10-K 1 d10k.txt FORM 10-K ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ---------------- FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Fee Required) For Fiscal Year Ended December 31, 2001 Commission file number 1-7940 GOODRICH PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) Delaware 76-0466193 (State of incorporation) (I.R.S. Employer Identification No.) 815 Walker St., Suite 1040 77002 Houston, Texas (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code is (713) 780-9494 Title of each Name of each exchange class on which registered ----- --------------------- Securities registered pursuant to Section 12(b) of the Act: Common Stock, $0.20 par value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Series A Preferred Stock, $1.00 par value NASDAQ Small Cap Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] 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. [_] At March 15, 2002, there were 17,896,356 shares of Goodrich Petroleum Corporation common stock outstanding. The aggregate market value of shares of common stock held by non-affiliates of the registrant as of March 15, 2002, was approximately $35,235,000 based on a closing price of $4.06 per share on the New York Stock Exchange on such date. ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- PART I Items 1 and 2. Business and Properties. General Goodrich Petroleum Corporation and subsidiaries ("Goodrich" or "the Company") is an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties in the transition zone of south Louisiana and in north Louisiana, the Gulf Coast of Texas and east Texas. The Company owns working and overriding royalty interests in 132 active oil and gas wells located in 27 fields in five states. At December 31, 2001, Goodrich had estimated proved reserves of approximately 8,750,000 barrels of oil and condensate and 34.0 Bcf of natural gas, or an aggregate of 86.5 Bcfe with a pre-tax present value of future net revenues, discounted at 10%, of $78.9 million and an after-tax Standardized Measure value of $73.1 million. The Company's principal executive offices are located at 815 Walker, Suite 1040 Houston, Texas 77002. The Company also has offices in Shreveport, Louisiana. At March 15, 2002, the Company had 17 employees. Company Background Goodrich resulted from a business combination on August 15, 1995 between La/Cal Energy Partners ("La/Cal") and Patrick Petroleum Company and subsidiaries ("Patrick"). La/Cal was a privately held independent oil and gas partnership formed in July 1993 and engaged in the development, production and acquisition of oil and natural gas properties, primarily in southern Louisiana. Patrick was a NYSE listed independent oil and gas company engaged in the exploration, production, development and acquisition of oil and natural gas properties in the continental United States. Patrick's oil and gas operations and properties were primarily located in West Texas and Michigan at the time of the combination, with additional operations and properties in certain western states. Oil and Gas Operations and Properties The following is a summary description of the Company's oil and gas properties. Louisiana The majority of the Company's proved natural gas reserves are in the transition zone of the south Louisiana producing region. This region refers to the geographic area that covers the onshore and in-land waters of south Louisiana lying in the southern half of Louisiana, which is one of the most prolific oil and natural gas producing sedimentary basins. The region generally contains sedimentary sandstones, which are of high qualities of porosity and permeabilities. There is a myriad of types of reservoir traps found in the region. These traps are generally formed by faulting, folding and subsurface salt movement, or a combination of one or more of these. The formations found in the southern Louisiana producing region range in depth from 1,000 feet to 20,000 feet below the surface. These formations range from the Sparta and Frio formations in the northern part of the region to Miocene and Pleistocene in the southern part of the region. The Company's production comes predominately from Miocene and Frio age formations. Burrwood and West Delta Block 83 Fields. The Burrwood and West Delta Block 83 fields, located in Plaquemines Parish, Louisiana, were discovered in 1955 by Chevron. The fields lie upthrown to a large down-to-the southeast growth fault system with the structure striking northeast-southwest and dipping northwestward in a counter-regional direction. The fields have collectively produced 49.1 million barrels of oil and 143 Bcf of natural gas. The productive sands are Miocene and Pliocene age sands ranging in depth from 6,300 feet to approximately 11,700 feet. There are currently 23 active producing wells in the fields. 2 Goodrich acquired a 95% working interest in approximately 8,600 acres through an acquisition that closed on March 2, 2000 with an effective date of January 1, 2000. On March 12, 2002, the Company, in an effort to monetize a portion of the value created in its Burrwood and West Delta fields and enhance its liquidity position, completed the sale of a thirty percent (30%) working interest in the existing production and shallow rights, and a fifteen percent (15%) working interest in the deep rights below 10,600 feet, in the Fields for $12 million to Malloy Energy Company, LLC led by Patrick E. Malloy, III and participated in by Sheldon Appel, both members of the Company's Board of Directors. The sale price was determined by discounting the present value of the acquired interest in the field's proved, probable and possible reserves using prevailing oil and gas prices. The Company retains a sixty-five percent (65%) working interest in the existing production and shallow rights, and a thirty-two and one-half percent (32.5%) working interest in the deep rights after the close of the transaction. In conjunction with the sale, the investor group will provide a $7.7 million line of credit. The $7.7 million line of credit, which will reduce to $5.0 million on January 1, 2003, is subordinate to the Company's senior facility and can be used for acquisitions, drilling, development and general corporate purposes until December 31, 2004. The investor group retains the option, during the two-year period, to convert the amount outstanding under the credit line, and/or provide cash on any unused credit to a maximum of $7.7 million in the first year, reduced to $5.0 million after December 31, 2002, into working interests in any acquisition(s) the Company may make in Louisiana prior to January 1, 2005. The conversion of the credit facility will be on a pro-rata basis with the Company and may not exceed a maximum of $7.7 million, reduced to $5.0 million after December 31, 2002, or thirty percent (30%) of any potential acquisition(s). The Company will record a gain of approximately $2.1 million in the first quarter of 2002 as a result of the sale. The proceeds were used to reduce outstanding debt under its credit facility to approximately $12 million. Lafitte Field. The Lafitte Field is located in Jefferson Parish, Louisiana and was discovered in 1935 by Texaco. The Lafitte Field is a large, north- south elongated salt dome anticline feature. There are currently more than thirty (30) defined productive sands, which have collectively produced in excess of 264 million barrels of oil and 319 Bcf of natural gas. The productive sands are Miocene and Pliocene age sands ranging in depth from 3,000 feet to approximately 12,000 feet. There are currently 35 active producing wells in the field. In September 1999, the Company acquired an approximate 49% interest in the Lafitte Field with respect to the field's leases, surface facilities and equipment and an approximate 45% average interest in the 31 active producing wells. In November 1999, the Company acquired additional interests, resulting in an approximate field-wide interest of 49%. Second Bayou Field. The Second Bayou Field is located in Cameron Parish, Louisiana and was discovered in 1955 by the Sun Texas Company. Goodrich is the operator of nine producing wells, six of which are dually completed, and has an average working interest of approximately 29% in 1,395 gross acres. To date, the field has produced over 425 Bcf of natural gas and 3.6 million barrels of oil from multiple Miocene aged sands ranging from 4,000 to 15,200 feet. Pecan Lake Field. The Pecan Lake Field was discovered in 1944 by the Superior Oil Company. Geologically, the field is comprised of a relatively low relief, four-way closure and multiple stacked pay sands. The Pecan Lake Field comprises approximately 870 gross leased acres in Cameron Parish, Louisiana, approximately 42 miles southeast of Lake Charles, Louisiana. The field has produced from over 15 Miocene sands ranging in depths from 7,500 to 11,800 feet, which have been predominately gas and gas condensate reservoirs. These sand reservoirs are characterized by generally widespread development and strong waterdrive production mechanisms. The field has produced in excess of 354 Bcf of gas and 798,000 barrels of condensate. All of the field production to date has come from normal pressured reservoirs. The Company is the operator of seven producing wells with working interests ranging from approximately 43% to 47%. Isle St. Jean Charles Field. Isle St. Jean Charles Field is located in Terrebonne Parish, Louisiana. The field is a northwest extension of the Bayou Jean LaCroix Field located in the southeastern area of the Parish. These fields are trapped on a four-way closure, downthrown on a major east-west trending down to the south fault. 3 Production is from multiple Miocene-aged sands, which are normally pressured and range in depth from 9,000 feet to 13,000 feet. The field was developed primarily in the 1950's by Exxon and reservoirs have exhibited both depletion and water drive mechanisms. To date, this field has produced in excess of 57 billion cubic feet of gas and 6.61 million barrels of oil and condensate. Goodrich acquired its interest in its leasehold of approximately 425 acres through both acreage acquisitions and a farmout from Fina, et al. Goodrich is operator of the field and holds an approximate 34% working interest. Lake Raccourci Field. The Lake Raccourci Field was discovered by a predecessor to Exxon in 1949, with the field extended to the south by a predecessor to Amoco in 1958. Geologically, the field is a large four-way dipping closure, which is cross-cut by numerous northeast-southwest striking down to the south faults. The field has produced from a minimum of 18 different Miocene age sandstones, ranging in depth from 9,000 to 16,500 feet. These normally and abnormally pressured reservoirs exhibit depletion, water and combination drive mechanisms, and have produced in excess of 834 billion cubic feet of gas and 20 million barrels of oil and condensate. Goodrich acquired its average 27% working interest in the field through a farmout from a predecessor to Apache in July 1996 and a separate farmout from Exxon. The Company controls approximately 1,079 acres in the field. In December 2001, the Company purchased Exxon's interest in one of the wells in the field. Other. The Company maintains ownership interests in acreage and wells in several additional fields in Louisiana, including the (i) Opelousas Field, located in St. Landry Parish, (ii) Sibley Field, located in Webster Parish, (iii) City of Lake Charles Field, located in Calcasieu Parish, (iv) South Drew Field, located in Ouachita Parish, (v) Mosquito Bay Field, located in Terrebonne Parish and (vi) Kings Ridge Field, located in Lafourche Parish, and (vii) Ada Field, located in Bienville Parish Texas Goodrich explores and has production in the western, eastern and southern regions of Texas. Sean Andrew Field. The Sean Andrew Field was discovered by the Company in 1994 utilizing the Company's 375 square mile 3-D seismic database in West Texas. The Company is the operator of four wells in the field and holds an approximate 37.5% working interest. Marholl Field. The Marholl Field is a Siluro-Devonian (Fussellman) field in Dawson County discovered in 1995 through the use of 3-D seismic. The Company operates two wells in the field with an approximate 23% working interest. Mary Blevins Field. The Mary Blevins Field is located in Smith County, Texas. It was a new discovery that is fault separated from Hitts Lake Field, which was discovered in 1953 by Sun Oil. Currently there are four producing wells in the field in which Goodrich serves as operator, having an approximate 48% working interest in 782 gross acres. To date, Hitts Lake has produced over 14 million barrels of oil and Mary Blevins has produced over 551,000 barrels of oil from the Paluxy, which occurs at a depth of approximately 7,300 feet. Other. The Company maintains ownership interests in acreage and wells in several additional fields in Texas including the (i) Ackerly Field, located in Dawson and Howard Counties, (ii) Lamesa Farms Field, located in Dawson County, (iii) Midway Field, located in San Patricio County, (iv) East Jacksonville Field, located in Cherokee County, and (v) Mott Slough Field, located in Wharton County. Australia Goodrich has interest in two exploration permits in the Carnarvon Basin of Western Australia. 4 The Carnarvon Basin is two-thirds the size of the Gulf of Mexico and has produced in excess of 4.3 TCF and 550 million barrels of oil from less than 1000 wells. The Carnarvon Basin retains significant exploration potential. Additional strengths of the basin include large inexpensive acreage blocks, vast available geological and geophysical data sets, existing and expanding petroleum infrastructure and increasing domestic demands for natural gas. EP-395. Goodrich Petroleum has a 6.9% non-operated working interest in the 240 square kilometer Exploration Permit in 1995. Since 1995, the partners have reprocessed the original 2-D seismic data sets, shot a 38 km 3-D seismic survey (1995), and shot an additional 93 km of high quality 2-D seismic. EP-397. This Permit covers 160 square kilometers in which the Company has a 33% working interest. The 130 km of available seismic has been reprocessed and interpreted with several prospect leads. Oil and Natural Gas Reserves The following tables set forth summary information with respect to the Company's proved reserves as of December 31, 2001 and 2000, as estimated by the Company by compiling reserve information, substantially all of which was prepared by the engineering firm of Coutret and Associates, Inc.
