved undeveloped drilling or deepening projects, 284 recompletions and 546 restimulation ("refrac") opportunities included in total proved reserves. During 1999, production averaged 107.9 MMcfe per day. Based on year-end 1999 reserves, the Company had a reserve life index of 11.8 years. From its inception, the Company has focused on further consolidating the ownership of its properties, developing an efficient organization, reducing costs and improving operations. During 1999, revenues and net cash provided from operations totaled $91.6 million and $49.7 million, respectively. The Company used its operating cash flow to repurchase $24.7 million of its equity securities and reduce indebtedness by $10.0 million. In addition, the Company invested $24.0 million in the further development of its properties and the acquisition of additional interests in Wattenberg. During the year, the Company's development program was primarily comprised of drilling or deepening 36 development wells, performing 113 refracs and recompleting three wells. This development activity, the benefits of certain minor acquisitions and continued success with the production enhancement program allowed the Company to realize a 10% increase in production in 1999. Total proved reserves also increased 25% over 1998 due to the identification of additional refrac projects and drilling locations, upward revisions due to over-performance and the increase in oil and gas prices. The Company's future Wattenberg activities will be primarily focused on the development of J-Sand reserves through drilling new wells or deepening within existing wellbores and refracing existing Codell wells. These projects and the continued success with the production enhancement program should allow the Company to realize production growth and increase total proved reserves in 2000. 2 Business Strategy Management believes that the Company's sizable asset base and cash flow, along with its low production costs and efficient operating structure, provide it with a competitive advantage in Wattenberg and in certain analogous basins. Given management's expertise in operations and the advantages set forth above, the Company believes it is in a good position to increase its reserves, production and cash flows in a cost-efficient manner primarily through: (i) further development and exploitation of its properties in Wattenberg through development activity, well workovers and operational improvements; (ii) the generation of grassroots drilling prospects with the potential to add significant reserves and production, and (iii) selectively pursuing consolidation and acquisition opportunities in existing and future core areas. Consistent with prior years, the Company plans to repurchase its equity securities from time to time, dependant upon market conditions. Management believes that the Company's strong financial position affords it the financial flexibility to execute its business strategy. Production, Revenue and Price History The following table sets forth information regarding net oil and natural gas production, revenues and direct operating expenses attributable to such production, average sales prices and other production information for each of the years in the five year period ended December 31, 1999. The financial and operating information reflect the acquisition of Gerrity in May 1996.
December 31, -------------------------------------------------------------- 1995 1996 1997 1998 1999 ----------- ----------- ----------- ----------- ---------- (Dollars in thousands, except prices and per Mcfe information) Production Oil (MBbl)............................. 1,342 1,688 1,889 1,699 1,653 Gas (MMcf)............................. 20,981 23,947 26,863 25,522 29,477 MMcfe (a).............................. 29,034 34,074 38,194 35,715 39,396 Revenues Oil.................................... $22,049 $34,541 $ 37,197 $22,583 $26,218 Gas (b)................................ 28,024 47,644 62,342 49,594 64,189 ------- ------- -------- ------- ------- Subtotal........................... 50,073 82,185 99,539 72,177 90,407 Other.................................. 29 1,003 794 2,533 1,164 ------- ------- -------- ------- ------- Total............................... 50,102 83,188 100,333 74,710 91,571 ------- ------- -------- ------- ------- Direct operating expenses Lease operating expenses............... 5,387 8,866 11,735 12,399 11,902 Production taxes....................... 3,480 5,653 7,055 4,941 6,271 ------- ------- -------- ------- ------- Total............................... 8,867 14,519 18,790 17,340 18,173 ------- ------- -------- ------- ------- Direct operating margin................... $41,235 $68,669 $ 81,543 $57,370 $73,398 ======= ======= ======== ======= ======= Average sales price Oil (Bbl).............................. $ 16.43 $ 20.47 $ 19.70 $ 13.29 $ 15.86 Gas (Mcf) (b).......................... 1.34 1.99 2.32 1.94 2.18 Mcfe (a)............................... 1.73 2.41 2.61 2.02 2.29 Average direct operating expense/Mcfe..... 0.31 0.43 0.49 0.49 0.46 Average production margin/Mcfe............ 1.42 1.99 2.12 1.54 1.83
_________________________________ (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. 3 Marketing The Company's oil and natural gas production is principally sold to end users, marketers, refiners and other purchasers having access to natural gas pipeline facilities near its properties and the ability to truck oil to local refineries or oil pipelines. The marketing of oil and natural gas can be affected by a number of factors that are beyond the Company's control and which cannot be accurately predicted. The Company does not believe, however, that the loss of any of its customers would have a long-term material adverse effect on its operations. Natural Gas. Wattenberg natural gas is high in heating content (BTU's) and must be processed in order to extract natural gas liquids ("NGL's") before the residue gas is sold to utilities, independent marketers and end users through both intrastate and interstate pipelines. The Company utilizes two separate arrangements to gather, process and market its natural gas production. Approximately 30% of the Company's natural gas production is sold to Duke Energy Field Services ("Duke Energy") at the wellhead under percentage of proceeds contracts. Pursuant to this type of contract, the Company receives a fixed percentage of the proceeds from the sale of its residue gas and NGL's by Duke Energy. Substantially all of the Company's remaining natural gas production is dedicated for gathering to either Duke Energy or HS Gathering, LLC ("HSG") and is processed at plants owned by Duke Energy or Amoco Production Company ("Amoco"). Under this arrangement, the Company retains the right to market its share of residue gas at the tailgate of the plant and sells it under spot market arrangements along the front range of Colorado or transports the gas to Midwest markets under transportation agreements. NGL's are sold by the processor and the Company receives payment net of applicable processing fees. A portion of the natural gas processed by Amoco at the Wattenberg Processing Plant is under a favorable "keepwhole" contract that not only provides payment for a percentage of the NGL's stripped from the natural gas, but also redelivers to the tailgate the same amount of MMBtu's as was delivered to the plant. This agreement remains in effect until December 2012. Oil. Oil production is principally sold to refiners, marketers and other purchasers who truck oil to local refineries or pipelines. The price is based on a local market posting for oil, which generally approximates a West Texas Intermediate posting, and is adjusted upward to reflect local demand and quality. Amoco has the right to purchase oil produced from certain of the Company's properties. Competition The oil and natural gas industry is highly competitive. The Company encounters competition from other oil and natural gas companies in all of its operations, including the acquisition of exploration and development prospects and producing properties. Patina competes for the acquisition of oil and natural gas properties with numerous entities, including major oil companies, other independent oil and natural gas concerns and individual producers and operators. Many competitors have financial and other resources substantially greater than those of the Company. The ability of the Company to increase reserves in the future will be dependent on its ability to select and acquire suitable producing properties and prospects for future development and exploration. Title to Properties Title to the Company's oil and natural gas properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the oil and natural gas industry, to liens incident to operating agreements and for current taxes not yet due and other comparatively minor encumbrances. As is customary in the oil and natural gas industry, only a perfunctory investigation as to ownership is conducted at the time undeveloped properties 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 oil and gas industry increases the cost of doing business, decreases flexibility in the timing of operations and may adversely affect the economics of capital projects. 4 In the past, the federal government has regulated the prices at which oil and natural gas could be sold. Prices of oil and natural gas sold by the Company are not currently regulated. In recent years, the Federal Energy Regulatory Commission ("FERC") has taken significant steps to increase competition in the sale, purchase, storage and transportation of natural gas. FERC's regulatory programs allow more accurate and timely price signals from the consumer to the producer and, on the whole, have helped natural gas become more responsive to changing market conditions. To date, the Company believes it has not experienced any material adverse effect as the result of these initiatives. Nonetheless, increased competition in natural gas markets can and does add to price volatility and inter-fuel competition, which increases the pressure on the Company to manage its exposure to changing conditions and position itself to take advantage of changing market forces. State statutes govern exploration and production operations, conservation of oil and natural gas resources, protection of the correlative rights of oil and natural gas owners and environmental standards. State Commissions implement their authority by establishing rules and regulations requiring permits for drilling, reclamation of production sites, plugging bonds, reports and other matters. Colorado, where the Company's producing properties are located, amended its statute concerning oil and natural gas development in 1994 to provide the Colorado Oil & Gas Conservation Commission (the "COGCC") with enhanced authority to regulate oil and natural gas activities to protect public health, safety and welfare, including the environment. Several rule makings pursuant to these statutory changes have been undertaken by the COGCC concerning groundwater protection, soil conservation and site reclamation, setbacks in urban areas and other safety concerns, and financial assurance for industry obligations in these areas. To date, these rule changes have not adversely affected operations of the Company, as the COGCC is required to enact cost-effective and technically feasible regulations, and the Company has been an active participant in their development. However, there can be no assurance that, in the aggregate, these and other regulatory developments will not increase the cost of conducting operations in the future. In Colorado, a number of city and county governments have enacted oil and natural gas regulations. These ordinances increase the involvement of local governments in the permitting of oil and natural gas operations, and require additional restrictions or conditions on the conduct of operations so as to reduce their impact on the surrounding community. Accordingly, these local ordinances have the potential to delay and increase the cost of drilling, refracing and recompletion operations. Environmental Regulation. Operations of the Company are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company currently owns or leases numerous properties that have been used for many years for natural gas and oil production. Although the Company believes that it and previous owners have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company. In connection with its most significant acquisitions, the Company has performed environmental assessments and found no material environmental noncompliance or clean-up liabilities requiring action in the near or intermediate future. Such environmental assessments have not, however, been performed on all of the Company's properties. The Company operates its own exploration and production waste management facilities, which enable it to treat, bioremediate and otherwise dispose of tank sludges and contaminated soil generated from the Company's operations. There can be no assurance, that these facilities, or other commercial disposal facilities utilized by the Company from time to time, will not give rise to environmental liability in the future. To date, expenditures for the Company's environmental control facilities and for remediation of production sites have not been significant. The Company believes, however, that the trend toward stricter standards in environmental legislation and regulations will continue and could have a significant adverse impact on the Company's operating costs and the oil and gas industry in general. Office and Operations Facilities The Company, a Delaware corporation, leases its principal executive offices at 1625 Broadway, Denver, Colorado 80202. The lease covers approximately 29,000 square feet and expires in November 2001. The monthly rent is approximately $43,000. The Company also owns a 6,000 square foot production facility in Platteville, Colorado used to support its Wattenberg Field operations. 5 Employees On December 31, 1999, the Company had 153 employees, including 91 that work in its field office. 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:
Name Age Position ---- --- -------- Thomas J. Edelman........... 49 Chairman of the Board and Chief Executive Officer Jay W. Decker............... 47 President and Director David J. Kornder............ 39 Vice President and Chief Financial Officer James A. Lillo.............. 45 Vice President Terry L. Ruby............... 41 Vice President David W. Siple.............. 40 Vice President Christopher C. Behrens...... 39 Director Robert J. Clark............. 55 Director Thomas R. Denison........... 39 Director Elizabeth K. Lanier......... 48 Director Alexander P. Lynch.......... 47 Director
- -------------------- Thomas J. Edelman has served as Chairman of the Board and Chief Executive Officer of the Company since its formation. He co-founded SOCO and was its President from 1981 through 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 Paradise Music & Entertainment, Inc. Jay W. Decker has served as President of the Company since March 1998 and as a Director since May 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 Vice President and Chief Financial Officer of the Company since May 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. James A. Lillo has served as a Vice President of the Company since May 1998. From 1995 to 1998, Mr. Lillo was President of James Engineering, Inc., an independent petroleum engineering consulting firm. 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. 6 Terry L. Ruby has served as a Vice President of the Company since May 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 of the Company since May 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 of the Company since February 1999. Mr. Behrens was been a general partner at Chase Capital Partners since 1999 and a principal since 1994. Chase Capital Partners is a General Partner of Chase Venture Capital Associates, L.P. 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 of the Company since May 1996. Mr. Clark is the President of Bear Paw Energy LLC, a private gas gathering and processing company, formerly a wholly owned subsidiary of TransMontaigne, Inc. Mr. Clark formed a predecessor company Bear Paw Energy Inc. in 1995 and joined TransMontaigne in 1996 when TransMontaigne acquired a majority interest in the predecessor company. From 1988 to 1995 he was President of SOCO Gas Systems, Inc. and Vice President - Gas Management for SOCO. Mr. Clark was Vice President Gas Gathering, Processing and Marketing of Ladd Petroleum Corporation, an affiliate of General Electric from 1985 to 1988. Prior to 1985, Mr. Clark held various management positions with NICOR, Inc. and its affiliate NICOR Exploration, Northern Illinois Gas and Reliance Pipeline Company. Mr. Clark received his Bachelor of Science Degree from Bradley University and his M.B.A. from Northern Illinois University. Thomas R. Denison has served as a Director of the Company since January 1998. Mr. Denison has been a Managing Director and General Counsel of First Reserve Corporation since January 1998. Prior to joining First Reserve, he was a partner in the international law firm of Gibson, Dunn & Crutcher LLP, a firm he joined in 1986 as an associate. Mr. Denison received his Bachelor of Science degree in Business Administration from the University of Denver and his Juris Doctor from the University of Virginia. Mr. Denison also serves as a Director of Anker Coal Group, Inc. Elizabeth K. Lanier has served as a Director of the Company since January 1998. Mrs. Lanier has served as Vice President and General Counsel of General Electric Power Systems since August 1998. From 1996 to 1998, Mrs. Lanier served as Vice President and Chief of Staff of Cinergy Corp. Mrs. Lanier received her Bachelor of Arts Degree with honors from Smith College 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 of the Company since May 1996. Mr. Lynch has been a General Partner of The Beacon Group, a private investment and financial advisory firm since 1997. From 1995 to 1996, Mr. Lynch was Co-President and Co-Chief Executive Officer of The Bridgeford Group, a financial advisory firm. From 1991 to 1994, he served as Senior Managing Director of Bridgeford. From 1985 until 1991, Mr. Lynch was a Managing Director of Lehman Brothers, a division of Shearson Lehman Brothers Inc. Mr. Lynch received his Bachelor of Arts Degree from the University of Pennsylvania and his M.B.A. from the Wharton School of Business at the University of Pennsylvania. Mr. Lynch also serves as a Director of Canadian National Railway Company. 7 ITEM 2. PROPERTIES General The Company's reserves are concentrated in the Wattenberg Field within the D-J Basin of north central Colorado. Discovered in 1970, the Field is located approximately 35 miles northeast of Denver and stretches over portions of Adams, Boulder and Weld counties in Colorado. One of the most attractive features of Wattenberg is the presence of several productive formations. In a section only 4,500 feet thick, there are up to eight potentially productive formations. Three of the formations, the Codell, Niobrara and J-Sand, are considered "blanket" zones in the area of the Company's holdings, while others, such as the D-Sand, Dakota and the shallower Shannon, Sussex and Parkman, are more localized. 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 new incremental reserves. These projects and the benefits of certain minor acquisitions and continued success with the production enhancement program allowed the Company to realize production growth during 1999 and increase its total proved reserves. During 1999, the Company drilled or deepened 36 wells to the J-Sand or Dakota formation. The cost of drilling and completing a J-Sand well approximates $315,000 while a completed deepening within an existing wellbore costs roughly $225,000. 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. Thus, the economics associated with a J-Sand project are more dependent on natural gas prices. The finding and development costs for the J-Sand and Dakota drilling and deepening projects for 1999 averaged $0.44 per Mcfe with projected rates of return in excess of 75% at current commodity prices. At December 31, 1999, the Company had 135 proven J-Sand drilling locations or deepening projects in inventory. The Company also performed 113 Codell refracs during 1999. The refrac program continues to be focused primarily on the Codell formation. A typical refrac costs approximately $103,000. The finding and development costs associated with the Company's 1999 refrac program averaged $0.57 per Mcfe with projected rates of return in excess of 100% at current commodity prices. At December 31, 1999, the Company had 546 proven refrac projects. Given the exceptional results of the 1999 refrac program, the 2000 budget activity has been increased to over 180 refrac projects. In addition to the development activity described above, the Company recompleted three wells. The Company has an additional 284 proven recompletion opportunities at December 31, 1999. During 1999, tubing was installed in another 37 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 Company's 1999 capital development program and continued increases in the Company's production. The Company estimates it had over 500 of these minor projects at year-end 1999. At December 31, 1999, the Company had working interests in approximately 3,400 gross (3,200 net) producing oil and natural gas wells in the D-J Basin and held royalty interests in an additional 176 producing wells. As of December 31, 1999 estimated proved reserves totaled 465.8 Bcfe, including 17.4 million barrels of oil and 361.3 Bcf of gas. 8 Proved Reserves The following table sets forth estimated year-end net proved reserves for the three years ended December 31, 1999.
December 31, ------------------------- 1997 1998 1999 ------- ------- ------- Oil (MBbl) Developed............................................................................. 14,594 13,655 16,633 Undeveloped........................................................................... 2,382 585 787 ------- ------- ------- Total............................................................................ 16,976 14,240 17,420 ======= ======= ======= Natural gas (MMcf) Developed............................................................................. 232,058 244,736 307,560 Undeveloped........................................................................... 23,577 41,859 53,701 ------- ------- ------- Total............................................................................ 255,635 286,595 361,261 ======= ======= ======= Total MMcfe................................................................................ 357,491 372,035 465,781 ======= ======= =======
The following table sets forth the estimated pretax future net revenues from the production of proved reserves and the pretax present value discounted at 10% of such revenues, net of estimated future capital costs, including estimated development costs of $33.5 million in 2000. December 31, 1999 ----------------------------- Developed Undeveloped Total --------- ----------- ----- (In thousands) Future Net Revenues ------------------- 2000..................... $ 78,757 $(5,846) $ 72,911 2001..................... 71,393 (2,001) 69,392 2002..................... 66,458 902 67,360 Remainder................ 528,026 85,065 613,091 -------- ------- -------- Total................. $744,634 $78,120 $822,754 ======== ======= ======== Pretax PW 10% Value (a).. $430,037 $27,505 $457,542 ======== ======= ======== - ------------------ (a) The after tax present value discounted at 10% of the proved reserves totaled $362.5 million at year-end 1999. 9 The quantities and values in the preceding tables are based on prices in effect at December 31, 1999, which averaged $24.27 per barrel of oil and $2.34 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, 1999. 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, 1999 were audited by Netherland, Sewell & Associates, Inc. ("NSAI"). Since January 1, 2000, the Company has filed Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by operators of domestic oil and gas properties. There are differences between the reserves as reported on Form EIA-23 and reserves as reported herein. Form EIA-23 requires that operator's 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. 10 Producing Wells The following table sets forth the producing wells in which the Company owned a working interest at December 31, 1999. The Company also held royalty interests in 176 producing wells at such date. The Company had 154 wells (148 net) shut in at December 31, 1999. The Company's average working interest in all wells was 95%. Wells are classified as oil or natural gas wells according to their predominant production stream. Principal Gross Net Production Stream Wells Wells ----------------- ----- ----- Oil............................................... 2,983 2,835 Natural gas....................................... 396 361 ----- ----- Total...................................... 3,379 3,196 ===== ===== 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. 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. 1997 1998 1999 ---- ---- ---- Productive Gross........................ 28.0 36.0 36.0 Net.......................... 28.0 36.0 35.0 Dry Gross........................ 1.0 0.0 0.0 Net.......................... 1.0 0.0 0.0 At December 31, 1999 no development wells were in progress. Acreage The following table sets forth the leasehold acreage held by the Company at December 31, 1999. 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. Developed Undeveloped --------- ----------- Gross Net Gross Net ----- --- ----- --- Colorado............. 188,000 177,000 54,000 48,000 ======= ======= ====== ====== In late 1999, the Company sold its undeveloped Wyoming acreage. 11 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS The Company's Common Stock, $12.50 Warrants and 7.125% Preferred Stock are listed on the New York Stock Exchange ("NYSE") under the symbols "POG", "POGWT" and "POGPr", respectively. Such listings became effective in May 1996. The Company's 8.50% Preferred Stock was privately placed and does not trade publicly. The following table sets forth the range of high and low closing prices as reported on the NYSE Composite Tape. Common Stock Warrants Preferred Stock ------------ -------- --------------- High Low High Low High Low ---- --- ---- --- ---- --- 1998 ---- First Quarter......... $7.75 $6.69 $1.63 $1.13 $29.50 $27.00 Second Quarter........ 7.81 6.50 1.56 1.13 29.56 25.94 Third Quarter......... 7.13 3.56 1.25 0.38 26.75 20.06 Fourth Quarter........ 4.56 2.38 0.63 0.22 21.50 17.19 1999 ---- First Quarter......... $4.19 $2.75 $0.41 $0.25 $19.25 $15.50 Second Quarter........ 6.31 3.88 0.75 0.31 23.25 19.00 Third Quarter......... 9.13 6.43 1.50 0.69 28.25 23.25 Fourth Quarter........ 9.13 7.13 1.25 0.44 27.13 25.25 On February 23, 2000, the closing prices of the Common Stock and Warrants were $9.13 and $1.19, respectively. All remaining shares of the 7.125% Preferred Stock were redeemed in January 2000. As of December 31, 1999, there were approximately 166 holders of record of the common stock and 16.1 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 common dividend was increased to $0.02 per common share in the fourth quarter of 1999. The Company currently 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 $1.1 million available for dividends on its common stock as of December 31, 1999. This amount was reset at $10.0 million at January 1, 2000. 12 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, 1999. 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.
As of or for the Year Ended December 31, ----------------------------------------------------- 1995 1996 1997 1998 1999 --------- --------- --------- --------- --------- (In thousands except per share data) Statement of Operations Data Revenues................................................ $ 50,102 $ 83,188 $100,333 $ 74,710 $ 91,571 Expenses Direct operating...................................... 8,867 14,519 18,790 17,340 18,173 Exploration........................................... 416 224 131 59 666 General and administrative............................ 5,974 6,151 7,154 7,139 6,185 Interest and other.................................... 5,476 14,304 16,038 13,001 10,844 Depletion, depreciation and amortization.............. 32,591 44,822 49,076 41,695 40,744 Impairment of oil and gas properties.................. - - 26,047 - - -------- -------- -------- -------- -------- Total expenses....................................... 53,324 80,020 117,236 79,234 76,612 -------- -------- -------- -------- -------- Income (loss) before taxes.............................. (3,222) 3,168 (16,903) (4,524) 14,959 Provision (benefit) for income taxes................... (1,128) (394) - - - -------- -------- -------- -------- -------- Net income (loss)....................................... $ (2,094) $ 3,562 $(16,903) $ (4,524) $ 14,959 ======== ======== ======== ======== ======== Basic net income (loss) per common share................ $ (0.15) $ 0.08 $ (1.11) $ (0.68) $ 0.52 ======== ======== ======== ======== ======== Diluted net income (loss) per common share.............. $ (0.15) $ 0.08 $ (1.11) $ (0.68) $ 0.50 ======== ======== ======== ======== ======== Basic weighted average shares outstanding............... 14,000 17,796 18,324 16,025 15,972 Diluted weighted average shares outstanding............. 14,000 17,796 18,324 16,025 16,471 Cash dividends per common share......................... $ 0.00 $ 0.00 $ 0.01 $ 0.04 $ 0.05 Balance Sheet Data Current assets....................................... $ 9,611 $ 27,587 $ 31,068 $ 23,325 $ 19,350 Oil and gas properties, net.......................... 214,594 398,640 342,833 324,777 308,035 Total assets......................................... 224,521 430,233 376,875 351,533 330,216 Current liabilities.................................. 9,611 26,572 30,297 23,579 19,108 Debt................................................. 75,000 197,594 146,435 142,021 132,000 Stockholders' equity................................. 113,663 196,236 188,441 175,976 165,890 Cash Flow Data Net cash provided by operations...................... $ 18,407 $ 52,996 $ 68,645 $ 34,331 $ 49,660 Net cash used by investing........................... (21,060) (9,796) (18,801) (23,145) (23,669) Net cash realized (used) by financing................ 2,653 (38,047) (43,388) (13,709) (35,451)
13 The following table sets forth unaudited summary financial results on a quarterly basis for the two most recent years.