After-Tax Net Reserves Pre-Tax Present Standardized Measure ---------------------------- Value of Future of Discounted Future Oil Net Revenues Net Revenues Category (Bbls) Gas (Mcf) Bcfe(1) (in millions) (in millions) -------- --------- ---------- ------- --------------- -------------------- December 31, 2001 Proved Developed...... 3,399,610 16,692,390 37.1 $ 42.39 Proved Undeveloped.... 5,350,810 17,263,860 49.4 36.50 --------- ---------- ---- ------- Total Proved........ 8,750,420 33,956,250 86.5 $ 78.89 $ 73.12 ========= ========== ==== ======= ======= December 31, 2000 Proved Developed...... 3,196,330 22,251,970 41.4 $162.41 Proved Undeveloped.... 3,593,028 7,258,709 28.8 87.70 --------- ---------- ---- ------- Total Proved........ 6,789,358 29,510,679 70.2 $250.11 $179.78 ========= ========== ==== ======= =======
-------- (1) Estimated by the Company using a conversion ratio of 1.0 Bbl/6.0 Mcf. Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, the pre-tax Present Value of Future Net Revenues amounts shown above should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company's properties. In accordance with the Commission's guidelines, the engineers' estimates of future net revenues from the Company's properties and the pre-tax Present Value of Future Net Revenues thereof are made using oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The prices as of December 31, 2001, and 2000 used in such estimates averaged $2.51 and $10.06 per Mcf, respectively, of natural gas and $17.91 and $26.10 per Bbl, respectively, of crude oil/condensate. 5 Productive Wells The following table sets forth the number of active well bores in which the Company maintains ownership interests as of December 31, 2001:
Oil Gas Total --------------- --------------- --------------- Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) -------- ------ -------- ------ -------- ------ California...................... -- -- 4.00 2.09 4.00 2.09 Louisiana....................... 54.00 34.44 40.00 18.90 94.00 53.34 Michigan........................ 2.00 .26 5.00 .05 7.00 .31 New Mexico...................... -- -- 1.00 .03 1.00 .03 Texas........................... 22.00 10.83 4.00 .64 26.00 11.47 ----- ----- ----- ----- ------ ----- Total Productive Wells........ 78.00 45.53 54.00 21.71 132.00 67.24 ===== ===== ===== ===== ====== =====
-------- (1) Does not include royalty or overriding royalty interests. (2) Net working interest. Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. A gross well is a well in which the Company maintains an ownership interest, while a net well is deemed to exist when the sum of the fractional working interests owned by the Company equals one. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, twelve had multiple completions. Acreage The following table summarizes the Company's gross and net developed and undeveloped natural gas and oil acreage under lease as of December 31, 2001. Acreage in which the Company's interest is limited to a royalty or overriding royalty interest is excluded from the table.
Gross Net ------- ------ Developed acreage California............................................... 1,280 568 Louisiana................................................ 24,087 14,855 Michigan................................................. 1,920 19 Texas.................................................... 4,365 1,491 Undeveloped acreage Offshore Australia....................................... 98,841 17,306 Louisiana................................................ 2,123 1,344 Michigan................................................. 640 50 Texas.................................................... 1,000 552 ------- ------ Total.................................................. 134,256 36,185 ======= ======
Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to the extent that would permit the production of commercial quantities of natural gas or oil, regardless of whether or not such acreage contains proved reserves. As is customary in the oil and gas industry, the Company can retain its interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the remaining primary term of such a lease. The natural gas and oil leases in which the Company has an interest are for varying primary terms; however, most of the Company's developed lease acreage is beyond the primary term and is held so long as natural gas or oil is produced. 6 Operator Activities Goodrich Petroleum operates a majority in value of the Company's producing properties, and will generally seek to become the operator of record on properties it drills or acquires in the future. Drilling Activities The following table sets forth the drilling activities of the Company for the last three years. (As denoted in the following table, "Gross" wells refers to wells in which a working interest is owned, while a "net" well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.)
Year Ended December 31, ---------------------------- 2001 2000 1999 --------- --------- -------- Development Wells: Productive................................. 4.00 3.39 3.00 1.77 1.00 .49 Non-Productive............................. -- -- 1.00 .49 -- -- ---- ---- ---- ---- ---- --- Total.................................... 4.00 3.39 4.00 2.26 1.00 .49 ==== ==== ==== ==== ==== === Exploratory Wells: Productive................................. 1.00 .17 2.00 .93 -- -- Non-Productive............................... 2.00 1.40 2.00 1.00 1.00 .12 ---- ---- ---- ---- ---- --- Total.................................... 3.00 1.57 4.00 1.93 1.00 .12 ==== ==== ==== ==== ==== === Total Wells: Productive................................. 5.00 3.56 5.00 2.70 1.00 .49 Non-Productive............................. 2.00 1.40 3.00 1.49 1.00 .12 ---- ---- ---- ---- ---- --- Total.................................... 7.00 4.96 8.00 4.19 2.00 .61 ==== ==== ==== ==== ==== ===
Net Production, Unit Prices and Costs The following table presents certain information with respect to oil, gas and condensate production attributable to the Company's interests in all of its fields, the revenue derived from the sale of such production, average sales prices received and average production costs during each of the years in the three-year period ended December 31, 2001.
2001 2000 1999 --------- --------- --------- Net Production: Natural gas (Mcf)........................ 3,823,227 3,394,921 2,930,655 Oil (barrels)............................ 581,680 571,766 394,442 Natural gas equivalents (Mcfe)(1)........ 7,313,307 6,825,517 5,297,307 Average Net Daily Production: Natural gas (Mcf)........................ 10,475 9,301 8,029 Oil (Bbls)............................... 1,594 1,566 1,081 Natural gas equivalents (Mcfe)(1)........ 20,039 18,697 14,515 Average Sales Price Per Unit(2): Natural gas (per Mcf).................... $ 3.97 3.95 2.41 Oil (per Bbl)............................ $ 24.67 25.55 16.88 Other Data: Lease operating expense (per Mcfe)....... $ 0.90 0.69 0.45 Production taxes (per Mcfe).............. $ 0.26 0.32 0.23 DD & A (per Mcfe)........................ $ 0.94 0.87 0.90 Exploration (per Mcfe)................... $ 0.57 0.41 0.31
-------- (1) Estimated by the Company using a conversion ratio of 1.0 Bbl/6.0 Mcf. (2) See results of operations under Item 7 for discussion of the effects of hedging on results. 7 The Company's acquisition strategy calls for the acquisition of mature oil and gas fields with declining production profiles, established production histories and multiple production sands that have been overlooked and/or starved of capital. Acquisitions of this type generally require significant lease operation, exploration and capital expenditure cash outlays during initial years of ownership. The Company's Lafitte, Burrwood and West Delta Fields acquisitions in late 1999 and early 2000, were strategic acquisitions that fit the aforementioned profile, and account for the increased unit costs noted above in the 2001 and 2000 periods presented above. Oil and Gas Marketing and Major Customers Marketing. Goodrich's natural gas production is sold under spot or market- sensitive contracts and to various gas purchasers on short-term contracts. Goodrich's natural gas condensate is sold under short-term rollover agreements based on current market prices. The Company's crude oil production is marketed to several purchasers based on short-term contracts. The Company entered into an agreement with Natural Gas Ventures, L.L.C. ("NGV"), a Louisiana limited liability company, for the purpose of marketing the Company's and its contracting parties' natural gas. The Company and other contracting parties contribute natural gas to NGV, who then markets to gas purchasers, pursuant to the joint venture agreement between NGV and Seaber Corporation of Louisiana ("Seaber"). The Company can terminate this agreement on 60-days notice. The Company believes its contract with NGV allows it to realize higher prices for its contributed gas because of the greater market power associated with larger volumes of gas than the Company would have for sale on a stand-alone basis. Customers. Due to the nature of the industry, the Company sells its oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. Revenues from these sources as a percent of total revenues for the periods presented were as follows:
Year Ended December 31, ---------------- 2001 2000 1999 ---- ---- ---- Seaber Corporation of Louisiana............................ 56% 48% 37% Genesis Crude Oil, L.P..................................... 22% 27% Navajo Refining Company.................................... 4% 4% Gulfmark Energy, Inc....................................... -- 10% 10% Equiva Trading............................................. -- 8% 27% Texla Energy Management.................................... -- -- 10%
Competition The oil and gas industry is highly competitive. Major and independent oil and gas companies, drilling and production acquisition programs and individual producers and operators are active bidders for desirable oil and gas properties, as well as the equipment and labor required to operate those properties. Many competitors have financial resources substantially greater than those of the Company, and staffs and facilities substantially larger than those of the Company. The availability of a ready market for the oil and gas production of the Company will depend in part on the cost and availability of alternative fuels, the level of consumer demand, the extent of domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, regulations by state and federal authorities and the cost of complying with applicable environmental regulations. Regulations The availability of a ready market for any natural gas and oil production depends upon numerous factors beyond the Company's control. These factors include regulation of natural gas and oil production, federal and 8 state regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of natural gas and oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut- in" because of an oversupply of natural gas or the lack of an available natural gas pipeline in the areas in which the Company may conduct operations. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies as well. Environmental Regulation Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company's operations and costs as a result of their effect on oil and gas development, exploration and production operations. It is not anticipated that the Company will be required in the near future to expend amounts that are material in relation to its total capital expenditures program by reason of environmental laws and regulations but, inasmuch as such laws and regulations are frequently changed by both federal and state agencies, the Company is unable to predict the ultimate cost of continued compliance. Additionally, see existing EPA matters discussed in Item 3--Legal Proceedings. State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. In addition, there are state statutes, rules and regulations governing conservation matters, including the unitization or pooling of oil and gas properties, establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced from the Company's properties and may restrict the number of wells that may be drilled on a particular lease or in a particular field. Item 3. Legal Proceedings. The U.S. Environmental Protection Agency ("EPA") has identified the Company as a potentially responsible party ("PRP") for the cost of clean-up of "hazardous substances" at an oil field waste disposal site in Vermilion Parish, Louisiana. The Company estimates that the remaining cost of long-term clean-up of the site will be approximately $3.5 million, with the Company's percentage of responsibility estimated to be approximately 3.05%. As of December 31, 2001, the Company had paid $321,000 in costs related to this matter and accrued $122,500 for the remaining liability. These costs have not been discounted to their present value. The EPA and the PRPs will continue to evaluate the site and revise estimates for the long-term clean-up of the site. There can be no assurance that the cost of clean-up and the Company's percentage responsibility will not be higher than currently estimated. In addition, under the federal environmental laws, the liability costs for the clean-up of the site is joint and several among all PRPs. Therefore, the ultimate cost of the clean-up to the Company could be significantly higher than the amount presently estimated or accrued for this liability. On February 8, 2000, the Company commenced a suit against the operator and joint owner of the Lafitte Field, alleging certain items of misconduct and violations of the letter agreement associated with the joint acquisition. The suit is ongoing and it is too early to predict a likely outcome, however, as the Company is the plaintiff in this action, this action is not expected to have a significantly adverse impact on the operations or financial position of the Company. The Company is party to additional lawsuits arising in the normal course of business. The Company intends to defend these actions vigorously and believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to its financial position or results of operations. Item 4. Submission of Matters to a Vote of Security Holders. None. 9 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters. The Company's common stock is traded on the New York Stock Exchange. At March 15, 2002 the number of holders of record of the Company's common stock without determination of the number of individual participants in security position was 2,187 with 17,896,356 shares outstanding. High and low sales prices for the Company's common stock for each quarter during the calendar years 2001 and 2000 are as follows:
2001 2000 ---------- --------- Quarter Ended High Low High Low ------------- ----- ---- ---- ---- March 31............................................. $6.50 4.88 6.25 2.63 June 30.............................................. $6.75 5.80 5.56 4.25 September 30......................................... $5.83 4.80 6.25 4.50 December 31.......................................... $5.35 3.71 6.50 5.00
The Company has not paid a cash dividend on its common stock and does not intend to pay such a dividend in the foreseeable future. 10 Item 6. Selected Financial Data. Selected Statement of Operations Data: The following table sets forth selected financial data of the Company for each of the years in the five-year period ended December 31, 2001, which information has been derived from the Company's audited financial statements. This information should be read in connection with and is qualified in its entirety by the more detailed information in the Company's financial statements under Item 8 below and Item 7, "Management's Discussion And Analysis Of Financial Condition And Results Of Operations."