1998 -------------------------------------- First Second Third Fourth -------- -------- -------- -------- (In thousands, except per share data) Revenues........................................................... $ 20,637 $ 18,327 $ 18,490 $ 17,256 Direct operating expenses.......................................... 4,637 4,258 4,198 4,247 Depletion, depreciation and amortization........................... 10,538 10,222 10,665 10,270 Net income (loss).................................................. 304 (1,501) (1,464) (1,863) Basic and diluted income (loss) per common share................... (0.08) (0.19) (0.19) (0.22)
1999 -------------------------------------- First Second Third Fourth -------- -------- -------- -------- (In thousands, except per share data) Revenues........................................................... $ 16,656 $ 20,447 $ 24,476 $ 29,992 Direct operating expenses.......................................... 4,122 4,454 4,762 4,835 Depletion, depreciation and amortization........................... 10,273 9,813 10,292 10,366 Net income (loss).................................................. (2,018) 1,742 5,280 9,955 Basic net income (loss) per common share........................... (0.23) 0.01 0.23 0.50 Diluted net income (loss) per common share......................... (0.23) 0.01 0.21 0.41
14 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Results of Operations Comparison of 1999 results to 1998. Revenues for 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 for 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. The Company's current development activity, the benefits of certain minor acquisitions and continued success with the production enhancement program has resulted in increasing production for six successive quarters. Based upon a $35.0 million capital budget for 2000, 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 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 the Company's 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 lower interest rates on the Company's debt due to the redemption of the 11.75% Subordinated Notes on July 15, 1999. The redemption was financed with borrowings under the bank credit facility. The 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. Comparison of 1998 results to 1997. Revenues for 1998 totaled $74.7 million, a 26% decrease from the prior year. The decrease was due primarily to a sharp decline in oil and gas prices and, to a lesser extent, lower production. The net loss in 1998 was $4.5 million compared to net loss of $16.9 million in 1997. The net loss in 1997 was primarily attributed to a $26.0 million impairment of oil and gas properties recorded in the fourth quarter of 1997. Exclusive of the non-cash impairment, the Company would have reported $9.1 million of net income in 1997. No impairment of oil and gas properties was recorded in 1998. 15 Average daily oil and gas production for 1998 totaled 4,654 barrels and 69.9 MMcf (97.8 MMcfe), decreases of 10% and 5%, respectively, from 1997. During 1998, 36 wells and 75 recompletions and refracs were placed on production, compared to 28 wells and 102 recompletions and refracs in 1997. Average oil prices decreased from $19.70 per barrel in 1997 to $13.29 in 1998. Average natural gas prices decreased from $2.32 per Mcf in 1997 to $1.94 in 1998. The average oil price includes hedging gains in 1997 and 1998 of $297,000 or $0.16 per barrel and $285,000 or $0.17 per barrel. The decrease in natural gas prices was primarily the result of the decrease in the average CIG and PEPL indexes for 1998 compared to 1997 and lower natural gas liquids prices in 1998. The average natural gas price for 1997 and 1998 included hedging gains of $2.0 million or $0.07 per Mcf and $1.7 million or $0.06 per Mcf. Direct operating expenses totaled $17.3 million or $0.49 per Mcfe in 1998 compared to $18.8 million or $0.49 per Mcfe in the prior year. The decrease in operating expenses was primarily attributed to the decrease in production taxes as a result of lower average product prices somewhat offset by increases in well workovers and more effective production methods. General and administrative expenses, net of third party reimbursements, for 1998 and 1997 totaled $7.1 million and $7.2 million, respectively. Included in general and administrative expense is $1.5 million and $2.0 million in 1998 and 1997 of non-cash expenses related to the common stock grants awarded to officers and managers of the Company in conjunction with the redistribution of SOCO's ownership of the Company in 1997. In the fourth quarter of 1998, the Company instituted a cost reduction program in response to the sharp decline in oil and gas prices. This plan resulted in the elimination of nine positions, or 15% of the Company's office staff, and the institution of additional cost cutting measures. The Company incurred approximately $500,000 of charges related to this restructuring. Interest and other expenses totaled $13.0 million in 1998, a decrease of $3.0 million or 19% from the prior year. Interest expense decreased as a result of lower average debt levels and the repurchase of over $22.0 million of face amount of 11.75% Subordinated Notes, through borrowings under the bank credit facility. The Company's average interest rate for 1998 was 10.0% compared to 9.6% in 1997. Depletion, depreciation and amortization expense for 1998 totaled $41.7 million, a decrease of $7.4 million or 15% from 1997. Depletion expense totaled $40.9 million or $1.14 per Mcfe, for 1998 compared to $46.2 million or $1.21 per Mcfe for 1997. The decrease in depletion expense resulted primarily from lower oil and natural gas production and a reduction of the depletion rate to $1.08 per Mcfe in the fourth quarter of 1998 due to the increase in proved reserves at December 31, 1998. Depreciation and amortization expense for 1998 totaled $807,000 or $0.02 per Mcfe compared to $2.9 million or $0.08 per Mcfe for 1997. Amortization expense for 1997 included $2.5 million related to the expensing of a noncompete agreement. Development, Acquisition and Exploration During 1999, the Company incurred $24.0 million in capital expenditures, including $21.1 million of development expenditures. During the period, the Company successfully drilled or deepened 36 wells, refraced 113 wells, and recompleted three wells. The Company also acquired additional interests in Wattenberg reserves for $2.2 million. The Company anticipates incurring approximately $35.0 million on the further development of its properties during 2000. 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, 1999, the Company had $330.2 million of assets. Total capitalization was $297.9 million, of which 56% was represented by stockholders" equity and 44% by bank debt. During 1999, net cash provided by operations totaled $49.7 million, as compared to $34.3 million in 1998 ($56.4 million and $37.0 million prior to changes in working capital, respectively). At December 31, 1999, there were no significant commitments for capital expenditures. The Company anticipates 2000 capital expenditures, exclusive of acquisitions, to approximate $35.0 million. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. The Company plans to finance its ongoing development, acquisition and exploration expenditures and additional equity security repurchases using internal cash flow, proceeds from asset sales and bank borrowings. In addition, joint ventures or future public and private offerings of debt or equity securities may be utilized. 16 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 $175.0 million at December 31, 1999. The Credit Agreement contains certain financial covenants, including but not limited to a maximum total debt to EBITDA ratio and a minimum current ratio. The Credit Agreement also contains certain negative covenants, including but not limited to restrictions on indebtedness; certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge causes; issuance of securities; and non-speculative commodity hedging. Borrowings under the Credit Agreement mature in July 2003, but may be prepaid at anytime. The Company has periodically negotiated extensions of the Credit Agreement; however, there is no assurance the Company will be able to do so in the future. The Company had a restricted payment basket, as defined by the Credit Agreement, of $1.1 million as of December 31, 1999, which may be used to repurchase common stock, preferred stock and warrants and pay dividends on its common stock. The restricted payment basket was reset at January 1, 2000 at $10.0 million. The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the higher of (a) the prime rate or (b) the Federal Funds Effective Rate plus .5%, or (ii) the rate at which Eurodollar deposits for one, two, three or six months (as selected by the Company) are offered in the interbank Eurodollar market plus a margin which fluctuates from 1.00% to 1.50%, determined by a debt to EBITDA ratio. The average interest rate under the facility approximated 6.6% during 1999 and was 7.2% at December 31, 1999. In October 1998, the Company entered into an interest rate swap contract for a two-year period, extendable for one additional year at the option of the third party. The contract is for $30.0 million principal with a fixed interest rate of 4.57% payable by the Company and the variable interest rate, the three- month LIBOR, payable by the third party. The difference between the Company's fixed rate of 4.57% and the three-month LIBOR rate, which is reset every 90 days, is received or paid by the Company in arrears every 90 days. The Company received $184,000 in 1999 pursuant to this contract. 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 accompanying 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 the appointment of a President in March 1998, the President purchased 100,000 shares of common stock at $6.875 per share. The Company loaned him $584,000, or 85% of the purchase price, represented by a recourse promissory note that bears interest at 8.50% per annum payable each March 31 until the note is paid. The note matures in March 2001 and is secured by the 200,000 shares purchased and granted to him in connection with his employment with the Company. The Company has entered into arrangements to monetize its Section 29 tax credits. These arrangements result in revenue increases of approximately $0.40 per Mcf on production volumes from qualified Section 29 properties. As a result, additional gas revenues of $1.8 million, $2.1 million and $2.9 million were recognized during 1997, 1998 and 1999, respectively. These arrangements are expected to increase revenues through December 31, 2002, at which point the tax credits expire. The Company's primary cash requirements will be to finance acquisitions, development expenditures, repayment of indebtedness, and general working capital needs. However, future cash flows are subject to a number of variables, including the level of production and oil and natural gas prices, and there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. 17 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. Year 2000 Issues The Company is aware of the issues associated with the programming code in many existing computer systems and devices with embedded technology. The "Year 2000" problem concerns the inability of information and technology-based operating systems to properly recognize and process date-sensitive information beyond December 31, 1999. Since 1997, the Company has been upgrading its information systems with Year 2000 compliant software and hardware. The conversion from calendar year 1999 to calendar year 2000 occurred without any disruption to the Company's operations or business systems. The Company will continue to monitor any Year 2000 issues, both internally and with third party dependencies with respect to vendors, suppliers, customers and other significant business relationships. Such monitoring will be on going and encompassed in normal operations. The total costs incurred to date in the assessment, evaluation and remediation of the Year 2000 matters plus any additional costs that may be incurred are expected to be less than management's original estimate of $100,000. Market and Commodity Risk The Company's major market risk exposure is in the pricing applicable to its oil and natural gas production. Realized pricing is primarily driven by the prevailing domestic price for 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 1999, exclusive of any hedges, ranged from a monthly low of $1.51 per Mcf to a monthly high of $2.70 per Mcf. Oil prices, exclusive of any hedges, ranged from a monthly low of $10.70 per barrel to a monthly high of $24.61 per barrel during 1999. Both oil and natural gas prices increased significantly from the first quarter to the fourth quarter of 1999. A significant decline in the prices of oil or natural gas could have a material adverse effect on the Company's financial condition and results of operations. 18 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 revenues in the period in which the associated production occurs. As of December 31, 1999, the Company had entered into swap contracts for oil (NYMEX based) for approximately 2,700 barrels of oil per day for 2000 at fixed prices ranging from $18.86 to $24.95 per barrel. Certain swap contracts for oil (NYMEX based) contain "knock out" provisions. These contracts cover 1,000 barrels of oil per day with a swap price of $21.00 per barrel and a "knock out" price of $16.00 per barrel for the period January 2000 to December 2000, 500 barrels of oil per day with a swap price of $22.20 per barrel and a "knock out" price of $17.00 per barrel for the period March 2000 to December 2000 and 500 barrels of oil per day with a swap price of $22.70 per barrel and a "knock out" price of $16.00 per barrel for the period March 2000 to June 2000. If the average price of NYMEX WTI crude oil falls below the "knock out" price for the contract month, the swaps will be considered "knocked out" and no payment will be made to the Company for the applicable month. The overall weighted average hedged price for the swap contracts is $21.17 per barrel for 2000 (NYMEX based). The unrecognized losses on these contracts totaled $1.9 million based on estimated market values at December 31, 1999. As of December 31, 1999, the Company had entered into natural gas swap contracts for approximately 17,000 MMBtu's per day for the period January 2000 through October 2000 at fixed prices ranging from $2.06 to $2.62 per MMBtu on CIG index based swap contracts. The Company also has entered into physical natural gas sale contracts for the delivery of approximately 15,000 of MMBtu's per day for the period January 2000 through March 2000 at prices ranging from $2.73 to $2.84 per MMBtu. The weighted average daily volumes and prices for these natural gas swaps and physical contracts are 21,500 MMBtu's per day at $2.30 per MMBtu for the period January 2000 through October 2000. The unrecognized gain on the swap contracts totaled $582,000 based on estimated market values at December 31, 1999. As of February 23, 2000, the Company was a party to the following fixed price swap and physical arrangements:
Oil (NYMEX) Gas (CIG) ---------------------- ----------------------- Average Daily Average Daily Time Period Volume (Bbl) $/Bbl Volume (MMbtu) $/MMbtu - ------------------------- -------------- ------ -------------- ------- 01/01/00 - 03/31/00.................. 3,500 $21.14 38,300 $2.56 04/01/00 - 06/30/00.................. 3,500 21.55 46,600 2.18 07/01/00 - 09/30/00.................. 3,500 22.21 41,700 2.17 10/01/00 - 12/31/00 (a).............. 2,700 21.51 13,500 2.17 01/01/01 - 06/30/01 (a).............. 1,000 23.20 - - 07/01/01 - 12/31/01 (a).............. 750 23.13 - -
(a) In addition to the "knock out" oil swaps entered into as of December 31, 1999 described above, the table includes additional "knock-out" swap contracts the Company has entered into subsequent to year-end. These contracts are for 500 barrels a day at a weighted average price of $22.38 per barrel for the fourth quarter of 2000 with a "knock out" provision of $16.00 per barrel, 1,000 barrels per day at a weighted average price of $23.20 for the first six months of 2001 and 750 barrels per day at a weighted average price of $23.13 per barrel for the final six months of 2001. Each of the 2001 contracts contain a "knock out" provision of $17.00 per barrel. 19 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 1998 and 1999. Average price computations exclude hedging gains and losses and other nonrecurring items to provide comparability. Average prices per Mcfe indicate the composite impact of changes in oil and natural gas prices. Oil production is converted to natural gas equivalents at the rate of one barrel per six Mcf.