Year Ended December 31, ----------------------------------------------------------- 2001 2000 1999 1998 1997 ----------- ---------- ---------- ---------- ---------- Revenues................ $29,894,779 28,489,391 14,020,574 10,591,873 12,901,361 Depletion, Depreciation and Amortization....... 6,844,751 5,953,641 4,743,608 4,094,447 4,862,754 Exploration............. 4,174,436 2,813,332 1,656,158 6,010,425 3,205,730 Interest Expense........ 1,290,681 4,390,331 2,810,576 1,909,849 1,416,675 Total Costs and Expenses............... 25,687,242 24,712,518 15,330,062 18,311,421 14,978,629 Gain (Loss) on sale of assets................. 26,779 307,299 (519,495) 4,206 688,304 Income taxes............ 1,487,070 (1,655,032) -- -- -- Net Income(Loss)........ 2,747,246 5,739,204 (1,828,983) (7,715,342) (1,388,964) Preferred Stock Dividends.............. 3,002,872 1,193,768 1,249,343 1,255,638 1,205,210 Income(Loss) Applicable to Common Stock........ (255,626) 4,545,436 (3,078,326) (8,970,980) (2,594,174) Basic Income(Loss) Per Average Common Share... $ (.01) .46 (.58) (1.71) (.50) Diluted Income(Loss) Per Average Common Share... $ (.01) .35 (.58) (1.71) (.50) Average Common Shares Outstanding Basic...... 17,351,375 9,903,248 5,288,011 5,243,105 5,229,307 Average Common Shares Outstanding Diluted.... 17,351,375 13,116,641 5,288,011 5,243,105 5,229,307 Year Ended December 31, ----------------------------------------------------------- 2001 2000 1999 1998 1997 ----------- ---------- ---------- ---------- ---------- Selected Balance Sheet Data: Total Assets.......... $82,243,931 65,343,594 56,258,552 44,036,588 37,537,918 Total Long Term Debt.. 24,500,000 22,965,000 36,953,117 29,500,000 18,500,000 Stockholders' Equity.. $47,920,547 32,605,216 6,411,044 4,959,388 14,332,676
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations General The Company was created by the combination of Patrick Petroleum Company ("Patrick") and La/Cal Energy Partners, a partnership in which it had a controlling interest ("La/Cal"), in August 1995. The combination was a reverse merger in which the Company's current management gained control of the combined company, renamed it Goodrich Petroleum Corporation and assumed Patrick's New York Stock Exchange listing. Results of Operations Year ended December 31, 2001 versus year ended December 31, 2000--Total revenues in 2001 amounted to $29,895,000 and were $1,406,000 (5%) higher than total revenues in 2000 due primarily to higher oil and gas sales. Oil and gas sales were $29,542,000 for the twelve months ended 2001, compared to $28,014,000, or $1,528,000 higher due to higher oil and gas production volumes partially offset by lower oil prices. Oil sales were reduced by $89,000 and gas sales were reduced by $972,000 for the year ended December 31, 2001 11 compared to reductions of $2,461,000 for oil sales and $441,000 for gas sales in the year ended December 31, 2000 as a result of settlement of the Company's outstanding futures contracts. The Company recorded a gain on the sale of certain non-core oil and gas properties of $27,000 for the twelve months ended December 31, 2001 compared to a gain of $307,000 for the twelve months ended December 31, 2000. The following table reflects the production volumes and pricing information for the periods presented:
2001 2000 ------------------------ ------------------------ Production Average Price Production Average Price ---------- ------------- ---------- ------------- Gas (Mcf)............... 3,823,227 $ 3.97 3,394,921 $ 3.95 Oil (Bbls).............. 581,680 $24.67 571,766 $25.55
Lease operating expense was $6,576,000 for 2001 compared to $4,695,000 for 2000, or $1,881,000 higher, due primarily to a full twelve months of costs at Burrwood and West Delta 83 fields in the 2001 period compared to ten months in the prior period and an increased number of net properties. Production taxes in 2001 were $1,866,000 compared to $2,219,000 or $353,000 lower due to severance tax exemptions received on certain production in the Burrwood and West Delta 83 fields. Depletion, depreciation and amortization was $6,845,000 in 2001 versus $5,954,000 in 2000, or $891,000 higher, due to increased oil and gas production. The Company incurred $4,174,000 of exploration expense in 2001 compared to $2,813,000 in 2000, or $1,361,000 higher, due primarily to dry hole and seismic costs of $1,604,000 and $994,000 respectively in 2001, compared to $796,000 and $475,000 respectively in 2000. The Company recorded an impairment in the recorded value of certain oil and gas properties in 2001 in the amount of $1,801,000 due primarily to a sooner than anticipated depletion of reserves in two non-core fields. This compares to an impairment of $1,835,000 recorded in 2000. Interest expense was $1,291,000 in the twelve months ended December 31, 2001 compared to $4,390,000 in the twelve months ended December 31, 2000, or $3,099,000 lower, due primarily to lower average debt outstanding and a lower average effective interest rate for the twelve months ended December 31, 2001. The 2001 amount includes $242,000 of non cash expenses associated with the amortization of deferred debt financing costs and amortization of the discount associated with the production payment liability recorded in connection with the Lafitte Field acquisition. The 2000 amount includes $919,000 of non cash expenses associated with the amortization of financing costs and debt discount in connection with the September 1999 private placement and amortization of the discount associated with the production payment liability recorded in connection with the Lafitte Field acquisition. General and administrative expenses amounted to $3,135,000 for 2001 versus $2,518,000 in 2000, 617,000 higher, due mostly to an increase in legal expenses in the 2001 period. The Company recorded deferred tax expense (does not require current cash payment) of $1,487,000 in 2001 compared to the recording of a deferred tax benefit of $1,655,000 in 2000 based primarily on the evaluation of utilization of net operating loss carryforwards. During 2001, the Company paid dividends of $626,000 on its Series A preferred stock. The Company exchanged each share of its Series B preferred stock for 1.8 shares of its common stock and recorded a conversion premium on the income statement as dividends, of $2,377,000 to reflect the excess of the 1.8 conversion factor over the terms of the original preferred stock issuance. For the period ended December 31, 2000, the Company paid an aggregate of approximately $1.8 million of dividend arrearages and $580,000 of regular quarterly (third and fourth quarter 2000) dividends on its outstanding Series of preferred stock. At December 31, 2001 and 2000, the Company was current as to dividends its preferred stock. The Company also accrued non-cash dividends on its Goodrich--Louisiana Series A Preferred units, prior to conversion, of $38,000 that is reflected as preferred dividends of subsidiary in the statement of operations for the 2000 period. Year ended December 31, 2000 versus year ended December 31, 1999--Total revenues in 2000 amounted to $28,489,000 and were $14,468,000 (103%) higher than total revenues in 1999 due primarily to higher oil and 12 gas sales. Oil and gas sales were $28,014,000 for the twelve months ended 2000, compared to $13,735,000, or $14,279,000 higher due to higher oil and gas prices and higher oil and gas production volumes associated with the Burrwood and West Delta 83 Fields acquisition in February 2000, and a full year of production at the Lafitte Field in 2000 compared to four months in 1999. Oil sales were reduced by $2,461,000 and gas sales were reduced by $441,000 for the year ended December 31, 2000 as a result of settlement of the Company's outstanding futures contracts. The Company recorded a gain on the sale of certain non-core oil and gas properties of $307,000 for the twelve months ended December 31, 2000. The Company incurred a loss on the sale of marketable equity securities of $519,000 for the twelve months ended December 31, 1999. The following table reflects the production volumes and pricing information for the periods presented:
2000 1999 ------------------------ ------------------------ Production Average Price Production Average Price ---------- ------------- ---------- ------------- Gas (Mcf)............... 3,394,921 $ 3.95 2,930,655 $ 2.41 Oil (Bbls).............. 571,766 $25.55 394,442 $16.88
Lease operating expense was $4,695,000 for 2000 compared to $2,681,000 for 1999, or $2,014,000 higher, due primarily to costs associated with the Company's Burrwood and West Delta 83 Fields and Lafitte Field acquisitions, and higher base operating costs associated with certain mature oil and gas fields. Production taxes for 2000 were $2,219,000 compared to $910,000 for 1999 or $1,309,000 higher due to higher oil and gas sales as a result of the Burrwood, West Delta 83 Field and Lafitte Field acquisitions. Depletion, depreciation and amortization was $5,954,000 in 2000 versus $4,744,000 in 1999, or $1,210,000 higher, due to increased oil and gas production including volumes associated with the Burrwood, West Delta 83 and Lafitte Field properties and increased capitalized costs. The Company incurred $2,813,000 of exploration expense in 2000 compared to $1,656,000 in 1999, or $1,157,000 higher, due primarily to seismic and dry hole costs of $796,000 and $475,000 respectively in 2000, compared to $51,000 and $68,000 respectively in 1999. The Company recorded an impairment in the recorded value of certain oil and gas properties in 2000 in the amount of $1,835,000 due primarily to a sooner than anticipated depletion of reserves in one non-core field. This compares to an impairment of $465,000 recorded in 1999. Interest expense was $4,390,000 in the twelve months ended December 31, 2000 compared to $2,810,000 in the twelve months ended December 31, 1999, or $1,580,000 higher, due to higher average debt outstanding and higher average effective interest rate for the twelve months ended December 31, 2000. The 2000 amount includes $919,000 of non cash expenses associated with the amortization of financing costs and debt discount in connection with the September 1999 private placement and amortization of the discount associated with the production payment liability recorded in connection with the Lafitte Field acquisition. Such non-cash expenses totaled $252,000 for the 1999 period. General and administrative expenses amounted to $2,518,000 for 2000 versus $1,990,000 in 1999. Liquidity and Capital Resources Net cash provided by operating activities was $15,760,000 or 25% higher in 2001 compared to $12,641,000 in 2000 and $1,065,000 in 1999. The accompanying consolidated statements of cash flows identify major differences between net income (loss) and net cash provided by operating activities for each of the years presented. Net cash used in investing activities amounted to $31,846,000 in 2001 compared to $15,881,000 in 2000 and $6,407,000 in 1999. Net cash used in investing activities for 2001 consists of capital expenditures of $32,253,000 and proceeds from the sale of oil and gas properties and equipment of $407,000. Net cash used in 13 investing activities for the twelve months ended December 31, 2000, reflects capital expenditures totaling $15,142,000, cash paid in connection with the acquisition of oil and gas properties of $1,199,000 and proceeds from the sale of oil and gas properties of $460,000. The amount for year ended December 31, 1999 is composed almost entirely of cash paid in connection with the purchase of oil and gas properties of $4,100,000 and exploration and drilling capital expenditures of $2,557,000. These amounts were partially offset by proceeds from the sale of marketable equity securities and the sale of an oil and gas property of $240,000 and $9,000, respectively. Net cash provided by financing activities was $12,802,000 in 2001 compared to $842,000 in 2000 and $11,176,000 in 1999. The 2001 amounts consist of proceeds from the issuance of common stock of $15,000,000 and pay downs by the Company under its line of credit of $13,690,000. The 2001 amounts also include proceeds from bank borrowings of $15,225,000, the payment of debt financing and public offering costs of $1,984,000, changes in restricted cash of $799,000, and production payments of $545,000. In addition, the 2001 amount includes preferred stock dividends of $626,000 and proceeds from the exercise of stock warrants and employee stock options of $210,000 and $12,000, respectively. The 2000 amount includes proceeds from the issuance of common stock of $9,150,000 and paydowns by the Company under its line of credit of $4,125,000. The 2000 amount includes preferred stock dividends of $2,308,000, changes in restricted cash of $1,240,000 and proceeds from the exercise of stock purchase warrants and director and employee stock options of $451,000. The 2000 amount also includes production payments of $653,000 and payment of debt and equity financing costs of $432,000. The 1999 amount includes proceeds from the issuance of convertible notes of $12,000,000 and proceeds from the issuance of preferred stock of $3,000,000. The amount also includes debt financing costs of $1,303,000 and pay downs of $2,409,000 by the Company under its line of credit. The 1999 period reflects no preferred dividends. Credit Facility On November 9, 2001, the Company established a new credit facility with BNP Paribas Bank, with a borrowing base of $25,000,000. The borrowing base will remain effective until the next borrowing base redetermination, which is scheduled to be made on or before March 31, 2002. Interest on the credit facility will accrue at a rate calculated at the option of the Company as either the BNP Paribas Bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%--2.50% depending on borrowing base utilization. Interest on LIBOR-Rate borrowings is due and payable on the last day of its respective Interest Period. Accrued interest on each Base-Rate borrowings is due and payable on the last day of each quarter. The credit facility will mature on November 8, 2004. The credit facility requires that the Company pay a 0.375% per annum commitment fee, payable in quarterly installments quarter based on the Company's borrowing base utilization. Prior to maturity, no payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility. The credit facility requires the Company to monitor tangible net worth and maintain certain financial statement ratios at certain levels. Substantially all the Company's assets are pledged to secure the credit facility. Public Offering On February 1, 2001, the Company completed a public offering of 3,000,000 shares of its common stock at $5.00 per share resulting in net proceeds of approximately $13.2 million to the Company. The Company used the proceeds from the offering and available cash to reduce outstanding debt under its credit facility by approximately $13.7 million. Exchange of Series B Preferred Stock Prior to the public offering, the Company reached an agreement with all of the holders of its Series B preferred stock to exchange each share of Series B for 1.8 shares of its common stock. Concurrent with the closing of the public offering, the Company exchanged all 660,839 shares of its Series B preferred stock into 1,189,510 shares of common stock. In connection with the conversion of the Series B preferred stock, a 14 conversion premium in the amount of $2,377,000 was recorded to reflect the excess of the 1:8 conversion factor over the terms of the original preferred stock issuance. This one-time, non-cash charge has been reflected as a preferred stock dividend to arrive at net income applicable to common stock and had no effect on stockholders equity. Stock Listing The Company has been notified by the New York Stock Exchange ("NYSE") that it has been removed from the NYSE's "Watch List" under the Exchange's continued listing and compliance standards and is now considered a "company in good standing" as the NYSE rule filing No. SR-NYSE-2001-02 was approved by the Securities and Exchange Commission on June 27, 2001. The Company will be subject to the NYSE's normal continued listing requirements and its monitoring process. Subsequent Events--Sale of Oil and Gas Properties to Related Party On March 12, 2002, the Company, in an effort to monetize a portion of the value created in its Burrwood and West Delta fields and enhance its liquidity position, completed the sale of a thirty percent (30%) working interest in the existing production and shallow rights, and a fifteen percent (15%) working interest in the deep rights below 10,600 feet, in its Burrwood and West Delta 83 fields for $12 million to Malloy Energy Company, LLC led by Patrick E. Malloy, III and participated in by Sheldon Appel, both members of the Company's Board of Directors. The sale price was determined by discounting the present value of the acquired interest in the fields' proved, probable and possible reserves using prevailing oil and gas prices. The Company has retained a sixty-five percent (65%) working interest in the existing production and shallow rights, and a thirty-two and one-half percent (32.5%) working interest in the deep rights after the close of the transaction. In conjunction with the sale, Malloy Energy Company, LLC, will provide a $7.7 million line of credit. The $7.7 million line of credit, which will reduce to $5.0 million on January 1, 2003, is subordinate to the Company's senior facility and can be used for acquisitions, drilling, development, and general corporate purposes until December 31, 2004. Malloy Energy Company, LLC, retains the option, during the two-year period, to convert the amount outstanding under the credit line, and/or provide cash on any unused credit up to a maximum of $7.7 million in the first year, reduced to $5.0 million after December 31, 2002, into working interests in any acquisition(s) the Company may make in Louisiana prior to January 1, 2005. The conversion of the credit line will be on a pro-rata basis with the Company and may not exceed a maximum of $7.7 million reduced to $5.0 million after December 31, 2002, or thirty percent (30%) of any potential acquisition(s). The Company will record a gain of approximately $2.1 million in the first quarter of 2002 as a result of the sale. The Company used the proceeds to reduce outstanding debt under its credit facility to approximately $12 million. Burrwood and West Delta 83 Field Performance Bond and Seismic Study In connection with the March 2, 2000 Burrwood and West Delta 83 Field aquisition, the Company secured a performance bond and established an escrow account to be used for the payment of obligations associated with the plugging and abandonment of the wells, salvage and removal of platforms and related equipment, and the site restoration of the fields. Required escrowed outlays included an initial cash payment of $750,000 and monthly cash payments of $70,000 beginning June 1, 2000 and continuing until June 1, 2005. The escrow agreement was amended in the fourth quarter of 2001 to suspend monthly cash payments and cap the escrow account at its current balance of $2,039,000. The escrow account is shown on the Balance Sheet as Restricted Cash. In addition, as part of the purchase agreement, the Company agreed to shoot a 3-D seismic survey over the fields which was completed in the fourth quarter of 2001. The cost of the seismic study was approximately $2,500,000 of which $1,250,000 was paid in 2001. Conversion of Private Placement Securities On February 17, 2000, all of the holders of the 300,000 outstanding preferred units of Goodrich Petroleum Company, LLC's Series A Preferred Units converted their units into approximately 1,550,000 shares of the 15 Company's common stock. The conversion of the preferred units into common stock increased the Company's stockholders equity by approximately $2,700,000. On August 17, 2000, the holders of approximately $12,943,000 of principal and accrued interest on the above mentioned convertible notes converted their notes into 3,235,647 shares of the Company's common stock. The conversion of the notes into common stock increased stockholders equity by approximately $10,130,000, inclusive of approximately $1,033,000 in remaining deferred loan financing costs, which were eliminated. Financing Transactions In October 2000 the Company completed a private placement of 1,000,000 shares of its common stock for gross proceeds of $5.0 million. In August 2000, the Company issued 3,235,647 shares of its common stock in connection with the conversion of convertible notes issued by two of its subsidiaries. The convertible notes had outstanding principal and accrued interest of $12.9 million at the time of conversion. In February 2000, the Company completed a private placement of 1,533,333 shares of its common stock resulting in gross proceeds of $4.5 million. Contractual Obligations and Guarantees--The Company is obligated to make future cash payments under its borrowing agreement. Total payments due after 2001 under such contractual obligations are shown below.
Amount Due ----------------------------------------- Total 2002 2003-2005 2006-2007 After 2007 (Millions of dollars) ----- ---- --------- --------- ---------- Long-term debt.................. $24.5 -- 24.5 -- --
Accounting Matters Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS No. 141) and Statement of Financial Accounting Standard No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142) were issued in July 2001. SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and that certain acquired intangible assets in a business combination be recognized and reported as assets apart from goodwill. SFAS No. 142 requires that amortization of goodwill be replaced with periodic tests of the goodwill's impairment at least annually in accordance with the provisions of SFAS No. 142 and that intangible assets other than goodwill be amortized over their useful lives. The Company will adopt SFAS No. 141 immediately and SFAS No. 142 in the first quarter 2002. The adoption of SFAS No. 141 and 142 are not expected to have a significant impact on the Company's financial statements. Statement of Financial Accounting Standard No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143) has been approved for issuance. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The statement is effective for fiscal years beginning after June 15, 2002. The Company has not yet determined what, if any, impact the adoption of this statement may have on its financial statements. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144). SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long- lived assets. This Statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. SFAS No. 144 requires companies to separately report discontinued 16 operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. The Company is required to adopt SFAS No. 144 on January 1, 2002. The Company has not yet determined what, if any, impact the adoption of this statement may have on its financial statements. Significant accounting policies--In preparing the financial statements of the Company in accordance with accounting principles generally accepted in the United States of America, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company's accounting policies requires a significant amount of estimates. These accounting policies are described below. . Proved oil and natural gas reserves--Proved reserves are defined by the Securities and Exchange Commission (SEC) as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although the Company's external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates utilized by the Company. The Company cannot predict the types of reserve revisions that will be required in future periods. . Successful efforts accounting--The Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on operating results. Successful exploration drilling costs and all development capital expenditures are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by engineers. The Company also uses proved developed reserves for calculating the amount of expense to recognize for future estimated dismantlement and abandonment costs. . Impairment of properties--The Company continually monitors its long- lived assets recorded in Property, Plant and Equipment in the Consolidated Balance Sheet to make sure that they are presented fairly and accurately. The Company must evaluate its properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. Performing these evaluations requires a significant amount of judgment since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserves, or other changes to contracts, environmental regulations or tax laws. The Company cannot predict the amount of impairment charges that may be recorded in the future. . Income taxes--The Company is subject to income and other related taxes in areas in which it operates. When recording income tax expense, certain estimates are required by management due to timing and the impact of future events on when income tax expenses and benefits are recognized by the Company. The Company has recorded a deferred tax asset relating primarily to its tax operating loss carryforwards. The Company periodically evaluates its deferred tax asset to determine the likelihood of its realization. A valuation allowance has been recorded for the deferred tax asset to the extent that they are not likely to be realized based on management's estimation. 17 Item 7A. Quantitative and Qualitative Disclosures About Market Risk Debt and debt-related derivatives The Company is exposed to interest rate risk on its short-term and long-term debt with variable interest rates. Based on the overall interest rate exposure on variable rate debt at December 31, 2001 a hypothetical 2% increase in the interest rates would increase interest expense by approximately $315,000. Hedging Activity The Company enters into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of its production. The Company considers these to be hedging activities and, as such, monthly settlements on these contracts are reflected in its oil and natural gas sales. The Company's strategy, which is reviewed periodically by its board of directors, has been to hedge between 30% and 70% of its production. Most of the Company's hedging arrangements are in the form of costless collars, whereby a floor and a ceiling are fixed. It is the Company's belief that the benefits of the downside protection afforded by these costless collars outweigh the costs incurred by losing potential upside when commodity prices increase. On January 1, 2001, the Company adopted a formal policy with respect to hedging arrangements in accordance with accounting pronouncements. The Company does not expect its hedging policy or future hedging practice to differ materially from its historical practice. The Company has no plans to engage in speculative activity not supported by production. The Company's futures contract agreements provide for separate contracts tied to the New York Mercantile Exchange ("NYMEX") light sweet crude oil and natural gas futures contracts. The contracts contain specific price ranges or "collars" that are settled monthly based on the differences between the contract price or price ranges and the average NYMEX prices for each month applied to the related contract volumes. To the extent the average NYMEX price exceeds the contract price, the Company pays the difference, and to the extent the contract price exceeds the average NYMEX price, the Company receives the difference. As of December 31, 2001, the Company's open forward position on its outstanding natural gas future contracts were as follows: (a) 2000 Mmbtu per day with a no cost collar of $2.50 and $3.18 per Mmbtu through December 31, 2002; and (b) 1333 Mmbtu per day with a no cost collar of $2.75 and $3.09 per Mmbtu through December 31, 2002. The fair value of the natural gas hedging contracts in place at December 31, 2001, resulted, in an asset of $13,000. The Company entered into the following oil and gas hedging contracts subsequent to December 31, 2001. Natural Gas 1,200 MMBtu per day "swap" at $2.87 for April through November 2002; 1,500 MMBtu per day "swap" at $2.89 for April through November 2002; and 3,000 MMBtu per day "swap" at $3.50 for December 2002 through February 2003. 18 Crude Oil 200 barrels of oil per day "swap" at $21.43 for March 2002; 300 barrels of oil per day "swap" at $21.95 for April and May 2002; 150 barrels of oil per day "swap" at $24.07 for April and May 2002; and 150 barrels of oil per day "swap" at $23.22 for April and May 2002 Price fluctuations and the volatile nature of markets Despite the measures the Company has taken to attempt to control price risk, it remains subject to price fluctuations for oil and natural gas sold in the spot market. Prices received for natural gas sold in the spot market are volatile due primarily to seasonality of demand and other factors beyond the Company's control. Oil and natural gas prices can change dramatically primarily as a result of the balance between supply and demand. The Company's average natural gas price received for the year ending December 31, 2001, was $3.97 per Mcf, up from $3.95 per Mcf in 2000 and $2.41 per Mcf in 1999. The Company's average oil price received for the year ended December 31, 2001, was $24.67, down from an average price received of $25.55 in 2000 and up from an average price received of $16.88 in 1999. There can be no assurance that prices will not decline from current levels. Declines in domestic oil and natural gas prices could have a material adverse effect on the Company's financial position, results of operations and quantities of reserves recoverable on an economic basis. Based on oil and gas pricing in effert at December 31, 2001, a hypothetical 2% increase or decrease in oil and gas pricing would not have had a material effect on the Company's financial statements. Disclosure Regarding Forward-Looking Statements This Annual Report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in this Annual Report on Form 10-K regarding reserve estimates, planned capital expenditures, future oil and gas production and prices, future drilling activity, the Company's financial position, business strategy and other plans and objectives for future operations, are forward- looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates and such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Additional important factors that could cause actual results to differ materially from the Company's expectations include changes in oil and gas prices, changes in regulatory or environmental policies, production difficulties, transportation difficulties and future drilling results. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors. 19 Item 8. Financial Statements and Supplementary Data INDEPENDENT AUDITORS' REPORT The Board of Directors and Stockholders Goodrich Petroleum Corporation: We have audited the accompanying consolidated balance sheets of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, cash flows and stockholders' equity and comprehensive income for each of the years in the three year period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note B to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities. KPMG LLP Shreveport, Louisiana March 22, 2002 20 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31, December 31, 2001 2000 ------------ ------------ ASSETS CURRENT ASSETS Cash and cash equivalents........................ $ 248,701 3,531,763 Accounts receivable Trade and other, net of allowance.............. 825,593 241,659 Accrued oil and gas revenue.................... 3,456,210 4,553,863 Prepaid insurance and other...................... 139,452 238,647 Fair value of oil and gas derivatives............ 13,000 -- ------------ ------------ Total current assets........................... 4,682,956 8,565,932 ------------ ------------ PROPERTY AND EQUIPMENT Oil and gas properties........................... 108,019,749 79,252,980 Furniture, fixtures and equipment................ 321,393 240,150 ------------ ------------ 108,341,142 79,493,130 Less accumulated depletion, depreciation and amortization.................................... (33,247,502) (26,044,257) ------------ ------------ Net property and equipment..................... 75,093,640 53,448,873 ------------ ------------ OTHER ASSETS Restricted Cash.................................. 2,039,000 1,240,000 Deferred taxes................................... 207,605 1,694,675 Other............................................ 220,730 394,114 ------------ ------------ Total Other Assets............................. 2,467,335 3,328,789 ------------ ------------ TOTAL ASSETS................................... $ 82,243,931 65,343,594 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable................................. 2,398,437 3,043,477 Accrued liabilities.............................. 1,693,674 1,231,965 Current portion of other noncurrent liabilities.. 124,875 820,454 ------------ ------------ Total current liabilities...................... 4,216,986 5,095,896 ------------ ------------ LONG TERM DEBT..................................... 24,500,000 22,965,000 OTHER NONCURRENT LIABILITIES Production payment payable....................... 1,264,729 969,870 Accrued abandonment costs........................ 4,341,669 3,707,612 ------------ ------------ Total liabilities.............................. 34,323,384 32,738,378 ------------ ------------ STOCKHOLDERS' EQUITY Preferred stock; authorized 10,000,000 shares: Series A convertible preferred stock, par value $1.00 per share; issued and outstanding 791,968 and 791,968 shares (liquidating preference $10 per share, aggregating to $7,919,680).......... 791,968 791,968 Series B convertible preferred stock, par value $1.00 per share; issued and outstanding 0 and 660,839 shares (liquidation preference $10 per share, aggregating to $6,608,390).............. -- 660,839 Common stock, par value $0.20 per share; authorized 25,000,000 shares; issued and outstanding 17,896,356 and 13,318,920 shares.... 3,579,271 2,663,784 Additional paid-in capital....................... 52,279,331 39,348,013 Accumulated deficit.............................. (8,738,473) (10,859,388) Accumulated other comprehensive income........... 8,450 ---- ------------ ------------ Total stockholders' equity..................... 47,920,547 32,605,216 ------------ ------------ TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY... $ 82,243,931 65,343,594 ============ ============
See notes to consolidated financial statements. 21 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, ----------------------------------- 2001 2000 1999 ----------- ---------- ---------- REVENUES Oil and gas sales....................... $29,541,662 28,014,245 13,734,691 Other................................... 353,117 475,146 285,883 ----------- ---------- ---------- Total revenues........................ 29,894,779 28,489,391 14,020,574 ----------- ---------- ---------- COSTS AND EXPENSES Lease operating expense................. 6,576,247 4,694,714 2,680,934 Production taxes........................ 1,865,726 2,219,254 910,493 Depletion, depreciation and amortization........................... 6,844,751 5,953,641 4,743,608 Exploration............................. 4,174,436 2,813,332 1,656,158 Impairment of oil and gas properties.... 1,800,536 1,834,654 465,465 Interest expense........................ 1,290,681 4,390,331 2,810,576 General and administrative.............. 3,134,865 2,518,228 1,989,703 Other................................... -- 250,000 -- Preferred dividend requirements of subsidiary............................. -- 38,364 73,125 ----------- ---------- ---------- Total costs and expenses.............. 25,687,242 24,712,518 15,330,062 ----------- ---------- ---------- GAIN (LOSS) ON SALES OF ASSETS............ 26,779 307,299 (519,495) ----------- ---------- ---------- INCOME (LOSS) BEFORE INCOME TAXES......... 4,234,316 4,084,172 (1,828,983) Income Taxes............................ 1,487,070 (1,655,032) -- ----------- ---------- ---------- NET INCOME (LOSS)......................... 2,747,246 5,739,204 (1,828,983) Preferred stock dividends............... 3,002,872 1,193,768 1,249,343 ----------- ---------- ---------- INCOME (LOSS) APPLICABLE TO COMMON STOCK.. (255,626) 4,545,436 (3,078,326) =========== ========== ========== BASIC INCOME (LOSS) PER AVERAGE COMMON SHARE.................................... $ (.01) .46 (.58) =========== ========== ========== DILUTED INCOME (LOSS) PER AVERAGE COMMON SHARE.................................... $ (.01) .35 (.58) =========== ========== ========== AVERAGE COMMON SHARES OUTSTANDING--BASIC.. 17,351,375 9,903,248 5,288,011 AVERAGE COMMON SHARES OUTSTANDING-- DILUTED.................................. 17,351,375 13,116,641 5,288,011