Average Prices --------------------------------------- Natural Equivalent Oil Gas Mcf --- --- --- (Per Bbl) (Per Mcf) (Per Mcfe) Annual ------ 1995...................... $16.43 $1.34 $1.73 1996...................... 20.47 1.99 2.41 1997...................... 19.54 2.25 2.55 1998...................... 13.13 1.87 1.96 1999...................... 17.71 2.21 2.40 Quarterly --------- 1998 ---- First..................... $14.70 $2.04 $2.16 Second.................... 13.41 1.95 2.03 Third..................... 12.83 1.72 1.84 Fourth.................... 11.45 1.78 1.81 1999 ---- First..................... $11.65 $1.65 $1.72 Second.................... 16.10 1.99 2.17 Third..................... 19.90 2.48 2.68 Fourth.................... 23.01 2.63 2.92
20 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page ---- PATINA OIL & GAS CORPORATION Report of Independent Public Accountants............................... F-2 Consolidated Balance Sheets as of December 31, 1998 and 1999........... F-3 Consolidated Statements of Operations for the years ended December 31, 1997, 1998 and 1999.................................. F-4 Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1997, 1998 and 1999.............. F-5 Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1998 and 1999.................................. F-6 Notes to Consolidated Financial Statements............................. F-7
F-1 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, 1998 and 1999, 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, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Patina Oil & Gas Corporation and subsidiaries as of December 31, 1998 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles. Denver, Colorado, ARTHUR ANDERSEN LLP February 23, 2000 F-2 PATINA OIL & GAS CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands except share data)
December 31, --------------------- 1998 1999 --------- --------- ASSETS Current assets Cash and equivalents $ 10,086 $ 626 Accounts receivable 9,953 15,694 Inventory and other 3,286 3,030 --------- --------- 23,325 19,350 --------- --------- Oil and gas properties, successful efforts method 598,712 621,767 Accumulated depletion, depreciation and amortization (273,935) (313,732) --------- --------- 324,777 308,035 --------- --------- Gas facilities and other 6,692 3,790 Accumulated depreciation (4,590) (2,251) --------- --------- 2,102 1,539 --------- --------- Other assets, net 1,329 1,292 --------- --------- $ 351,533 $ 330,216 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 16,825 $ 14,993 Accrued liabilities 6,754 4,115 --------- --------- 23,579 19,108 --------- --------- Senior debt 68,000 132,000 Subordinated notes 74,021 - Other noncurrent liabilities 9,957 13,218 Commitments and contingencies Stockholders' equity Preferred Stock, $.01 par, 5,000,000 shares authorized, 3,166,860 and 2,383,328 shares issued and outstanding 32 24 Common Stock, $.01 par, 100,000,000 shares authorized, 15,752,389 and 16,131,310 shares issued and outstanding 158 161 Capital in excess of par value 206,792 188,545 Deferred compensation (1,038) (279) Retained earnings (deficit) (29,968) (22,561) --------- --------- 175,976 165,890 --------- --------- $ 351,533 $ 330,216 ========= =========
The accompanying notes are an integral part of these statements. F-3 PATINA OIL & GAS CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands except per share data)
Year Ended December 31, ---------------------------- 1997 1998 1999 -------- ------- ------- Revenues Oil and gas sales $ 99,539 $72,177 $90,407 Other 794 2,533 1,164 -------- ------- ------- 100,333 74,710 91,571 -------- ------- ------- Expenses Direct operating 18,790 17,340 18,173 Exploration 131 59 666 General and administrative 7,154 7,139 6,185 Interest and other 16,038 13,001 10,844 Depletion, depreciation and amortization 49,076 41,695 40,744 Impairment of oil and gas properties 26,047 - - -------- ------- ------- 117,236 79,234 76,612 -------- ------- ------- Income (loss) before taxes (16,903) (4,524) 14,959 -------- ------- ------- Provision (benefit) for income taxes Current - - - Deferred - - - -------- ------- ------- - - - -------- ------- ------- Net income (loss) $(16,903) $(4,524) $14,959 ======== ======= ======= Basic net income (loss) per common share $ (1.11) $ (0.68) $ 0.52 ======== ======= ======= Diluted net income (loss) per common share $ (1.11) $ (0.68) $ 0.50 ======== ======= ======= Basic weighted average shares outstanding 18,324 16,025 15,972 ======== ======= ======= Diluted weighted average shares outstanding 18,324 16,025 16,471 ======== ======= =======
The accompanying notes are an integral part of these statements. F-4 PATINA OIL & GAS CORPORATION CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS" EQUITY (In thousands)
Capital in Retained Preferred Stock Common Stock Excess of Deferred Earnings --------------- -------------- Shares Amount Shares Amount Par Value Compensation (Deficit) ------ ------ ------ ------ --------- ------------ --------- Balance, December 31, 1996 1,594 $ 16 18,887 $ 189 $ 194,066 $ - $ 1,965 Repurchase of common and preferred (126) (1) (3,101) (31) (32,723) - - Issuance of common - - 664 7 7,958 (1,828) - Issuance of preferred 1,600 16 - - 38,516 - - Preferred dividends and accretion 26 - - - 708 - (3,346) Common dividends - - - - - - (168) Net loss - - - - - - (16,903) ------ ------ ------ ------ --------- ------------ --------- Balance, December 31, 1997 3,094 31 16,450 165 208,525 (1,828) (18,452) Repurchase of common and preferred (68) (1) (1,338) (13) (8,676) - - Issuance of common - - 640 6 3,224 (688) - Preferred dividends and accretion 141 2 - - 3,719 - (6,335) Common dividends - - - - - - (657) Net loss - - - - - 1,478 (4,524) ------ ------ ------ ------ --------- ------------ --------- Balance, December 31, 1998 3,167 32 15,752 158 206,792 (1,038) (29,968) Repurchase of common and preferred (735) (7) (868) (9) (24,674) - (489) Conversion of preferred into common (168) (2) 489 4 - - - Issuance of common - - 758 8 3,108 (334) - Preferred dividends and accretion 119 1 - - 3,319 - (6,251) Common dividends - - - - - - (812) Net income - - - - - 1,093 14,959 ------ ------ ------ ------ --------- ------------ --------- Balance, December 31, 1999 2,383 $ 24 16,131 $ 161 $ 188,545 $ (279) $ (22,561) ====== ====== ====== ====== ========= ============ =========
The accompanying notes are an integral part of these statements. F-5 PATINA OIL & GAS CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
Year Ended December 31, --------------------------------------- 1997 1998 1999 -------- ---------- ------------ Operating activities Net income (loss) $ (16,903) $ (4,524) $ 14,959 Adjustments to reconcile net income (loss) to net cash provided by operations Exploration expense 131 59 666 Depletion, depreciation and amortization 49,076 41,695 40,744 Impairment of oil and gas properties 26,047 - - Deferred compensation expense 1,987 1,478 1.046 Amortization of deferred credits - (622) (1,211) Amortization of loan fees - - 152 Gain on sale of other assets (338) (1,124) - Changes in current and other assets and liabilities Decrease (increase) in Accounts receivable 4,548 5,354 (5,741) Inventory and other (213) 63 (180) Increase (decrease) in Accounts payable 5,639 (3,626) (1,833) Accrued liabilities (1,248) (3,092) (2,412) Other assets and liabilities (81) (1,330) 3,470 Net cash provided by operating activities --------- --------- --------- 68,645 34,331 49,660 --------- --------- --------- Investing activities Acquisition, development and exploration (19,831) (24,089) (24,003) Other 1,030 944 334 Net cash used by investing activities --------- --------- --------- (18,801) (23,145) (23,669) --------- --------- --------- Financing activities Decrease in indebtedness (51,159) (4,414) (10,021) Deferred credits 2,005 1,271 2,087 Loan origination fees - - (455) Issuance of preferred stock 39,432 - - Issuance of common stock 2,795 1,396 2,040 Cost of common stock and preferred issuance (900) - - Repurchase of common stock and warrants (28,946) (7,315) (6,582) Repurchase of preferred stock (3,809) (1,375) (18,106) Preferred stock redemption premium - - (489) Preferred dividends (2,638) (2,615) (3,113) Common dividends (168) (657) (812) --------- --------- --------- Net cash used by financing activities (43,388) (13,709) (35,451) --------- --------- --------- Increase (decrease) in cash 6,456 (2,523) (9,460) Cash and equivalents, beginning of period 6,153 12,609 10,086 --------- --------- --------- Cash and equivalents, end of period $ 12,609 $ 10,086 $ 626 ========= ========= =========
The accompanying notes are an integral part of these statements. F-6 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. In 1997, a series of transactions eliminated SOCO's ownership in the Company. The Company's operations currently consist of the acquisition, development, exploitation and production of oil and natural gas properties in the Wattenberg Field of Colorado's D-J Basin. (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Producing Activities The Company utilizes the successful efforts method of accounting for its oil and natural gas properties. Consequently, leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments in value are charged to expense. Exploratory expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined to be unsuccessful. Costs of productive wells, unsuccessful developmental wells and productive leases are capitalized and amortized on a unit-of-production basis over the life of the remaining proved or proved developed reserves, as applicable. Oil is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf. Amortization of capitalized costs has generally been provided over the entire Wattenberg Field, as the wells are located in the same reservoirs. No accrual has been provided for estimated future abandonment costs as management estimates that salvage value will approximate or exceed such costs. In 1995, the Company adopted Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets." SFAS 121 requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a field-by-field basis. During 1997, the Company recorded an impairment of $26.0 million to oil and gas properties as the estimated future cash flows (undiscounted and without interest charges) expected to result from these assets and their disposition, largely proven undeveloped drilling locations, was less than their net book value. The impairment primarily resulted from low year-end oil and natural gas prices. While no impairments were necessary in 1998 or 1999, 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 the estimated useful life of five years. Equipment is depreciated using the straight-line method with estimated useful lives ranging from three to five years. Other Assets Other Assets at December 31, 1998 and 1999 were comprised of $1.3 million and $988,000 of notes receivable from officers and key managers of the Company, respectively. See Note (9). At December 31, 1999, the balance also included net loan origination fees of $303,000. These fees are being amortized on a straight- line basis over 18 months. F-7 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 $1.8 million, $2.1 million and $2.9 million were recognized during 1997, 1998 and 1999, respectively. These arrangements are expected to increase revenues through December 31, 2002, at which point the tax credits expire. Gas Imbalances The Company uses the sales method to account for gas imbalances. Under this method, revenue is recognized based on the cash received rather than the Company's proportionate share of gas produced. Gas imbalances at December 31, 1998 and 1999 were insignificant. Financial Instruments The book value and estimated fair value of cash and equivalents was $10.1 million and $626,000 at December 31, 1998 and 1999. The book value and estimated fair value of the senior debt was $68.0 million and $132.0 million at December 31, 1998 and 1999. The book value of these assets and liabilities approximates fair value due to the short maturity or floating rate structure of these instruments. The book value of the Senior Subordinated Notes ("Subordinated Notes" or "Notes") was $74.0 million and the estimated fair value was $69.9 million at December 31, 1998. The Company redeemed the Notes in July 1999. From time to time, the Company enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. Commodity derivatives contracts, which are generally placed with major financial institutions or with counterparties of high credit quality that the Company believes are minimal credit risks, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these commodity derivatives contracts are based upon oil and natural gas futures which have a high degree of historical correlation with actual prices received by the Company. The Company accounts for its commodity derivative contracts using the hedge (deferral) method of accounting. Under this method, realized gains and losses on such contracts are deferred and recognized as an adjustment to oil and gas sales revenues in the period in which the physical product to which the contracts relate, is actually sold. Gains and losses on commodity derivative contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. The Company entered into various swap contracts for oil (NYMEX based) for 1997, 1998 and 1999. The Company recognized a loss of $27,000 in 1997, a gain of $238,000 in 1998 and a loss of $3.1 million in 1999 related to these swap contracts. The Company entered into various CIG and PEPL index based swap contracts for natural gas for 1997, 1998 and 1999. The Company recognized gains of $1.8 million and $1.5 million in 1997 and 1998 and a loss of $1.0 million in 1999 related to these swap contracts. As of December 31, 1999, the Company had entered into swap contracts for oil (NYMEX based) for approximately 2,700 barrels of oil per day for 2000 at fixed prices ranging from $18.86 to $24.95 per barrel. Certain swap contracts for oil (NYMEX based) contain "knock out" provisions. These contracts cover 1,000 barrels of oil per day with a swap price of $21.00 per barrel and a "knock out" price of $16.00 per barrel for the period January 2000 to December 2000, 500 barrels of oil per day with a swap price of $22.20 per barrel and a "knock out" price of $17.00 per barrel for the period March 2000 to December 2000 and 500 barrels of oil per day with a swap price of $22.70 per barrel and a "knock out" price of $16.00 per barrel for the period March 2000 to June 2000. If the average price of NYMEX WTI crude oil falls below the "knock out" price for the contract month, the swaps will be considered "knocked out" and no payment will be made to the Company for the applicable month. The overall weighted average hedged price for the swap contracts is $21.17 per barrel for 2000 (NYMEX based). The unrecognized losses on these contracts totaled $1.9 million based on estimated market values at December 31, 1999. F-8 As of December 31, 1999, the Company had entered into natural gas swap contracts for approximately 17,000 MMBtu's per day for the period January 2000 through October 2000 at fixed prices ranging from $2.06 to $2.62 per MMBtu on CIG index based swap contracts. The Company also has entered into physical natural gas sale contracts for the delivery of approximately 15,000 of MMBtu's per day for the period January 2000 through March 2000 at prices ranging from $2.73 to $2.84 per MMBtu. The weighted average daily volumes and prices for these natural gas swaps and physical contracts are 21,500 MMBtu's per day at $2.30 per MMBtu for the period January 2000 through October 2000. The unrecognized gain on the swap contracts totaled $582,000 based on estimated market values at December 31, 1999. As of February 23, 2000, the Company was a party to the following fixed price swap and physical arrangements:
Oil (NYMEX) Gas (CIG) -------------------- -------------- Average Daily Average Daily Time Period Volume (Bbl) $/Bbl Volume (MMbtu) $/MMbtu - ----------- ------------- ----- -------------- ------- 01/01/00 - 03/31/00........... 3,500 $21.14 38,300 $2.56 04/01/00 - 06/30/00........... 3,500 21.55 46,600 2.18 07/01/00 - 09/30/00........... 3,500 22.21 41,700 2.17 10/01/00 - 12/31/00 (a)....... 2,700 21.51 13,500 2.17 01/01/01 - 06/30/01 (a)....... 1,000 23.20 - - 07/01/01 - 12/31/01 (a)....... 750 23.13 - -
(a) In addition to the "knock out" oil swaps entered into as of December 31, 1999 described above, the table includes additional "knock-out" swaps the Company has entered into subsequent to year-end. These contracts are for 500 barrels a day at a weighted average price of $22.38 per barrel for the fourth quarter of 2000 with a "knock out" provision of $16.00 per barrel, 1,000 barrels per day at a weighted average price of $23.20 for the first six months of 2001 and 750 barrels per day at a weighted average price of $23.13 per barrel for the final six months of 2001. Each of the 2001 contracts contain a "knock out" provision of $17.00 per barrel. In October 1998, the Company entered into an interest rate swap contract for a two-year period, extendable for one additional year at the option of the third party. The contract is for $30.0 million principal with a fixed interest rate of 4.57% payable by the Company and the variable interest rate, the three- month LIBOR, payable by the third party. The difference between the Company's fixed rate of 4.57% and the three-month LIBOR rate, which is reset every 90 days, is received or paid by the Company in arrears every 90 days. The Company received $184,000 in 1999 pursuant to this contract. The unrecognized gain on this contract totaled $495,000 based on estimated market values at December 31, 1999. In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS 133 is effective for fiscal years beginning after June 15, 2000. The Company has not yet quantified the impacts of adopting SFAS 133 on its financial statements and has not determined the timing of, or method of, adoption of SFAS 133. However, SFAS 133 could increase volatility in earnings and other comprehensive income. F-9 Stock Options and Awards The Company accounts for its stock-based compensation plans under the principles prescribed by the Accounting Principles Board's Opinion No. 25 ("APB No. 25"), "Accounting for Stock Issued to Employees." Accordingly, stock options awarded under the Employee Plan and the Non-Employee Directors Plan are considered to be "noncompensatory" and do not result in recognition of compensation expense. However, the restricted stock awarded under the Restricted Stock Plan is considered to be "compensatory" and the Company recognized $2.0 million, $1.5 million and $1.0 million of non-cash general and administrative expenses for 1997, 1998 and 1999, respectively. See Note (6). Per Share Data The Company uses the weighted average number of shares outstanding in calculating earnings per share data. When dilutive, options and warrants are included as share equivalents using the treasury stock method and are included in the calculation of diluted per share data. Common stock issuable upon conversion of convertible preferred securities is also included in the calculation of diluted per share data if their effect is dilutive. Risks and Uncertainties Historically, the market for oil and natural gas has experienced significant price fluctuations. Prices for natural gas in the Rocky Mountain region have been particularly volatile in recent years. The price fluctuations can result from variations in weather, levels of production in the region, availability of transportation capacity to other regions of the country and various other factors. Increases or decreases in prices received could have a significant impact on the Company's future results. Supplemental Cash Flow Information The Company incurred the following significant non-cash items:
Year-Ended December 31, ----------------------- 1998 1999 ---- ---- Stock grant award................................ $ 688 $ 335 Stock Purchase Plan.............................. 173 53 Dividends and accretion - 8.50% preferred stock.. 3,720 3,321 401(k) profit sharing in common stock............ 338 483
The 1998 stock grant award represents 100,000 common shares granted to the President in conjunction with his appointment in the first quarter of 1998 and has been recorded as Deferred Compensation in the equity section of the accompanying consolidated balance sheets. The 1999 stock grant award represents 100,000 common shares granted to the Chief Executive Officer in conjunction with his voluntary reduction in cash salary, waiver of any 1998 bonus and other compensation arrangements in the second quarter of 1999. The Company recognized $1.5 million and $1.0 million of non-cash general and administrative expenses for 1998 and 1999 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. All significant intercompany balances and transactions have been eliminated in consolidation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. F-10 (3) OIL AND GAS PROPERTIES The cost of oil and gas properties at December 31, 1998 and 1999 included approximately $585,000 and $225,000 in net unevaluated leasehold costs related to a prospect in Wyoming. Acreage is generally held for exploration, development or resale and its value, if any, is excluded from amortization. The following table sets forth costs incurred related to oil and gas properties: 1997 1998 1999 -------- ------- ------- (In thousands) Acquisition............ $ 2,225 $ 2,319 $ 2,215 Development............ 17,013 21,711 21,122 Exploration and other.. 131 59 666 ------- ------- ------- $19,369 $24,089 $24,003 ======= ======= ======= (4) INDEBTEDNESS The following indebtedness was outstanding on the respective dates: December 31, ----------------------- 1998 1999 ------- ------- (In thousands) Bank facilities................. $68,000 $132,000 Less current portion............ - - ------- -------- Senior debt, net................ $68,000 $132,000 ======= ======== Subordinated notes.............. $74,021 $ - ======= ======== In July 1999, in conjunction with the redemption of the 11.75% Senior Subordinated Notes, the Company entered into a Second Amended and Restated Bank Credit Agreement (the "Credit Agreement"). The Credit Agreement is a revolving credit facility in an aggregate amount up to $200.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and equaled $175.0 million at December 31, 1999. The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the higher of (a) the prime rate or (b) the Federal Funds Effective Rate plus .5%, or (ii) the rate at which Eurodollar deposits for one, two, three or six months (as selected by the Company) are offered in the interbank Eurodollar market plus a margin which fluctuates from 1.00% to 1.50%, determined by a debt to EBITDA ratio. The average interest rate under the facility approximated 6.6% during 1999 and was 7.2% at December 31, 1999. In October 1998, the Company entered into an interest rate swap contract for a two-year period, extendable for one additional year at the option of the third party. The contract is for $30.0 million principal with a fixed interest rate of 4.57% payable by the Company and the variable interest rate, the three- month LIBOR, payable by the third party. The difference between the Company's fixed rate of 4.57% and the three-month LIBOR rate, which is reset every 90 days, is received or paid by the Company in arrears every 90 days. The Company received $184,000 in 1999 pursuant to this contract. 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. F-11 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 $1.1 million as of December 31, 1999, which may be used to repurchase common stock, preferred stock and warrants and pay dividends on its common stock. The restricted payment basket was reset at January 1, 2000 at $10.0 million. In conjunction with the Gerrity Acquisition, the Company assumed $100.0 million of 11.75% Senior Subordinated Notes due July 15, 2004. Under purchase accounting, the Notes were reflected in the financial statements at a book value of 105.875% of their principal amount, their initial call price as of July 15, 1999. The Notes became redeemable on July 15, 1999. The Company redeemed all of the Notes at the call price of 105.875% on July 15, 1999. The redemption was financed with borrowings under the bank credit facility. Scheduled maturities of indebtedness for the next five years are zero for 2000, 2001, 2002 and $132.0 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 $16.5 million, $14.0 million and $14.3 million during 1997, 1998 and 1999, respectively. (5) STOCKHOLDERS" EQUITY A total of 100,000,000 common shares, $0.01 par value, are authorized of which 16,131,310 were issued and outstanding at December 31, 1999. 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 and was continued through the third quarter of 1999. The common dividend was increased to $0.02 per common share in the fourth quarter of 1999. The following is a schedule of the changes in the Company's shares of common stock:
1997 1998 1999 ----------- ----------- ----------- Beginning Common Shares Outstanding.......... 18,886,900 16,450,400 15,752,400 Sale of shares to management................. 303,800 100,000 - Shares issued to 8.50% preferred investors... 160,000 - - Exercise of stock options.................... 11,700 - 226,300 Shares issued under Stock Purchase Plan...... - 180,900 92,900 Shares issued in lieu of salaries & bonuses.. - 76,700 164,800 Shares issued for directors fees............. 4,500 11,900 8,600 Conversion of 7.125% preferred............... - - 488,800 Shares issued to deferred compensation plan.. - - 35,200 Stock grant (vested)......................... 124,000 131,600 168,600 401(K) profit sharing contribution........... 59,900 138,500 61,300 Shares repurchased and retired............... (3,100,400) (1,337,600) (867,600) ---------- ---------- ---------- Ending Common Shares Outstanding............. 16,450,400 15,752,400 16,131,300 ========== ========== ==========
At December 31, 1999, the Company had 2,919,451 $12.50 common stock warrants outstanding. These warrants are exercisable at $12.50 for one share of common stock and expire in May 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. At December 31, 1999, the Company had 2,383,328 shares outstanding related to two issues of preferred stock consisting of 7.125% preferred shares and 8.50% preferred shares. At December 31, 1999 there were 564,817 shares of 7.125% preferred stock outstanding with an aggregate liquidation preference of $14.1 million. Each share of 7.125% preferred stock is convertible into common stock at any time at $8.61 per share, or 2.9036 common shares. The 7.125% preferred stock pays quarterly cash dividends, when declared by the Board of Directors, based on an annual rate of $1.78 per share. The 7.125% preferred stock is currently redeemable at the option of the Company at $26.069 per share. The liquidation preference of the 7.125% preferred stock is $25.00 per share, plus accrued and unpaid dividends. In September 1999, the Company called for F-12 redemption one-half of its 7.125% preferred stock. The effective date of the redemption was October 25, 1999. Of the 625,600 preferred shares called, 168,300 were converted into 488,800 shares of common stock and the remaining 457,300 were redeemed for $12.0 million in cash. The cash redemption was financed with borrowings under the bank credit facility. In December 1999, the Company called for redemption the remainder of its 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. Holders of the 7.125% preferred stock are not generally entitled to vote, except with respect to certain limited matters. The Company paid $2.6 million, $2.6 million and $2.7 million in preferred dividends during 1997, 1998 and 1999, and had accrued an additional $327,000 and $114,000 at December 31, 1998 and 1999, respectively, for dividends. Included in the $2.7 million of preferred stock dividends paid in 1999 was $489,000 of redemption premium paid to shareholders that elected to redeem their preferred stock for cash on October 25, 1999. At December 31, 1999, there were 1,818,511 shares of 8.50% preferred stock outstanding with an aggregate liquidation preference of $45.5 million. Each share of the 8.50% preferred stock is convertible into common stock at any time at $9.50 per share or 2.6316 common shares. The 8.50 % preferred stock pays quarterly dividends, when declared by the Board of Directors, and are payable- in-kind ("PIK Dividend") until October 1999, and in cash thereafter. The 8.50% preferred stock is redeemable at the option of the Company at any time after October 2000 at 106% of its stated value declining by 2% per annum thereafter. The liquidation preference is $25.00 per share, plus accrued and unpaid dividends. The 8.50% preferred stock is privately held. Holders of the 8.50% preferred stock are generally entitled to vote with the common stock, based upon the number of shares of common stock into which the shares of 8.50% preferred stock are convertible. The Company paid $661,000, $3.5 million, and $3.7 million in dividends during 1997, 1998 and 1999, respectively. Dividends through October 21, 1999 were paid in kind ("PIK"). As such, the Company issued 26,437, 141,240 and 119,577 of additional 8.50% preferred shares as PIK dividends in 1997, 1998 and 1999, respectively. Dividends subsequent to October 21, 1999 of $737,000 were paid in cash in the fourth quarter of 1999. The Company adopted Statement of Financial Accounting Standards No. 128 ("SFAS 128"), "Earnings per Share" during 1997. SFAS 128 specifies computation, presentation and disclosure requirements for earnings per share for entities with publicly held common stock or potential common stock.