See notes to consolidated financial statements. 22 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, ------------------------------------ 2001 2000 1999 ----------- ----------- ---------- OPERATING ACTIVITIES Net income(loss)........................ $ 2,747,246 5,739,204 (1,828,983) Adjustments to reconcile net income(loss) to net cash provided by operating activities: Depletion, depreciation and amortization........................... 6,844,751 5,953,641 4,743,607 Amortization of leasehold costs......... 1,017,426 1,007,636 1,103,219 Amortization of deferred debt financing costs.................................. 121,945 331,042 109,088 Deferred income taxes................... 1,487,070 (1,655,032) -- Impairment of oil and gas properties.... 1,800,536 1,834,654 465,465 Accrued interest and other charges on private placement borrowings........... -- 973,631 -- Amortization of debt discount........... -- 357,016 142,500 Amortization of production payment discount............................... 119,728 230,649 251,154 Preferred dividends of subsidiary....... -- 38,364 73,125 (Gain)Loss on sale of asset............. (26,779) (307,299) 519,495 Director stock grant.................... 30,000 30,000 30,000 Dry hole costs.......................... 1,604,226 475,130 119,800 Payment of contingent liability......... -- -- (68,636) Other................................... -- 250,000 -- Net change in: Accounts receivable.................... 513,719 (2,188,070) 678,953 Prepaid insurance and other............ 93,945 (181,323) 195,975 Accounts payable....................... (645,041) 331,728 (5,051,761) Accrued liabilities.................... 81,709 (95,030) (418,092) Other liabilities...................... -- (484,525) -- ----------- ----------- ---------- Net cash provided by operating activities........................... 15,790,481 12,641,416 1,064,909 ----------- ----------- ---------- INVESTING ACTIVITIES Proceeds from sales of assets........... 406,779 459,526 249,487 Acquisition of oil and gas properties... -- (1,198,631) (4,099,956) Capital expenditures.................... (32,252,774) (15,141,818) (2,556,901) ----------- ----------- ---------- Net cash used in investing activities........................... (31,845,995) (15,880,923) (6,407,370) ----------- ----------- ---------- FINANCING ACTIVITIES Proceeds from private placement of common stock........................... 15,000,000 9,150,000 -- Principal payments of bank borrowings... (13,690,000) (4,125,617) (2,409,383) Proceeds from bank borrowings........... 15,225,000 -- -- Preferred stock dividends............... (626,331) (2,308,011) -- Proceeds from private placement borrowings............................. -- -- 12,000,000 Proceeds from preferred stock issue..... -- -- 3,000,000 Exercise of stock purchase warrants..... 180,233 249,322 -- Exercise of employee stock options...... 11,563 191,444 3,909 Exercise of director stock options...... -- 9,875 -- Net change in restricted cash........... (799,000) (1,240,000) -- Payment of debt and equity financing costs.................................. (1,983,691) (431,557) (1,303,496) Production payments..................... (545,322) (653,415) (114,970) ----------- ----------- ---------- Net cash provided by financing activities........................... 12,772,452 842,041 11,176,060 ----------- ----------- ---------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................. (3,283,062) (2,397,466) 5,833,599 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.................................. $ 3,531,763 5,929,229 95,630 ----------- ----------- ---------- CASH AND CASH EQUIVALENTS AT END OF PERIOD.................................. 248,701 3,531,763 5,929,229 =========== =========== ========== NON CASH INVESTING AND FINANCING ACTIVITIES Conversion of net carrying amount of notes payable and accrued interest..... -- 10,130,349 -- Conversion of preferred stock of subsidiary............................. -- 2,721,489 -- Acquisition of oil and gas properties and assumption of related liabilities.. -- -- 6,036,342 Costs of private placement.............. -- -- 355,800
See notes to consolidated financial statements. 23 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME Years Ended December 31, 2001, 2000 and 1999
Additional Accumulated Series A Series B Paid-In Accumulated Other Comprehensive Preferred Stock Preferred Stock Common Stock Capital Deficit Income ----------------- ------------------- --------------------- ------------ ------------- ------------------- Balance at 796,318 January 1, 1999 $796,318 750,000 $ 750,000 5,247,705 $1,049,541 $ 15,226,027 $ (12,461,598) $ (400,900) Net loss........ -- -- -- -- -- -- -- (1,828,983) -- Realized loss on sale of marketable Securities...... -- -- -- -- -- -- -- -- 400,900 Total Comprehensive Income (Loss)... -- -- -- -- -- -- -- -- -- Issuance of Common Stock purchase Warrants with Preferred Stock........... -- -- -- -- -- -- 210,000 -- -- Issuance of Common Stock purchase Warrants for services........ -- -- -- -- 40,000 8,000 113,800 -- -- Issuance of Common Stock purchase Warrants as transaction fee............. -- -- -- -- -- -- 234,000 -- -- Issuance of Common Stock Purchase Warrants with debt............ -- -- -- -- -- -- 2,280,000 -- -- Director Stock Grants.......... -- -- -- -- 30,000 6,000 24,000 -- -- Exercise of Employee Stock Options......... -- -- -- -- 5,250 1,050 2,889 -- -- Conversion of Series B Preferred Stock to Common Stock........... -- -- (84,241) (84,241) 94,216 18,843 65,398 -- -- ------- -------- -------- --------- ---------- ---------- ------------ ------------- ---------- Balance at December 31, 1999............ 796,318 $796,318 665,759 $ 665,759 5,417,171 $1,083,434 $ 18,156,114 $(14 ,290,581) $ -- ======= ======== ======== ========= ========== ========== ============ ============= ========== Net Income...... -- -- -- -- -- -- -- 5,739,204 -- Total Comprehensive Income.......... -- -- -- -- -- -- -- -- -- Issuance of Common Stock.... -- -- -- -- 2,533,333 506,667 8,643,333 -- -- Conversion of preferred stock of subsidiary to common stock.... -- -- -- -- 1,547,665 309,533 2,411,956 -- -- Exercise of director stock option.......... -- -- -- -- 12,500 2,500 7,375 -- -- Conversion of notes payable... -- -- -- -- 3,295,647 659,130 9,751,719 -- -- Preferred stock dividends....... -- -- -- -- -- -- -- (2,308,011) -- Exercise of common stock purchase warrants........ -- -- -- -- 252,022 50,403 198,919 -- -- Exercise of Employee Stock Options......... -- -- -- -- 245,698 49,140 142,304 -- -- Director Stock Grant........... -- -- -- -- 6,000 1,200 28,800 -- -- Conversion of Series B Preferred Stock to Common Stock........... -- -- (4,920) (4,920) 5,486 1,097 3,823 -- -- Conversion of Series A Preferred Stock to Common Stock........... (4,350) (4,350) -- -- 3,398 680 3,670 -- -- ------- -------- -------- --------- ---------- ---------- ------------ ------------- ---------- Balance at December 31, 2000............ 791,968 $791,968 660,839 $ 660,839 13,318,920 $2,663,784 $ 39,348,013 $(10, 859,388) $ -- ======= ======== ======== ========= ========== ========== ============ ============= ========== Net Income...... -- -- -- -- -- -- -- 2,747,246 -- Cumulative Effect of Accounting Change, net of tax............. -- -- -- -- -- -- -- -- (2,535,469) Net Derivative Gain, net of tax............. -- -- -- -- -- -- -- -- 1,797,336 Reclassification Adjustment, net of tax.......... -- -- -- -- -- -- -- -- 746,583 Total Comprehensive Income.......... -- -- -- -- -- -- -- -- -- Issuance of Common Stock.... -- -- -- -- 3,000,000 600,000 12,469,170 -- -- Preferred stock dividends....... -- -- -- -- -- -- -- (626,331) -- Exercise of common stock purchase warrants........ -- -- -- -- 375,296 75,059 105,174 -- -- Exercise of Employee Stock Options......... -- -- -- -- 7,500 1,500 10,063 -- -- Conversion of Series B Preferred Stock to Common Stock........... -- -- (660,839) (660,839) 1,189,510 237,902 317,937 -- -- Director Stock Grant........... -- -- -- -- 5,130 1,026 28,974 -- -- ------- -------- -------- --------- ---------- ---------- ------------ ------------- ---------- Balance at December 31, 2001............ 791,968 $791,968 -- $ -- 17,896,356 $3,579,271 $ 52,279,331 $ (8,738,473) $ 8,450 ======= ======== ======== ========= ========== ========== ============ ============= ========== Total Stockholders' Equity ------------- Balance at January 1, 1999 $ 4,959,388 Net loss........ (1,828,983) Realized loss on sale of marketable Securities...... 400,900 ------------- Total Comprehensive Income (Loss)... (1,428,083) Issuance of Common Stock purchase Warrants with Preferred Stock........... 210,000 Issuance of Common Stock purchase Warrants for services........ 121,800 Issuance of Common Stock purchase Warrants as transaction fee............. 234,000 Issuance of Common Stock Purchase Warrants with debt............ 2,280,000 Director Stock Grants.......... 30,000 Exercise of Employee Stock Options......... 3,939 Conversion of Series B Preferred Stock to Common Stock........... -- ------------- Balance at December 31, 1999............ $ 6,411,044 ============= Net Income...... 5,739,204 ------------- Total Comprehensive Income.......... 5,739,204 Issuance of Common Stock.... 9,150,000 Conversion of preferred stock of subsidiary to common stock.... 2,721,489 Exercise of director stock option.......... 9,875 Conversion of notes payable... 10,410,849 Preferred stock dividends....... (2,308,011) Exercise of common stock purchase warrants........ 249,322 Exercise of Employee Stock Options......... 191,444 Director Stock Grant........... 30,000 Conversion of Series B Preferred Stock to Common Stock........... -- Conversion of Series A Preferred Stock to Common Stock........... -- ------------- Balance at December 31, 2000............ $32,605,216 ============= Net Income...... 2,747,246 Cumulative Effect of Accounting Change, net of tax............. (2,535,469) Net Derivative Gain, net of tax............. 1,797,336 Reclassification Adjustment, net of tax.......... 746,583 ------------- Total Comprehensive Income.......... 2,755,696 Issuance of Common Stock.... 13,069,170 Preferred stock dividends....... (626,331) Exercise of common stock purchase warrants........ 180,233 Exercise of Employee Stock Options......... 11,563 Conversion of Series B Preferred Stock to Common Stock........... (105,000) Director Stock Grant........... 30,000 ------------- Balance at December 31, 2001............ 47,920,547 =============
See notes to consolidated financial statements 24 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2001 NOTE A--Description of Business The Company is in the primary business of exploration and production of crude oil and natural gas. The Company's subsidiaries have interests in such operations in seven states, primarily in Louisiana and Texas. NOTE B--Summary of Significant Accounting Policies Principles of Consolidation--The consolidated financial statements include the financial statements of Goodrich Petroleum Corporation and its wholly- owned subsidiaries. Significant intercompany balances and transactions have been eliminated in consolidation. Revenue Recognition--Revenues from the production of crude oil and natural gas properties in which the Company has an interest with other producers are recognized on the entitlements method. The Company records a liability for natural gas balancing when the Company has sold more than its working interest share of natural gas production. At December 31, 2001 and 2000, the liabilities for gas balancing were immaterial. Differences between actual production and net working interest volumes are routinely adjusted. These differences are not significant. Property and Equipment--The Company uses the successful efforts method of accounting for exploration and development expenditures. Leasehold acquisition costs are capitalized. When proved reserves are found on an undeveloped property, leasehold cost is reclassified to proved properties. Significant undeveloped leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. Cost of all other undeveloped leases is amortized over the estimated average holding period of the leases. Costs of exploratory drilling are initially capitalized, but if proved reserves are not found, the costs are subsequently expensed. All other exploratory costs are charged to expense as incurred. Development costs are capitalized, including the cost of unsuccessful development wells. The Company follows SFAS No. 121 and recognizes an impairment when the net of future cash inflows expected to be generated by an identifiable long-lived asset and cash outflows expected to be required to obtain those cash inflows is less than the carrying value of the asset. The Company performs this comparison for its oil and gas properties on a field-by-field basis using the Company's estimates of future commodity prices. The amount of such loss is measured based on the difference between the discounted value of such net future cash flows and the carrying value of the asset. The Company recorded such impairments in 2001, 2000 and 1999 in the amounts of $1,801,000, $1,835,000 and $465,000 respectively. The impairments were generally the result of certain non-core fields depleting earlier than anticipated. Depreciation and depletion of producing oil and gas properties are provided under the unit-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs. Estimated dismantlement, abandonment, and site restoration costs, net of salvage value, are considered in determining depreciation and depletion provisions. Gains and losses on disposals or retirements that are significant or include an entire depreciable or depletable property unit are included in income. All other dispositions, retirements, or abandonments are reflected in accumulated depreciation, depletion, and amortization. Cash and Cash Equivalents--Cash and cash equivalents include cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at date of purchase. 25 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 Marketable Equity Securities--The Company classifies its investment in marketable equity securities as available for sale. Accordingly, unrealized holding gains and losses are excluded from earnings and are reported as other comprehensive income until realized. Income Taxes--The Company follows the provisions of SFAS No. 109, Accounting for Income Taxes, which requires income taxes be accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Earnings Per Share--Basic income per common share is computed by dividing net income available for common stockholders, for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income per common share is computed by dividing net income available for common stockholders for each reporting period by the weighted average number of common shares outstanding during the period, plus the effects of potentially dilutive common shares. Derivative Instruments and Hedging Activities--The Company utilizes derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging its exposure to fluctuations in the price of crude oil and natural gas. Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standard (SFAS 133), Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138. See also Note K for further information about the Company's derivative instruments. In accordance with the transition provisions of SFAS 133, the Company recorded a cumulative-effect- type adjustment of $2,535,000 (net of $1,365,000 in income taxes) in accumulated other comprehensive income to recognize at fair value all derivatives that were designated as cash flow hedging instruments. There was no cumulative effect on earnings. The fair value of a derivative instrument is recognized as an asset or liability in the Company's Consolidated Balance Sheet. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, mark the contract to market through earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items, as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception, and on an ongoing basis, whether a derivative instrument used as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income, until earnings are affected by the cash flows of the hedged item. When the cash flow of the hedged item is recognized in the Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Ineffective portions of a cash flow hedging derivative's change in fair value are recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was recorded in other comprehensive income is recognized immediately in earnings. 26 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) For the years ended December 31, 2000, and 1999, prior to the adoption of SFAS No. 133, gains and losses from derivatives designated as hedges of sales were reported on the Statement of Income as an increase or reduction of oil and gas sales in the period related to the actual sale of product. Premiums paid on hedging contracts were amortized over the life of the contracts as a reduction to oil and gas sales. Accounting Matters--Statement of Financial Accounting Standards No. 141, "Business Combinations" (SFAS No. 141) and Statement of Financial Accounting Standard No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142) were issued in July 2001. SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and that certain acquired intangible assets in a business combination be recognized and reported as assets apart from goodwill. SFAS No. 142 requires that amortization of goodwill be replaced with periodic tests of the goodwill's impairment at least annually in accordance with the provisions of SFAS No. 142 and that intangible assets other than goodwill be amortized over their useful lives. The Company will adopt SFAS No. 141 immediately and SFAS No. 142 in the first quarter 2002. The adoption of SFAS No. 141 and 142 are not expected to have a significant impact on the Company's financial statements. Statement of Financial Accounting Standard No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143) has been approved for issuance. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The statement is effective for fiscal years beginning after June 15, 2002. The Company has not yet determined what, if any, impact the adoption of this statement may have on its financial statements. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144). SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long- lived assets. This Statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. SFAS No. 144 requires companies to separately report discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. The Company is required to adopt SFAS No. 144 on January 1, 2002. The Company has not yet determined what, if any, impact the adoption of this statement may have on its financial statements. Stock Based Compensation--The Company uses SFAS No. 123, Accounting for Stock-Based Compensation, which permits entities to recognize as expense, over the vesting period, the fair value of all stock-based awards on the date of grant. Alternatively, SFAS No. 123 also allows entities to continue to apply the provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and provide pro forma net income and pro forma earnings per share and other disclosures for employee stock options grants made in 1995 and future years as if the fair-value-based method defined in SFAS No. 123 had been applied. The Company has elected to continue to apply the provisions of APB Opinion No. 25 and provide the disclosure provisions of SFAS No. 123. Commitments and Contingencies--Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, which are probable of realization, are separately recorded, and are not offset against the related environmental liability. 27 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Use of Estimates--Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. NOTE C--Sale of Oil and Gas Properties to Related Party On March 12, 2002, the Company, in an effort to monetize a portion of the value created in its Burrwood and West Delta fields and enhance its liquidity position, completed the sale of a thirty percent (30%) working interest in the existing production and shallow rights, and a fifteen percent (15%) working interest in the deep rights below 10,600 feet, in its Burrwood and West Delta 83 fields for $12 million to Malloy Energy Company, LLC led by Patrick E. Malloy, III and participated in by Sheldon Appel, both members of the Company's Board of Directors. The sale price was determined by discounting the present value of the acquired interest in the fields' proved, probable and possible reserves using prevailing oil and gas prices. The Company retains a sixty-five percent (65%) working interest in the existing production and shallow rights, and a thirty-two and one-half percent (32.5%) working interest in the deep rights after the close of the transaction. In conjunction with the sale, the investor group will provide a $7.7 million line of credit. The $7.7 million line of credit, which will reduce to $5.0 million on January 1, 2003, is subordinate to the Company's senior facility and can be used for acquisitions, drilling, development and general corporate purposes until December 31, 2004. The investor group retains the option, during the two-year period, to convert the amount outstanding under the credit line, and/or provide cash on any unused credit to a maximum of $7.7 million in the first year, reduced to $5.0 million after December 31, 2002, into working interests in any acquisition(s) the Company may make in Louisiana prior to January 1, 2005. The conversion of the credit facility will be on a pro-rata basis with the Company and may not exceed a maximum of $7.7 million reduced to $5.0 million after December 31, 2002 or thirty percent (30%) of any potential acquisition(s). The Company will record a gain of approximately $2.1 million in the first quarter of 2002 as a result of the sale. The proceeds were used to reduce outstanding debt under its credit facility to approximately $12 million. NOTE D--Public Offering On February 1, 2001, the Company completed a public offering of 3,000,000 shares of its common stock at $5.00 per share resulting in net proceeds of approximately $13.2 million to the Company. The Company used the proceeds from the offering along with other available funds to reduce outstanding debt under its credit facility by approximately $13.7 million. NOTE E--Exchange of Series B Preferred Stock Prior to the public offering, the Company reached an agreement with all of the holders of its Series B preferred stock to exchange each share of Series B preferred stock for 1.8 shares of its common stock. Concurrent with the closing of the public offering, the Company exchanged all 660,839 shares of its Series B preferred stock into 1,189,510 shares of common stock. In connection with the conversion of the Series B preferred stock, a conversion premium in the amount of $2,377,000 was recorded to reflect the excess of the 1:8 conversion factor over the terms of the original preferred stock issuance. This one-time, non-cash charge was reflected as a preferred stock dividend to arrive at net income applicable to common stock and did not have an affect on total stockholders' equity. 28 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) NOTE F--Indebtedness Indebtedness at December 31, 2001 and 2000 consists of the following:
2001 2000 ----------- ---------- Bank Debt Borrowings under credit facility, interest, at BNP prime plus 0.5% or Libor plus 2.5% (weighted average rate at December 31, 2001--7.4%); principal due November 8, 2004...................................... $24,500,000 -- Borrowings under credit facility, interest, at Compass Prime plus 5/8% (weighted average rate at December 31, 2000--9.9%)........................................... $ -- 22,965,000 Less current portion................................... -- -- ----------- ---------- Long-term debt, excluding current portion.............. $24,500,000 22,965,000 =========== ==========
BNP Paribas Credit Facility On November 9, 2001, the Company established a new credit facility with BNP Paribas Bank, with a borrowing base of $25,000,000. The borrowing base will remain effective until the next borrowing base redetermination, which is scheduled to be made on or before March 31, 2002. Interest on the credit facility will accrue at a rate calculated at the option of the Company as either the BNP Paribas Bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%-2.50% depending on borrowing base utilization. Interest on each LIBOR- Rate borrowing is due and payable on the last day of the borrowing term. Accrued interest on each Base-Rate borrowing is due and payable on the last day of each quarter. The credit facility will mature on November 8, 2004. The credit facility requires that the Company pay a 0.375% per annum commitment fee each quarter based on the Company's borrowing base utilization. Prior to maturity no payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility. The credit facility requires the Company to monitor tangible net worth and maintain certain financial statement ratios at certain levels. Substantially all the Company's assets are pledged to secure the credit facility. Interest paid during 2001, 2000 and 1999 amounted to $849,725, $2,182,724 and $2,338,840 respectively. NOTE G--Income (Loss) Per Share Net income (loss) was used as the numerator in computing both basic and diluted income (loss) per common share for the years ended December 31, 2001, 2000 and 1999. The following table reconciles the weighted average shares outstanding used for these computations.
Year Ended December 31, ------------------------------- 2001 2000 1999 ---------- ---------- --------- Basic Method................................ 17,351,375 9,903,248 5,288,011 Dilutive Stock Warrants..................... -- 2,842,858 -- Dilutive Stock Options...................... -- 370,535 -- Convertible Debt............................ -- -- -- ---------- ---------- --------- --- Diluted Method.............................. 17,351,375 13,116,641 5,288,011 ========== ========== =========
The Company's Series A convertible preferred stock and its stock options are considered to be potential common stock. Additionally, stock purchase warrants issued in the 1999 Private Placement are also considered potential common stock. Approximately 798,000 stock options and 1,067,000 shares issuable in connection with 29 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) the convertible preferred stock have not been included in the computation of diluted income per share in 2000 respectively, because to do so would have been antidilutive. No potential common stock amounts have been included in the computation of diluted per share in 2001 and 1999 because to do so would have been antidilutive. The calculation of the dilutive effects of potentially dilutive securities has been calculated under the treasury stock method. NOTE H--Income Taxes Income tax expense (benefit) for the years ending December 31, 2001, 2000 and 1999 consists of:
Current Deferred Total ------- ---------- ---------- Year Ended December 31, 2001: U.S. Federal........................... $ -- 1,487,070 1,487,070 State.................................. -- -- -- ------ ---------- ---------- -- 1,487,070 1,487,070 ====== ========== ========== Year Ended December 31, 2000: U.S. Federal........................... $ -- (1,655,032) (1,655,032) State.................................. -- -- -- ------ ---------- ---------- -- (1,655,032) (1,655,032) ====== ========== ========== Year Ended December 31, 1999: U.S. Federal........................... $ -- -- -- State.................................. -- -- -- ------ ---------- ---------- -- -- -- ====== ========== ==========
-------- (1) Includes the recognition of the benefit of $1,436,000 of net operating loss carry forwards. The following is a reconciliation of the U.S. statutory income to the Company's income (loss) before income taxes for the years ended December 31, 2001, 2000 and 1999:
2001 2000 1999 --------- ---------- -------- U.S. statutory income tax................. 1,482,011 1,429,460 (640,144) Increase in deductible temporary differences for which no benefit recorded................................. -- -- 640,144 Change in the beginning of the year balance of the valuation allowance allocated to income tax expense.......... -- (3,089,767) -- Nondeductible expenses.................... 5,059 5,275 -- --------- ---------- -------- --- 1,487,070 (1,655,032) -- ========= ========== ========
30 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2001 and 2000 are presented below.