Year Ended December 31, -------------------------------------------------------------------------------------- 1997 1998 1999 -------------------------------------------------------------------------------------- Net Common Per Net Common Per Net Common Per Loss Shares Share Loss Shares Share Income Shares Share ---- ------ ------- ---- ------ ------ ------ ------ ----- Basic net income (loss) $ (16,903) 18,324 $ (4,524) 16,025 $14,959 15,972 7.125% preferred stock dividends (2,638) - (2,615) - (2,681) - - 8.50% preferred stock dividends (661) - (3,531) - (3,727) - Preferred stock accretion (47) - (189) - (331) - -------- ------ ------ ------ ------ ------ Basic net income (loss) attributable to common stock (20,249) 18,324 $(1.11) (10,859) 16,025 $ (0.68) 8,220 15,972 $0.52 ====== ======= ===== Effect of dilutive securities: 7.125% preferred stock - - - - - - 8.50% preferred stock - - - - - - Stock options - - - - - 222 Stock grant - - - - - 277 $12.50 common stock warrants - - - - - - --------- ------ -------- -------- -------- ------- Diluted net income (loss) attributab to common stock $ (20,249) 18,324 $(1.11) $(10,859) 16,025 $ (0.68) $ 8,220 16,471 $0.50 ========= ====== ====== ======== ======== ======= ======== ====== =====
The potential common stock equivalents of the 7.125% and 8.50% preferred stock, $12.50 common stock warrants and stock options were anti-dilutive for all periods presented except 1999. F-13 (6) EMPLOYEE BENEFIT PLANS 401(k) Savings The Company has a 401(k) profit sharing and savings plan (the "401(k) Plan"). Eligible employees may make voluntary contributions to the 401(k) Plan. The amount of employee contributions is limited as specified in the 401(k) Plan. The Company may, at its discretion, make additional matching or profit sharing contributions to the 401(k) Plan. The Company has historically made profit sharing contributions to the 401(k) Plan, which totaled $453,000, $338,000 and $483,000 for 1997, 1998 and 1999, respectively. The profit sharing contributions were made in shares of the Company's common stock of 59,900, 138,500 and 61,300 common shares in 1997, 1998 and 1999, respectively. Stock Purchase Plan In 1998, the Company adopted and the stockholders approved a stock purchase plan ("Stock Purchase Plan"). Pursuant to the Stock Purchase Plan, officers, directors and certain managers are eligible to purchase shares of common stock at prices ranging from 50% to 85% of the closing price of the stock on the trading day prior to the date of purchase ("Closing Price"). In addition, employee participants may be granted the right to purchase shares pursuant to the Stock Purchase Plan with all or a part of their salary and bonus. A total of 500,000 shares of common stock are reserved for possible purchase under the Stock Purchase Plan. In May 1999, an amendment to the Stock Purchase Plan was approved by the stockholders allowing for the annual renewal of the 500,000 shares of common stock reserved for possible purchase under the Plan. In 1998, the Board of Directors approved 291,300 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. The Company recorded non-cash general and administrative expenses of $173,000 and $53,000 associated with these purchases for 1998 and 1999, respectively. Stock Option and Award Plans In 1996, the shareholders adopted a stock option plan for employees providing for the issuance of options at prices not less than fair market value. Options to acquire the greater of up to three million shares of common stock or 10% of outstanding diluted common shares may be outstanding at any given time. The specific terms of grant and exercise are determinable by a committee of independent members of the Board of Directors. A summary by year of stock options granted under the stock option plan for employees is summarized below:
Weighted Range Average of Exercise Exercise Options Price Per Price Per Year Granted Common Share Common Share ---- ------- ------------- ------------ 1996......... 512,000 $7.75 $7.75 1997......... 521,000 $8.75 - $9.88 $9.75 1998......... 614,000 $6.56 - $7.19 $7.03 1999......... 630,000 $2.94 - $9.13 $3.54
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. F-14 In 1996, the shareholders adopted a 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 and 8,600 were issued in 1999. 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
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 vest at 25% per year on January 1, 1998, 1999, 2000 and 2001. The non-vested granted common shares have been recorded as Deferred Compensation in the equity section of the accompanying consolidated balance sheets. The Management Investors simultaneously purchased additional common shares from the Company at $9.875 per share. A portion of the purchase ($404,000) was financed by the Company. See Note (9). In conjunction with the appointment of a President in March 1998, the President was included in the stock grant and purchase plans. He was granted 100,000 restricted common shares that vest at 33% per year in March 1999, 2000 and 2001. The non-vested granted common shares have been recorded as Deferred Compensation in the equity section of the accompanying consolidated balance sheets. The President simultaneously purchased 100,000 common shares from the Company at $6.875 per share. A portion of this purchase ($584,000) was financed by the Company. See Note (9). In April 1999, the Chief Executive Officer was granted 100,000 restricted shares of common stock in consideration of his voluntary reduction in cash salary, waiver of any 1998 bonus and other compensation arrangements. The shares vested ratably throughout 1999. The Company recognized $2.0 million, $1.5 million and $1.0 million of non- cash general and administrative expenses for 1997, 1998 and 1999 with respect to these stock grants. At December 31, 1999, 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: F-15 1997 1998 1999 ---- ---- ---- Net income (loss) As Reported $(16,903) $(4,524) $14,959 Pro forma (18,611) (5,724) 13,954 Basic net income (loss) per common share As Reported $ (1.11) $ (0.68) $ 0.52 Pro forma (1.20) (0.75) 0.45 Diluted net income (loss) per common share As Reported $ (1.11) $ (0.68) $ 0.50 Pro forma (1.20) (0.75) 0.44 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 1997, 1998 and 1999: dividend yield of 0%, 0% and 1%; expected volatility of 35%, 46% and 47%; risk-free interest rate of 6.0%, 5.5% and 5.2%; and expected life of 4.5 years, 4.5 years and 4.5 years, respectively. A summary of the status of the Company's fixed stock option plan as of December 31, 1997, 1998 and 1999 and changes during the years are presented below:
1997 1998 1999 -------------------- -------------------- -------------------- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price ---------- -------- ---------- -------- ---------- -------- Outstanding at beginning of year........ 503,000 $7.75 1,001,000 $8.70 1,526,000 $8.07 Granted................................. 551,000 9.53 649,000 7.06 660,000 3.60 Exercised............................... (12,000) 7.75 - - (226,000) 6.43 Forfeited............................... (41,000) 8.38 (124,000) 7.91 (220,000) 8.05 --------- --------- --------- Outstanding at end of year.............. 1,001,000 $8.70 1,526,000 $8.07 1,740,000 $6.59 ========= ========= ========= Options exercisable at year-end......... 389,000 582,000 747,000 ========= ========= ========= Weighted-average fair value of options granted during the year.............. $3.84 $3.17 $1.48
The following table summarizes information about fixed stock options outstanding at December 31, 1999:
Options Outstanding Options Exercisable -------------------------------- ------------------- Number Number Outstanding at Weighted-Avg. Weighted- Exercisable at Weighted- December 31, Remaining Average December 31, Average Exercise Price 1999 Contractual Life Exercise Price 1999 Exercise Price - ---------------- -------------- ---------------- -------------- ------------------- -------------- $2.94 to 5.13.............. 588,000 4.2 years $3.54 - $ - 6.56 to 7.75.............. 730,000 2.5 years 7.30 399,000 7.51 7.81 to 10.31............. 422,000 2.6 years 9.59 348,000 9.69 --------- ------- $2.94 to 10.31............. 1,740,000 3.1 years $6.59 747,000 $8.53 ========= =======
F-16 (7) FEDERAL INCOME TAXES Prior to the Gerrity Acquisition, the Company had been included in SOCO's consolidated tax return. Current and deferred income tax provisions allocated by SOCO were determined as though the Company filed as an independent company, making the same tax return elections used in SOCO's consolidated return. Since the Gerrity Acquisition, the Company has filed its own tax returns. A reconciliation of the federal statutory rate to the Company's effective rate as it applies to the provision (benefit) for the years ended December 31, 1997, 1998 and 1999 follows:
1997 1998 1999 ---------- --------- -------- Federal statutory rate...................................................................... (35%) (35%) 35% Increase (decrease) in valuation allowance against deferred tax asset....................... 35% 35% (35%) -------- ------- ------ Effective income tax rate - - - ======== ======= ====== For book purposes the components of the net deferred asset and liability at December 31, 1998 and 1999 were: 1998 1999 ---- ---- (In thousands) Deferred tax assets NOL carryforwards........................................................................ $ 29,080 $30,940 Deferred deductions and other............................................................ 4,941 4,025 -------- ------- 34,021 34,965 ------- ------ Deferred tax liabilities Depreciable and depletable property.................................................... 20,582 26,812 -------- ------ Deferred tax assets......................................................................... 13,439 8,153 -------- ------ Valuation allowance......................................................................... (13,439) (8,153) -------- ------ Net deferred tax asset...................................................................... $ - $ - ======== =======
For tax purposes, the Company had regular net operating loss carryforwards of approximately $88.4 million and alternative minimum tax ("AMT") loss carryforwards of approximately $42.0 million at December 31, 1999. Utilization of the regular and AMT 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 $31.9 million regular net operating loss carryforwards and $31.6 million AMT loss carryforwards will be limited to $5.2 million per year as a result of the Gerrity Acquisition in May 1996. These carryforwards expire from 2006 through 2018. At December 31, 1999, the Company had alternative minimum tax credit carryforwards of $650,000 that are available indefinitely. No cash payments were made by the Company for federal taxes during 1997 and 1999. The Company paid $239,000 of federal taxes during 1998. (8) MAJOR CUSTOMERS During 1997, 1998 and 1999, Duke Energy Field Services, Inc. accounted for 41%, 38% and 37%, Amoco Production Company accounted for 16%, 13% and 24%, Enron North America accounted for 5%, 10%, and 4% and Aurora Natural Gas, LLC accounted for 0%, 0% and 10% of revenues, respectively. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company. F-17 (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 ($404,000) has been financed by the Company through the issuance of 8.50% recourse promissory notes. These notes are secured by the common stock purchased and additional common shares granted to the respective officers and managers. Interest is due annually and the notes mature in January 2001. These notes have been reflected as Other Assets in the accompanying consolidated balance sheets. In conjunction with the appointment of a President in March 1998, the President purchased 100,000 shares of common stock at $6.875 per share. The Company loaned him $584,000, or 85% of the purchase price, represented by a recourse promissory note that bears interest at 8.50% per annum payable each March 31 until the note is paid. The note matures in March 2001 and is secured by all of the shares purchased and granted to him (100,000 shares) in connection with his employment with the Company. The note has been reflected as Other Assets in the accompanying consolidated balance sheets. In consideration of the then depressed stock price and overall lower 1998 bonuses, the interest due as of March 31, 1999 under the Management Investors" and President's notes was forgiven. (10) COMMITMENTS AND CONTINGENCIES The Company leases office space and certain equipment under non-cancelable operating leases. Future minimum lease payments under such leases approximate $500,000 per year from 2000 through 2001. The Company is a party to various lawsuits incidental to its business, none of which are anticipated to have a material adverse impact on its financial position or results of operations. (11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION Independent petroleum consultants audited the Company's total proved reserves at December 31, 1997, 1998 and 1999. All reserve estimates are based on economic and operating conditions at that time. Future net cash flows as of each year-end were computed by applying then current prices to estimated future production less estimated future expenditures (based on current costs) to be incurred in producing and developing the reserves. All reserves are located onshore in the United States. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. With respect to certain properties that historically have experienced seasonal curtailment, the reserve estimates assume that the seasonal pattern of such curtailment will continue in the future. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. The data in the tables below represent estimates only. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those shown below. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. Results in drilling, testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered. F-18 Quantities of Proved Reserves Oil Natural Gas ------- ------------ (MBbl) (MMcf) Balance, December 31, 1996.............. 22,475 296,659 Revisions.............................. (4,418) (27,671) Extensions, discoveries and additions.. 784 11,162 Production............................. (1,889) (26,863) Purchases.............................. 101 3,193 Sales.................................. (77) (845) ------ ------- Balance, December 31, 1997.............. 16,976 255,635 Revisions.............................. (3,033) (23,084) Extensions, discoveries and additions.. 1,890 77,120 Production............................. (1,699) (25,522) Purchases.............................. 108 2,465 Sales.................................. (2) (19) ------ ------- Balance, December 31, 1998.............. 14,240 286,595 Revisions.............................. 1,665 18,498 Extensions, discoveries and additions.. 3,006 66,191 Production............................. (1,653) (29,477) Purchases.............................. 202 20,425 Sales.................................. (40) (971) ------ ------- Balance, December 31, 1999.............. 17,420 361,261 ====== ======= Proved Developed Reserves Oil Natural Gas ------ ----------- (MBbl) (MMcf) December 31, 1996.......................... 15,799 242,777 ====== ======= December 31, 1997.......................... 14,594 232,058 ====== ======= December 31, 1998.......................... 13,655 244,736 ====== ======= December 31, 1999.......................... 