2001 2000 ------------ ------------ Deferred tax assets: Differences between book and tax basis of: Contingent liabilities........................ $ 107,848 132,349 Other......................................... 229,798 157,247 Operating loss carryforwards.................. 12,878,565 14,383,974 Statutory depletion carryforward.............. 6,695,115 6,407,941 AMT Tax credit carryforward................... 1,399,890 1,477,872 Investment tax credit carryforward............ -- 2,108 ------------ ------------ Total gross deferred tax assets............... 21,311,216 22,561,491 Less valuation allowance...................... (17,000,473) (16,816,199) ------------ ------------ Net deferred tax assets....................... 4,310,743 5,745,292 ------------ ------------ Deferred tax liability: Differences between book and tax basis of: Property and equipment........................ (4,103,138) (4,050,617) ------------ ------------ Total gross deferred liability................ (4,103,138) (4,050,617) ------------ ------------ Net deferred tax asset........................ $ 207,605 1,694,675 ============ ============
The valuation allowance for deferred tax assets increased $184,274 and decreased $2,968,470 for the years ended December 31, 2001 and 2000, respectively. The increase in 2001 is primarily the result of changes in deferred tax assets. The decrease in 2000 is primarily the result of recognizing a change in the beginning of the year valuation allowance resulting from changes in management's estimates of future taxable income. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based primarily upon the level of projections for future taxable income and the reversal of future taxable temporary differences over the periods which the deferred tax assets are deductible, management believes it is more likely than not the Company will realize the benefits of these deductible differences, net of the existing valuation allowance at December 31, 2001. The amount of the deferred tax assets considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced. 31 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 The following table summarizes the amounts and expiration dates of operating loss and investment tax credit carryforwards:
Operating loss carryforwards ---------------------------------------------------------------- Amount Expires ----------- ------- $ 3,963,174 2006 8,860,622 2007 4,285,746 2008 3,247,494 2009 6,450,859 2010 600,706 2011 1,939,496 2012 4,530,029 2018 2,546,445 2019 371,329 2020 ----------- $36,795,900 ===========
An ownership change in accordance with Internal Revenue Code (IRC) (S)382, occurred in August 1995 and again in August 2000. The net operating losses (NOLs) generated prior to August 1995 are subject to an annual IRC (S)382 limitation of $1,682,797. The IRC (S)382 annual limitation for the ownership change in August 2000 is $3,647,700. The latter IRC (S)382 ownership change limitation is a cumulative limitation and does not eliminate or increase the limitation on the pre-August 1995 NOLs. The NOL's generated after August 1995 and prior to August 2000, are subject to an annual limitation of $3,647,700 less the annual amount utilized for pre-August 1995 NOLs. It should be noted that the same IRC (S)382 limitations apply to the alternative minimum tax net operating loss carryforwards depletion carryforwards, and alternative minimum tax credit carryforwards. The minimum tax credit carryforward (MTC) of $1,399,890 as of December 31, 2000, will not begin to be utilized until after the available NOLs have been utilized or expired and when regular tax exceeds the current year alternative minimum tax. Additionally, the statutory (percentage) depletion carryforward of $19,128,899 is considered a special deduction under FASB Statement 109. In accordance with Statement 109, the tax benefits of special deductions are generally recognized in the year they become deductible on the tax return. The unused annual IRC (S)382 limitations can be carried over to subsequent years. NOTE I--Production Payment Obligation A production payment was entered into by the Company to assist in the financing of the Lafitte Field acquisition in September 1999. The original amount of the production payment obligation was $2,940,000, which was recorded as a production payment liability of $2,228,000 after a discount to reflect an effective rate of interest of 11.25%. At December 31, 2001 the remaining principal amount was $1,627,000 and the recorded liability was $1,265,000. Under the terms of the production payment the Company must make monthly cash payments which approximate the Company's forty-nine percent share of 10% of the monthly gross oil and gas revenue of the Lafitte Field. The Company's estimate as of December 31, 2001, based on expected production and prices and expected discount amortization is that projected payments will decrease the recorded liability as follows: 2002, $481,000; 2003, $451,000 and 2004, $333,000. 32 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 NOTE J--Stockholders' Equity On February 1, 2001, the Company completed a public offering of 3,000,000 shares of its common stock at $5.00 per share resulting in net proceeds of approximately $13.2 million to the Company. The Company used the proceeds from the offering along with other available funds to reduce outstanding debt under its credit facility by approximately $13.7 million. On October 23, 2000, the Company completed a private placement of 1,000,000 shares of common stock at $5.00 per share. Net proceeds from the private placement amounted to $4,650,000 and were used primarily to accelerate the development of the Company's Burrwood and West Delta 83 fields. An affiliate of a member of the Company's board of directors received $250,000 in compensation for its service in placing the shares in the private placement. On February 18, 2000, the Company completed a private placement of shares of its common stock resulting in net proceeds to the Company of $4,500,000. The Company issued 1,533,000 shares of common stock in its offering. The $4,500,000 in offering proceeds was used to assist in the acquisition and development of the Burrwood and West Delta 83 fields, and to further develop the Lafitte field purchased in 1999. Common Stock--At December 31, 2001 unissued shares of Goodrich common stock were reserved in the amount of 4,534,000 shares for the exercise of stock warrants issued in connection with the private placement transaction of September 23, 1999 and 330,013 shares for stock option plans. Preferred Stock The Series A convertible preferred stock has a par value of $1.00 per share with a liquidation preference of $10.00 per share, and is convertible at the option of the holder at any time, unless earlier redeemed, into shares of common stock of the Company at an initial conversion rate of .417 shares of common stock per share of Series A preferred. The Series A preferred stock also will automatically convert to common stock if the closing price for the Series A preferred stock exceeds $15.00 per share for ten consecutive trading days. The Series A preferred stock is redeemable in whole or in part, at $12.00 per share, plus accrued and unpaid dividends. Dividends on the Series A preferred stock accrue at an annual rate of 8% and are cumulative. The Company issued 750,000 shares of Series B convertible preferred stock in connection with its acquisition of the La/Cal II properties on January 31, 1997. The Series B convertible preferred stock had a par value of $1.00 per share with a liquidation preference of $10.00 per share and ranked junior to the Series A preferred stock. The shares of Series B preferred stock were convertible at the option of the holder at any time, unless earlier redeemed, into shares of common stock of the Company at the conversion rate of 1.12 shares of common stock per share of Series B preferred stock. The Series B preferred stock was redeemable by the Company prior to January 31, 2001 at $10.00 per share. Dividends on the Series B preferred stock accrued at an annual rate of 8.25% and were cumulative. The Company reached an agreement with all of the holders of its Series B preferred stock to exchange each share of Series B for 1.8 shares of its common stock. Concurrent with the closing of its public offering (See Note E), the Company exchanged all 660,839 shares of its Series B preferred stock into 1,189,510 shares of common stock. Stock Option and Incentive Programs--Goodrich currently has two plans, which provide for stock option and other incentive awards for the Company's key employees, consultants and directors. The Goodrich Petroleum Corporation 1995 Stock Option Plan allows the Board of Directors to grant stock options, restricted stock awards, 33 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 stock appreciation rights, long-term incentive awards and phantom stock awards, or any combination thereof, to key employees and consultants. The Goodrich Petroleum Corporation 1997 Director Compensation Plan provides for the grant of stock and options to each director who is not and has never been an employee of the Company. Additionally, the Company assumed certain outstanding stock options of Patrick as a result of the business combination in 1995. The Goodrich plans authorize grants of options to purchase up to a combined total of 1,587,168 shares of authorized but unissued common stock. Stock options are generally granted with an exercise price equal to the stock's fair market value at the date of grant, and all stock options granted under the 1995 Stock Option Plan generally have ten year terms and three year pro rata vesting. The per share weighted average fair value of stock options granted during 2001, 2000 and 1999 was $2.63, $3.16 and $2.17 on the date of grant using the Black Scholes option-pricing model with the following weighted-average assumptions: 2001--expected dividend yield 0%, risk-free interest rate of 6.0%, and an expected life of 6 years; 2000--expected dividend yield 0%, risk-free interest rate of 7.5%, and an expected life of 6 years; 1999--expected dividend yield 0%, risk-free interest rate of 7.5%, and an expected life of 6 years; expected volatility of stock over expected life of the options--35%. The Company applies APB Opinion No. 25 in accounting for its plans and, accordingly, no compensation cost has been recognized for its stock options in the financial statements. Had the Company determined compensation cost based on the fair value at the grant date for its stock options under SFAS No. 123, the Company's net income (loss) would have been reduced to the pro forma amounts indicated below:
2001 2000 1999 ----------- --------- ---------- Net Income(loss)............... As reported $ 2,747,246 5,739,204 (1,828,983) Pro forma 1,476,318 4,920,701 (2,109,357) Income(loss) applicable to common stock.................. As reported (255,626) 4,545,436 (3,078,326) Pro forma (1,526,554) 3,726,933 (3,358,700) Basic income(loss) per average common share.................. As reported (0.01) 0.46 (0.58) Pro forma (0.09) 0.38 (0.64) Diluted income(loss) per average common share.......... As reported (0.01) 0.35 (0.58) Pro forma (0.09) 0.28 (0.64)
34 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 Stock option transactions during 2001, 2000 and 1999 were as follows:
Weighted Average Weighted Average Exercise Remaining Number of Options Price Range of Exercise Price Contractual Life -------------------- ------------- -------------------------------- ----------------- Patrick Patrick Patrick Total Only Total Only Total Patrick Only Total Only ---------- -------- ----- ------- --------------- ---------------- -------- -------- Outstanding January 1, 1999................... 433,252 65,193 $5.50 to $24.00 $16.00 to $24.00 7.0 yrs. 3.4 yrs. ========== ======== Granted--1995 Stock Option................ 389,196 -- 1.37 -- Granted--1997 Director Compensation Plan..... 37,063 -- .80 -- Exercised--1995 Stock Option Plan........... (5,250) -- .75 -- Expiration/Surrender of Options............... (381,377) (29,567) 7.61 18.00 ---------- -------- Outstanding December 31, 1999................... 472,884 35,626 $0.75 to $24.00 $16.00 to $24.00 8.5 yrs. 2.9 yrs. ========== ======== Granted--1995 Stock Option Plan... 600,000 -- 4.99 -- Granted--1997 Director Compensation Plan..... 12,000 -- 4.88 -- Exercised--1995 Stock Option Plan........... (245,696) -- .78 -- Exercised--1997 Director Stock Option Plan.................. (12,500) -- .79 -- Expiration of Options.. (63,750) -- 4.35 -- ---------- -------- Outstanding December 31, 2000................... 762,938 35,626 $0.75 to $24.00 $16.00 to $24.00 8.9 yrs. 1.9 yrs. ========== ======== Granted--1995 Stock Option................ 710,000 -- 5.79 -- Granted--1997 Director Compensation Plan..... 24,000 -- 5.85 -- Exercised--1995 Stock Option Plan........... (7,500) -- 1.54 -- Expiration of Options.. (24,376) (9,376) 7.67 22.00 ---------- -------- Outstanding December 31, 2001................... 1,465,062 26,250 $0.75 to $18.00 $16.00 to $18.00 8.7 yrs. 1.4 yrs. ========== ======== Exercisable December 31, 1999................... 71,438 35,625 $9.95 19.00 Exercisable December 31, 2000................... 129,356 35,625 $7.59 19.00 Exercisable December 31, 2001................... 349,063 26,250 $5.21 17.91
35 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 NOTE K--Hedging Activities The Company enters into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of its production. The Company considers these to be hedging activities and, as such, monthly settlements on these contracts are reflected in its oil and natural gas sales. The Company's strategy, which is set by the Company's hedging committee and reviewed periodically by its Board of Directors, has been to hedge between 30% and 70% of its production. Most of the Company's hedging arrangements are in the form of costless collars, whereby a floor and a ceiling are fixed. It is the Company's belief that in most cases the benefits of the downside protection afforded by these costless collars outweigh the costs incurred by losing potential upside when commodity prices increase. The Company has adopted a formal policy with respect to hedging arrangements in accordance with accounting pronouncements. The Company does not expect its hedging policy or future hedging practice to differ materially from its historical practice--to hedge a portion of its production ranging from 30% to 70% in order to reduce the impact of short-term fluctuations in prices. The Company does not plan to engage in speculative activity not supported by anticipated production. The Company's futures contract agreements provide for separate contracts tied to the New York Mercantile Exchange ("NYMEX") light sweet crude oil and natural gas futures contracts. The Company has contracts which contain specific price ranges or "collars" that are settled monthly based on the differences between the contract price or price ranges and the average NYMEX prices applied to the related contract volumes. To the extent the average NYMEX price exceeds the contract price, the Company pays the difference, and to the extent the contract price exceeds the average NYMEX price, the Company receives the difference. As of December 31, 2001, the Company's open forward position on its outstanding natural gas hedging contracts were as follows: a) 2,000 Mmbtu per day with a no cost collar of $2.50 and $3.18 per Mmbtu through December 31, 2002; and b) 1,333 Mmbtu per day with a no cost collar of $2.75 and $3.09 per Mmbtu through December 31, 2002. The fair value of the natural gas hedging contracts in place at December 31, 2001, resulted, in an asset of $13,000. As of December 31, 2001, $8,450 (net of $4,550 in income taxes) of deferred gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. During 2001, $1,797,336 in net gains (net of $967,796 in income taxes) were recorded to accumulated other comprehensive income and $746,583 (net of $402,006 in income taxes) was reclassified from accumulated other comprehensive income to oil and gas sales as the cash flow of the hedged items was recognized. For the year ended December 31, 2001, the Company's earnings were not significantly impacted from cash flow hedging ineffectiveness arising from the natural gas hedging contracts. The Company entered into the following oil and gas hedging contracts subsequent to December 31, 2001. Natural Gas 1,200 MMBtu per day "swap" at $2.87 for April through November 2002; 1,500 MMBtu per day "swap" at $2.89 for April through November 2002; and 3,000 MMBtu per day "swap" at $3.50 for December 2002 through February 2003. 36 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 Crude Oil 200 barrels of oil per day "swap" at $21.43 for March 2002; 300 barrels of oil per day "swap" at $21.95 for April and May 2002; 150 barrels of oil per day "swap" at $24.07 for April and May 2002; and 150 barrels of oil per day "swap" at $23.22 for April and May 2002 The Company has the option to terminate its outstanding oil and natural gas hedging contracts by paying the amount of the liability. The Company does not anticipate terminating any of its open contracts. The Company is exposed to credit losses in the event of nonperformance by the counterparties to its hedging contracts. The Company anticipates, however, that counterparties will be able to fully satisfy their obligations under the contracts. The Company does not obtain collateral to support financial instruments but monitors the credit standing of the counterparties. Price fluctuations and volatile nature of markets Despite the measures taken by the Company to attempt to control price risk, the Company remains subject to price fluctuations for natural gas and oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond the Company's control. Domestic prices for oil and gas could have a material adverse effect on the Company's financial position, results of operations and quantities of reserves recoverable on an economic basis. NOTE L--Fair Value of Financial Instruments The following presents the carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2001 and 2000.