16,633 307,560 ====== ======= F-19 Standardized Measure December 31, ----------------------------------- 1997 1998 1999 ---------- ---------- ----------- (In thousands) Future cash inflows..................... $ 894,390 $ 692,747 $1,273,591 Future costs Production............................. (255,599) (220,846) (323,859) Development............................ (87,414) (68,125) (126,978) --------- --------- ---------- Future net cash flows................... 551,377 403,776 822,754 Undiscounted income taxes............... (89,094) (41,977) (192,956) --------- --------- ---------- After tax net cash flows................ 462,283 361,799 629,798 10% discount factor..................... (185,953) (156,395) (267,270) --------- --------- ---------- Standardized measure.................... $ 276,330 $ 205,404 $ 362,528 ========= ========= ========== Changes in Standardized Measure December 31, --------------------------------- 1997 1998 1999 ---------- ---------- --------- (In thousands) Standardized measure, beginning of year.. $ 499,936 $ 276,330 $ 205,404 Revisions: Prices and costs..................... (312,526) (124,977) 188,474 Quantities........................... 6,134 8,396 3,642 Development costs.................... (14,783) (3,310) (3,003) Accretion of discount................ 49,994 27,633 20,540 Income taxes......................... 105,189 23,944 (75,287) Production rates and other........... (8,433) (5,449) (6,299) --------- --------- ---------- Net revisions........................ (174,425) (73,763) 128,067 Extensions, discoveries and additions.... 11,756 33,910 64,048 Production............................... (81,149) (54,837) (72,234) Future development costs incurred........ 17,013 21,711 21,122 Purchases (a)............................ 3,900 2,068 17,026 Sales (b)................................ (701) (15) (905) --------- --------- ---------- Standardized measure, end of year........ $ 276,330 $ 205,404 $ 362,528 ========= ========= ========== (a) "Purchases" includes the present value at the end of the period acquired during the year plus cash flow received on such properties during the period, rather than their estimated present value at the time of the acquisition. (b) "Sales" represents the present value at the beginning of the period of properties sold, less the cash flow received on such properties during the period. F-20 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. * 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. * 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) F-21 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 Sublease Agreement dated as of May 1, 1996 by and between Snyder Oil Corporation, as Sublandlord, and the Company, as Subtenant. (Incorporated herein by reference to Exhibit 10.4 of the Company's Form 10-Q for the quarter ended June 30, 1996) 10.5.2 Sublease Agreement dated as of October 7, 1996 by and between Gerrity Oil & Gas Corporation, as Sublandlord, and Shadownet Technologies, L.L.C. (Incorporated herein by reference to Exhibit 10.4 of the Company's Form 10-Q for the quarter ended September 30, 1996) 10.6 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) 11 Computation of Per Share Earnings.* 12 Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.* 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, 1999. F-22 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. /s/ Thomas J. Edelman Chairman of the Board February 24, 2000 - --------------------- Thomas J. Edelman (Principal Executive Officer) /s/ Jay W. Decker President and Director February 24, 2000 - ----------------- Jay W. Decker /s/ David J. Kornder Vice President and February 24, 2000 - -------------------- David J. Kornder Chief Financial Officer /s/ Christopher C. Behrens Director February 24, 2000 - -------------------------- Christopher C. Behrens /s/ Robert J. Clark Director February 24, 2000 - ------------------- Robert J. Clark /s/ Thomas R. Denison Director February 24, 2000 - --------------------- Thomas R. Denison /s/ Elizabeth K. Lanier Director February 24, 2000 - ----------------------- Elizabeth K. Lanier /s/ Alexander P. Lynch Director February 24, 2000 - ---------------------- Alexander P. Lynch F-23 EX-10.1.2 2 RESTATED CREDIT AGREEMENT EXHIBIT 10.1.2 FIRST AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT --------------------------------------------------------------- This First Amendment to Second Amended and Restated Credit Agreement (this First Amendment) is executed as of the 25th day of October, 1999, by and among - --------------- Patina Oil & Gas Corporation, a Delaware Corporation (Borrower), Chase Bank of -------- Texas, National Association, as Administrative Agent (Administrative Agent), and -------------------- the financial institutions parties hereto as Banks (individually a Bank and ---- collectively Banks). ----- W I T N E S E T H: - - - - - - - - - WHEREAS, Borrower, Administrative Agent and Banks are parties to that certain Second Amended and Restated Credit Agreement dated as of July 15, 1999 (as amended, the Credit Agreement) (unless otherwise defined herein, all terms ---------------- used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement); and WHEREAS, pursuant to the Credit Agreement, Banks have made a revolving credit loan to Borrower; and WHEREAS, Borrower has (a) notified Administrative Agent and Banks that effective October 25, 1999 Borrower redeemed 623,000 shares of its Original Preferred Stock, 457,000 shares of which were redeemed for $12,000,000 in cash, and (b) requested that the Credit Agreement be amended to revise Section 10.2 thereof as set forth herein in connection therewith; and WHEREAS, Borrower and Banks desire to set forth herein the amount of the Borrowing Base for the period commencing on November 1, 1999 and continuing until the next succeeding Determination Date. NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, Borrower, Administrative Agent and each Bank hereby agree as follows: SECTION 1. Amendments. In reliance on the representations, warranties, --------- ---------- covenants and agreements contained in this First Amendment and subject to the terms and conditions set forth herein, the Credit Agreement shall be amended effective as of the date hereof in the manner provided in this Section 1. --------- 1.1. Amendment to Definition. The definition of Loan Papers contained in ----------------------- ----------- Section 2.1 of the Credit Agreement shall be amended to read in full as follows: Loan Papers means this Agreement, the First Amendment, the Notes, each ----------- Restricted Subsidiary Guarantee now or hereafter executed, each Restricted Subsidiary Pledge Agreement now or hereafter executed, all Mortgages now or at any time hereafter delivered pursuant to Section 6.1, the Collateral ----------- Assignment, and all other certificates, documents or instruments delivered in connection with this Agreement, as the foregoing may be amended from time to time. 1 1.2. Additional Definitions. Section 2.1 of the Credit Agreement shall be ---------------------- amended to add the following definitions to such Section: First Amendment means the First Amendment to Second Amended and --------------- Restated Credit Agreement dated as of October 25, 1999, entered into by and among Borrower, Administrative Agent and Banks. Qualified Redemption means a one-time redemption by Borrower of -------------------- 623,000 shares of the Original Preferred Stock, of which (i) 166,000 shares are converted into 482,000 shares of Common Stock, and (ii) 457,000 shares are redeemed for $12,000,000 in cash, and which redemption shall (a) be pursuant to a Redemption Notice delivered by Borrower not more than ninety (90) days and not less than thirty (30) days prior to October 25, 1999, and (b) be effective October 25, 1999. Redemption Notice means a notice by Borrower to the holders of the ----------------- Original Preferred Stock, pursuant to which Borrower calls 623,000 shares of such Original Preferred Stock for redemption. 1.3. Amendment to Restricted Payments Covenant. Section 10.2 of the ----------------------------------------- Credit Agreement shall be amended to read in full as follows: SECTION 10.2. Restricted Payments. Neither Borrower nor any ------------------- Restricted Subsidiary of Borrower will declare or make any Restricted Payment; provided, that, so long as no Default, Event of Default or -------- ---- Borrowing Base Deficiency then exists, and provided that no Default or Event of Default would result therefrom, Borrower shall be permitted to (a) declare and pay accrued dividends on the Preferred Stock and the Common Stock, (b) repurchase any of its Common Stock or Preferred Stock or warrants, options or other rights to acquire such Common Stock or Preferred Stock, so long as, at any date, the sum of (y) the aggregate amount of all such dividends declared and paid pursuant to clause (a) above during the period commencing on April 1, 1999 to and including such date, plus (z) the aggregate amount paid by Borrower and its Restricted Subsidiaries in respect of the repurchase of all such Common Stock or Preferred Stock or warrants, options or other rights to acquire such Common Stock or Preferred Stock pursuant to clause (b) above, shall not exceed the Restricted Payment Limit in effect at such date, and (c) notwithstanding anything to the contrary contained herein, consummate and effectuate the Qualified Redemption, which such Qualified Redemption shall not impact or be counted against the Restricted Payment Limit. SECTION 2. Borrowing Base. In accordance with Article V of the Credit --------- -------------- Agreement, effective November 1, 1999, and continuing until the next Determination Date, the Borrowing Base shall be $175,000,000. SECTION 3. Consent. Notwithstanding anything to the contrary contained in --------- ------- the Credit Agreement or in any other Loan Paper, Banks hereby (a) consent to the consummation of the Qualified Redemption, and (b) waive any inconsistent provisions of the Credit Agreement, 2 including, without limitation, Section 10.2 thereof, with respect to the consummation of such Qualified Redemption. The consent and waiver herein contained are expressly limited as follows: (i) such consent and waiver are limited solely to the consummation of the Qualified Redemption, (ii) such consent and waiver shall not be applicable to any provision of any Loan Paper other than Section 10.2 of the Credit Agreement, and (iii) such consent and waiver are each a limited, one-time consent and waiver, and nothing contained herein shall obligate Banks to grant any additional or future consent or waiver of, or with respect to, Section 10.2 of the Credit Agreement or any other provision of any Loan Paper. SECTION 4. Representations and Warranties. In order to induce --------- ------------------------------ Administrative Agent and Banks to enter into this First Amendment, Borrower hereby represents and warrants to Administrative Agent and each Bank that: 4.1. Accuracy of Representations and Warranties. Each representation and ------------------------------------------ warranty of Borrower and its Subsidiaries contained in the Loan Papers are true and correct in all material respects as of the date hereof (except to the extent that such representations and warranties are expressly made as of a particular date, in which event such representations and warranties were true and correct as of such date); 4.2. Absence of Defaults. Neither a Default nor an Event of Default has ------------------- occurred which is continuing; and 4.3. No Defense. Borrower has no defenses to payment, counterclaims or ---------- rights of set-off with respect to the Obligations on the date hereof. SECTION 5. Miscellaneous. --------- ------------- 5.1. Reaffirmation of Loan Papers; Extension of Liens. Any and all of the ------------------------------------------------ terms and provisions of the Credit Agreement and the Loan Papers shall, except as amended and modified hereby, remain in full force and effect. Borrower hereby extends the Liens securing the Obligations until the Obligations have been paid in full, and agrees that the amendments and modifications herein contained shall in no manner affect or impair the Obligations or the Liens securing payment and performance thereof. 5.2. Parties in Interest. All of the terms and provisions of this First ------------------- Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns. 5.3. Counterparts. This First Amendment may be executed in counterparts, ------------ and all parties need not execute the same counterpart; however, no party shall be bound by this First Amendment until this First Amendment has been executed by Borrower, Administrative Agent and all Banks at which time this First Amendment shall be binding on, enforceable against and inure to the benefit of Borrower, Administrative Agent and all Banks. Facsimiles shall be effective as originals. 5.4. COMPLETE AGREEMENT. THIS FIRST AMENDMENT, THE CREDIT AGREEMENT AND ------------------ THE OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, 3 CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. 5.5. Headings. The headings, captions and arrangements used in this First -------- Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this First Amendment, nor affect the meaning thereof. 5.6. Legal Expenses. Borrower hereby agrees to pay on demand all -------------- reasonable fees and expenses of counsel to Administrative Agent incurred by Administrative Agent in connection with the preparation, negotiation and execution of this First Amendment and all related documents. IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed by their respective Authorized Officers on the date and year first above written. [Signature Pages Follow] 4 SIGNATURE PAGE TO FIRST AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT DATED AS OF NOVEMBER 1, 1999, BY AND AMONG PATINA OIL & GAS CORPORATION, AS BORROWER, THE FINANCIAL INSTITUTIONS PARTIES THERETO, AS BANKS, AND CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, AS ADMINISTRATIVE AGENT PATINA OIL & GAS CORPORATION By: /s/ David J. Kornder -------------------------------------- David J. Kornder, Vice President and Chief Financial Officer CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, as Administrative Agent By: /s/ Dale S. Hurd -------------------------------------- Dale S. Hurd, Managing Director CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, as a Bank By: /s/ Dale S. Hurd -------------------------------------- Dale S. Hurd, Managing Director BANK OF AMERICA, N.A., as a Bank By: /s/ J. Scott Fowler -------------------------------------- J. Scott Fowler, Managing Director BANK ONE, NA (MAIN OFFICE - CHICAGO) as a Bank (FORMERLY KNOWN AS THE FIRST NATIONAL BANK OF CHICAGO) By: /s/ Carl Skoog -------------------------------------- Carl Skoog, Vice President 5 SIGNATURE PAGE TO FIRST AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT DATED AS OF NOVEMBER 1, 1999, BY AND AMONG PATINA OIL & GAS CORPORATION, AS BORROWER, THE FINANCIAL INSTITUTIONS PARTIES THERETO, AS BANKS, AND CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, AS ADMINISTRATIVE AGENT BANKERS TRUST COMPANY, as a Bank By: /s/ Calli S. Hayes -------------------------------------- Calli S. Hayes, Managing Director CREDIT LYONNAIS NEW YORK BRANCH By: /s/ Phillipe Soustra -------------------------------------- Phillipe Soustra, Senior Vice President FIRST UNION NATIONAL BANK By: /s/ Robert R. Wetteroff ------------------------------------- Robert R. Wetteroff, Senior V.P. WELLS FARGO BANK, N.A. By: /s/ Greg Petruska ------------------------------------- Greg Petruska, Vice President 6 EX-10.1.3 3 RESTATED CREDIT AGREEMENT EXHIBIT 10.1.3 SECOND AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT ---------------------------------------------------------------- This Second Amendment to Second Amended and Restated Credit Agreement (this Second Amendment) is executed as of the 16th day of December, 1999, by and among - ---------------- Patina Oil & Gas Corporation, a Delaware Corporation (Borrower), Chase Bank of -------- Texas, National Association, as Administrative Agent (Administrative Agent), and -------------------- the financial institutions parties hereto as Banks (individually a Bank and ---- collectively Banks). ----- W I T N E S E T H: - - - - - - - - - WHEREAS, Borrower, Administrative Agent and Banks are parties to that certain Second Amended and Restated Credit Agreement dated as of July 15, 1999 (as amended, the Credit Agreement) (unless otherwise defined herein, all terms ---------------- used herein with their initial letter capitalized shall have the meaning given such terms in the Credit Agreement); and WHEREAS, pursuant to the Credit Agreement, Banks have made a revolving credit loan to Borrower; and WHEREAS, Borrower has (a) notified Administrative Agent and Banks that Borrower intends to redeem approximately 565,000 shares of its Original Preferred Stock, and (b) requested that the Credit Agreement be amended to revise (i) Section 10.2 thereof as set forth herein in connection therewith, and (ii) the definition of Restricted Payment Limit as set forth herein. NOW THEREFORE, for and in consideration of the mutual covenants and agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged and confessed, Borrower, Administrative Agent and each Bank hereby agree as follows: SECTION 1. Amendments. In reliance on the representations, warranties, --------- ---------- covenants and agreements contained in this Second Amendment and subject to the terms and conditions set forth herein, the Credit Agreement shall be amended effective as of the date hereof in the manner provided in this Section 1. --------- 1.1. Amendment to Definitions. The definitions of Loan Papers and ------------------------ ----------- Restricted Payment Limit contained in Section 2.1 of the Credit Agreement shall - ------------------------ be amended to read in full as follows: Loan Papers means this Agreement, the First Amendment, the Second ----------- Amendment, the Notes, each Restricted Subsidiary Guarantee now or hereafter executed, each Restricted Subsidiary Pledge Agreement now or hereafter executed, all Mortgages now or at any time hereafter delivered pursuant to Section 6.1, the Collateral Assignment, and all other certificates, ----------- documents or instruments delivered in connection with this Agreement, as the foregoing may be amended from time to time. -1- Restricted Payment Limit means as of any date (the measurement date) ------------------------ ---------------- on and after January 1, 2000, the sum of (i) $10,000,000, plus (ii) an amount equal to twenty percent (20%) of Borrower's Consolidated Free Cash Flow for the period commencing January 1, 2000 and ending on the last day of the Fiscal Quarter most recently ended as of the measurement date for which Borrower's consolidated financial statements required by Section ------- 9.1(b) (in the case of the first three quarters of each Fiscal Year, and ------ Section 9.1(a) in the case of the fourth Fiscal Quarter of each Fiscal -------------- Year) have been delivered to Banks. 1.2. Additional Definitions. Section 2.1 of the Credit Agreement shall be ---------------------- amended to add the following definitions to such Section: Second Amendment means the Second Amendment to Second Amended and ---------------- Restated Credit Agreement dated as of December 16, 1999, entered into by and among Borrower, Administrative Agent and Banks. Second Qualified Redemption means a one-time redemption by Borrower of --------------------------- approximately 565,000 shares of the Original Preferred Stock, which redemption shall be pursuant to a Second Redemption Notice delivered by Borrower not more than ninety (90) days and not less than thirty (30) days prior to the fixed date for such redemption. Second Redemption Notice means a notice by Borrower to the holders of ------------------------ the Original Preferred Stock, pursuant to which Borrower calls approximately 565,000 shares of such Original Preferred Stock for redemption. 1.3. Amendment to Restricted Payments Covenant. Section 10.2 of the ----------------------------------------- Credit Agreement shall be amended to read in full as follows: SECTION 10.2. Restricted Payments. Neither Borrower nor any ------------------- Restricted Subsidiary of Borrower will declare or make any Restricted Payment; provided, that, so long as no Default, Event of Default or -------- ---- Borrowing Base Deficiency then exists, and provided that no Default or Event of Default would result therefrom, Borrower shall be permitted to (a) declare and pay accrued dividends on the Preferred Stock and the Common Stock, (b) repurchase any of its Common Stock or Preferred Stock or warrants, options or other rights to acquire such Common Stock or Preferred Stock, so long as, at any date, the sum of (y) the aggregate amount of all such dividends declared and paid pursuant to clause (a) above during the period commencing on January 1, 2000 to and including such date, plus (z) the aggregate amount paid by Borrower and its Restricted Subsidiaries in respect of the repurchase of all such Common Stock or Preferred Stock or warrants, options or other rights to acquire such Common Stock or Preferred Stock pursuant to clause (b) above during the period commencing on January 1, 2000 to and including such date, shall not exceed the Restricted Payment Limit in effect at such date, and (c) notwithstanding anything to the contrary contained herein, consummate and effectuate the Qualified Redemption and the Second Qualified Redemption, and neither the Qualified Redemption nor the Second Qualified Redemption shall impact or be counted against the Restricted Payment Limit. -2- SECTION 2. Consent. Notwithstanding anything to the contrary contained in --------- ------- the Credit Agreement or in any other Loan Paper, Banks hereby (a) consent to the consummation of the Second Qualified Redemption, and (b) waive any inconsistent provisions of the Credit Agreement, including, without limitation, Section 10.2 thereof, with respect to the consummation of such Second Qualified Redemption. The consent and waiver herein contained are expressly limited as follows: (i) such consent and waiver are limited solely to the consummation of the Second Qualified Redemption, (ii) such consent and waiver shall not be applicable to any provision of any Loan Paper other than Section 10.2 of the Credit Agreement, and (iii) such consent and waiver are each a limited, one-time consent and waiver, and nothing contained herein shall obligate Banks to grant any additional or future consent or waiver of, or with respect to, Section 10.2 of the Credit Agreement or any other provision of any Loan Paper. SECTION 3. Representations and Warranties. In order to induce --------- ------------------------------ Administrative Agent and Banks to enter into this Second Amendment, Borrower hereby represents and warrants to Administrative Agent and each Bank that: 3.1. Accuracy of Representations and Warranties. Each representation and ------------------------------------------ warranty of Borrower and its Subsidiaries contained in the Loan Papers are true and correct in all material respects as of the date hereof (except to the extent that such representations and warranties are expressly made as of a particular date, in which event such representations and warranties were true and correct as of such date); 3.2. Absence of Defaults. Neither a Default nor an Event of Default has ------------------- occurred which is continuing; and 3.3. No Defense. Borrower has no defenses to payment, counterclaims or ---------- rights of set-off with respect to the Obligations on the date hereof. SECTION 4. Miscellaneous. --------- ------------- 4.1. Reaffirmation of Loan Papers; Extension of Liens. Any and all of the ------------------------------------------------ terms and provisions of the Credit Agreement and the Loan Papers shall, except as amended and modified hereby, remain in full force and effect. Borrower hereby extends the Liens securing the Obligations until the Obligations have been paid in full, and agrees that the amendments and modifications herein contained shall in no manner affect or impair the Obligations or the Liens securing payment and performance thereof. 4.2. Parties in Interest. All of the terms and provisions of this Second ------------------- Amendment shall bind and inure to the benefit of the parties hereto and their respective successors and assigns. 4.3. Counterparts. This Second Amendment may be executed in counterparts, ------------ and all parties need not execute the same counterpart; however, no party shall be bound by this Second Amendment until this Second Amendment has been executed by Borrower, Administrative Agent and Required Banks at which time this Second Amendment shall be binding on, enforceable against and inure to the benefit of Borrower, Administrative Agent and all Banks. Facsimiles shall be effective as originals. -3- 4.4. COMPLETE AGREEMENT. THIS SECOND AMENDMENT, THE CREDIT AGREEMENT AND ------------------ THE OTHER LOAN PAPERS REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. 4.5. Headings. The headings, captions and arrangements used in this -------- Second Amendment are, unless specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the terms of this Second Amendment, nor affect the meaning thereof. 4.6. Legal Expenses. Borrower hereby agrees to pay on demand all -------------- reasonable fees and expenses of counsel to Administrative Agent incurred by Administrative Agent in connection with the preparation, negotiation and execution of this Second Amendment and all related documents. IN WITNESS WHEREOF, the parties hereto have caused this Second Amendment to be duly executed by their respective Authorized Officers on the date and year first above written. [Signature Pages Follow] -4- SIGNATURE PAGE TO SECOND AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT DATED AS OF DECEMBER 16, 1999, BY AND AMONG PATINA OIL & GAS CORPORATION, AS BORROWER, THE FINANCIAL INSTITUTIONS PARTIES THERETO, AS BANKS, AND CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, AS ADMINISTRATIVE AGENT PATINA OIL & GAS CORPORATION By: /s/ David J. Kornder ------------------------------------- David J. Kornder, Vice President and Chief Financial Officer CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, as Administrative Agent By: /s/ Robert C. Mertensotto ------------------------------------- Robert C. Mertensotto, Managing Director CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, as a Bank By: /s/ Robert C. Mertensotto ------------------------------------- Robert C. Mertensotto, Managing Director BANK OF AMERICA, N.A., as a Bank By: /s/ J. Scott Fowler ------------------------------------- J. Scott Fowler, Managing Director BANK ONE, NA (MAIN OFFICE - CHICAGO) as a Bank (FORMERLY KNOWN AS THE FIRST NATIONAL BANK OF CHICAGO) By: /s/ Tim Merrell ------------------------------------- Tim Merrell, Vice President -5- SIGNATURE PAGE TO SECOND AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT DATED AS OF DECEMBER 16, 1999, BY AND AMONG PATINA OIL & GAS CORPORATION, AS BORROWER, THE FINANCIAL INSTITUTIONS PARTIES THERETO, AS BANKS, AND CHASE BANK OF TEXAS, NATIONAL ASSOCIATION, AS ADMINISTRATIVE AGENT BANKERS TRUST COMPANY, as a Bank By: /s/ Marcus M. Tarkington --------------------------------------- Marcus M. Tarkington, Principal CREDIT LYONNAIS NEW YORK BRANCH By: /s/ Phillipe Soustra --------------------------------------- Phillipe Soustra, Senior Vice President FIRST UNION NATIONAL BANK By: /s/ Robert R. Wetteroff --------------------------------------- Robert R. Wetteroff, Senior V.P. WELLS FARGO BANK, N.A. By: /s/ Greg Petruska --------------------------------------- Greg Petruska, Vice President -6- EX-11 4 COMPUTATION OF NET INCOME PER SHARE EXHIBIT 11 COMPUTATION OF NET INCOME PER SHARE FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999 (dollars in thousands, except ratio's)
1997 1998 1999 -------- -------- -------- Basic net income (loss) per share: Net income (loss) $(16,903) $ (4,524) $ 14,959 Dividends on preferred stock (3,346) (6,335) (6,739) -------- -------- -------- Net income (loss) available common $(20,249) $(10,859) $ 8,220 Weighted average shares outstanding 18,324 16,025 15,972 Net income (loss) per share $ (1.11) $ (0.68) $ 0.52 ======== ======== ======== Diluted net income (loss) per share: Net income (loss) $(16,903) $ (4,524) $ 14,959 Dividends on preferred stock (3,346) (6,335) (6,739) -------- -------- -------- Net income (loss) available common $(20,249) $(10,859) $ 8,220 Weighted average shares outstanding 18,324 16,025 16,471 Net income (loss) per share $ (1.11) $ (0.68) $ 0.50 ======== ======== ========
Note: The common stock options, common stock grants, $12.50 common stock warrants, 7.125% convertible preferred stock and 8.50% convertible preferred stock were anti-dilutive for 1997 and 1998, and the $12.50 common stock warrants, 7.125% convertible preferred stock and 8.50% convertible preferred stock were anti-dilutive for 1999. EX-12 5 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES EXHIBIT 12 COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS (UNAUDITED) (dollars in thousands, except ratio's)
1995 1996 1997 1998 1999 -------- -------- -------- -------- -------- Net income (loss) before taxes $ (3,222) $ 3,168 $ (16,903) $ (4,524) $ 14,959 Interest expense 5,409 14,275 15,939 12,867 10,622 -------- -------- --------- -------- -------- Earning before fixed charges $ 2,187 $ 17,443 $ (964) 8,343 25,581 ======== ======== ========= ======== ======== Preferred dividends $ - $ 2,129 $ 3,346 6,335 6,739 Ratio of pretax income to net income 1.54 0.89 1.00 1.00 1.00 -------- -------- --------- -------- -------- Preferred dividend factor $ - $ 1,895 $ 3,346 $ 6,335 $ 6,739 ======== ======== ========= ======== ======== Fixed charges: Interest expense $ 5,409 $ 14,275 $ 15,939 $ 12,867 $ 10,622 Preferred dividend factor - 1,895 3,346 6,335 6,739 -------- -------- --------- -------- -------- Total fixed charges and preferred dividends $ 5,409 $ 16,170 $ 19,285 $ 19,202 $ 17,361 ======== ======== ========= ======== ======== Ratio of earnings to combined fixed charges and preferred dividends 0.40 1.08 (0.05) 0.43 1.47 ======== ======== ========= ======== ========
EX-23 6 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS ----------------------------------------- As independent public accountants, we hereby consent to the incorporation by reference of our report included in this Form 10-K, into Patina Oil & Gas Corporation's previously filed Registration Statements on Form S-3, File Nos. 333-77785, 333-89399 and on Form S-4, File No. 333-78291. Denver, Colorado February 23, 2000 EX-27 7 FINANCIAL DATA SCHEDULE
5 12-MOS DEC-31-1999 JAN-01-1999 DEC-31-1999 626 0 16,128 (434) 2,680 19,350 625,557 (315,983) 330,216 19,108 132,000 0 24 161 165,705 330,216 90,407 91,571 52,646 65,102 887 0 10,623 14,959 0 14,959 0 0 0 14,959 0.52 0.50
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