2001 2000 ---------------------- --------------------- Carrying Carrying Amount Fair Value Amount Fair Value ----------- ---------- ---------- ---------- Financial liabilities-- Long-term debt (including current maturities)........... $24,500,000 24,500,000 22,965,000 22,965,000 Production payment liability... $ 1,264,729 1,264,729 1,691,050 1,691,050 Oil and gas derivatives-- Oil............................ $ -- -- -- -- Gas............................ $ 13,000 13,000 -- (3,881,000)
The following methods and assumptions were used to estimate the fair value of each class of financial instruments: Cash and cash equivalents, accounts receivable, restricted cash, accounts payables and accrued liabilities: The carrying amounts approximate fair value because of the short maturity of those instruments. Therefore, these instruments were not presented in the table above. Long term debt and other noncurrent liabilities: The fair value is estimated using the discounted cash flow method based on the Company's borrowing rates or similar types of financing arrangements. Oil and gas derivatives: The fair value is calculated based on the discounted cash flow expected to be received or paid on the derivative utilizing future posted market prices of the underlying product. 37 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 NOTE M--Concentrations of Credit Risk and Significant Customers Due to the nature of the industry the Company sells its oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. Revenues from these sources as a percent of total revenues for the periods presented were as follows:
Year Ended December 31, ---------------- 2001 2000 1999 ---- ---- ---- Seaber Corporation of Louisiana............................ 56% 48% 37% Genesis Crude Oil, L.P..................................... 22% 27% -- Navajo Refining Company.................................... 4% 4% 7% Gulfmark Energy, Inc....................................... -- 10% -- Equiva Trading............................................. -- 8% 27% Texla Energy Management.................................... -- -- 10%
NOTE N--Commitments and Contingencies The U.S. Environmental Protection Agency ("EPA") has identified the Company as a potentially responsible party ("PRP") for the cost of clean-up of "hazardous substances" at an oil field waste disposal site in Vermilion Parish, Louisiana. The Company estimates that the remaining cost of long-term clean-up of the site will be approximately $3.5 million, with the Company's percentage of responsibility estimated to be approximately 3.05%. As of December 31, 2001, the Company had paid $321,000 in costs related to this matter and accrued $122,500 for the remaining liability. These costs have not been discounted to their present value. The EPA and the PRPs will continue to evaluate the site and revise estimates for the long-term clean-up of the site. There can be no assurance that the cost of clean-up and the Company's percentage responsibility will not be higher than currently estimated. In addition, under the federal environmental laws, the liability costs for the clean-up of the site is joint and several among all PRPs. Therefore, the ultimate cost of the clean-up to the Company could be significantly higher than the amount presently estimated or accrued for this liability. In connection with the acquisition of its Burrwood and West Delta 83 fields, the Company secured a performance bond and established an escrow account to be used for the payment of obligations associated with the plugging and abandonment of the wells, salvage and removal of platforms and related equipment, and the site restoration of the fields. Required escrowed outlays include an initial cash payment of $750,000 and monthly cash payments of $70,000 beginning June 1, 2000 and continuing until June 1, 2005. The escrow agreement was amended in the fourth quarter of 2001 to suspend monthly cash payments and cap the escrow account at its current balance of $2,039,000. In addition, as part of the purchase agreement, the Company agreed to shoot a 3-D seismic survey over the fields which was completed in the fourth quarter of this year. The cost of the seismic survey was approximately $2,500,000 of which the final $1,250,000 was paid in 2001. On February 8, 2000, the Company commenced a suit against the operator and joint owner of the Lafitte Field, alleging certain items of misconduct and violations of the letter agreement associated with the joint acquisition. The trial is currently scheduled to begin in April 2002, but it is too early to predict a likely outcome. The Company is the plaintiff in this action, and does not expect the outcome to have a significantly adverse impact on the operations or financial position of the Company. The Company is party to additional lawsuits arising in the normal course of business. The Company intends to defend these actions vigorously and believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to its financial position or results of operations. 38 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 NOTE O--Natural Gas and Crude Oil Cost Data and Results of Operations The following reflects the Company's capitalized costs related to natural gas and oil activities at December 31, 2001, and 2000:
2001 2000 ------------ ----------- Proved properties............................. $102,730,448 74,778,157 Unproved properties........................... 5,289,301 4,474,823 ------------ ----------- 108,019,749 79,252,980 Less accumulated depreciation and depletion... (32,981,657) (25,908,724) ------------ ----------- Net property and equipment.................... $ 75,038,092 53,344,256 ============ ===========
The following table reflects certain data with respect to natural gas and oil property acquisitions, exploration and development activities:
Year Ended December 31, ------------------------------------ 2001 2000 1999 ----------- ---------- ---------- Property acquisition Proved.......................... $ 175,110 1,198,631(a) 10,136,298(b) Unproved........................ 2,186,111 820,200 498,391 Exploration....................... 4,174,348 2,797,642 1,634,299 Development....................... 28,972,446 13,862,296 1,960,371 ----------- ---------- ---------- $35,508,103 18,678,769 14,229,359 =========== ========== ==========
-------- (a) Burrwood and West Delta 83 Fields acquisition (b) Primarily Lafitte Field acquisition, inclusive of liabilities assumed in connection with the purchase. NOTE P--Related Party Transactions On June 1, 2001 the Company entered into a consulting agreement with Patrick E. Malloy, III, a member of the Company's Board of Directors, under which Mr. Malloy provides the Company advice on hedging and financial matters. The contract, which expires in May 2003, pays Mr. Malloy $120,000 per year. The Company paid Mr. Malloy $70,000 in 2001. On March 12, 2002, the Company completed the sale of a thirty percent (30%) working interest in the existing production and shallow rights, and a fifteen percent (15%) working interest in the deep rights below 10,600 feet, in its Burrwood and West Delta 83 fields for $12 million to Malloy Energy Company, LLC, led by Patrick E. Malloy, III and participated in by Sheldon Appel, both members of the Company's Board of Directors. See Note C for further information regarding the sale. NOTE Q--Supplemental Oil and Gas Reserve Information (Unaudited) The supplemental oil and gas reserve information that follows is presented in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities. The schedules provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information follows concerning the schedules. 39 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 Schedules 1 and 2--Estimated Net Proved Oil and Gas Reserves Substantially all of the Company's reserve information related to crude oil, condensate, and natural gas liquids and natural gas was compiled based on evaluations performed by Coutret and Associates, Inc. All of the subject reserves are located in the continental United States. Many assumptions and judgmental decisions are required to estimate reserves. Quantities reported are considered reasonable but are subject to future revisions, some of which may be substantial, as additional information becomes available. Such additional knowledge may be gained as the result of reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, and other factors. Regulations published by the Securities and Exchange Commission define proved reserves as those volumes of crude oil, condensate, and natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes expected to be recovered as a result of making additional investments by drilling new wells on acreage offsetting productive units or recompleting existing wells. Schedule 3--Standardized Measure of Discounted Future Net Cash Flows to Proved Oil and Gas Reserves SFAS No. 69 requires calculation of future net cash flows using a ten percent annual discount factor and year end prices, costs, and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates. The calculated value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs, and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts. Crude oil and natural gas market prices at the end of each year, were used for this calculation, and averaged $17.91 per bbl and $2.51 per Mcf, respectively as of December 31, 2001; $26.10 per bbl and $10.06 per Mcf, respectively as of December 31, 2000; $25.16 per Bbl and $2.63 per Mcf, respectively as of December 31, 1999. Schedule 3 also presents a summary of the principal reasons for change in the standard measure of discounted future net cash flows for each of the three years in the period ended December 31, 2001. Schedule 1--Estimated Net Proved Gas Reserves (Mcf)
Year Ended December 31, ---------------------------------- 2001 2000 1999 ---------- ---------- ---------- Proved: Balance, beginning of period............. 29,510,679 20,849,592 28,144,310 Revisions of previous estimates.......... 6,070 708,580 (6,069,885) Purchase of minerals in place............ 1,527,172 5,955,477 1,705,822 Extensions, discoveries, and other additions............................... 6,735,556 5,546,322 -- Production............................... (3,823,227) (3,394,921) (2,930,655) Sales of minerals in place............... -- (154,371) -- ---------- ---------- ---------- Balance, end of period................... 33,956,250 29,510,679 20,849,592 ========== ========== ========== Proved developed: Beginning of period...................... 22,251,970 13,945,540 21,481,946 End of period............................ 16,692,390 22,251,970 13,945,450
40 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 Schedule 2--Estimated Net Proved Oil Reserves (Barrels)
Year Ended December 31, ------------------------------- 2001 2000 1999 --------- --------- --------- Proved: Balance, beginning of period................ 6,789,358 5,738,997 3,092,810 Revisions of previous estimates............. (5,602) 74,369 (12,989) Purchase of minerals in place............... 30,829 891,334 3,053,618 Extensions, discoveries, and other additions.................................. 2,517,515 665,911 -- Production.................................. (581,680) (571,766) (394,442) Sale of minerals in place................... -- (9,487) -- --------- --------- --------- Balance, end of period...................... 8,750,420 6,789,358 5,738,997 ========= ========= ========= Proved, developed: Beginning of period......................... 3,196,330 2,662,907 2,266,854 End of period............................... 3,399,610 3,196,330 2,662,907
The following table summarizes the Company's combined oil and gas reserve information on a Mcf equivalent basis. Estimates of oil reserves were converted using a conversion ratio of 1.0/6.0 Mcf.
Year Ended December 31, -------------------------------- 2001 2000 1999 ---------- ---------- ---------- Estimated Net Proved Reserves (Mcfe): Total Proved................................. 86,458,770 70,246,827 55,283,574 Proved Developed............................. 37,090,050 41,429,950 29,922,892
Schedule 3--Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
Year Ended December 31, --------------------------- 2001 2000 1999 -------- -------- ------- (in thousands) Future cash inflows.............................. $220,367 452,310 182,292 Production costs................................. (59,906) (55,948) (31,647) Development costs................................ (35,673) (25,201) (15,458) Future income tax expense........................ (8,972) (101,113) (21,534) -------- -------- ------- Future net cash flows............................ 115,816 270,048 113,653 10% annual discount for estimated timing of cash flows........................................... (42,694) (90,268) (35,092) -------- -------- ------- Standardized measure of discounted future net cash flows...................................... $ 73,122 179,780 78,561 ======== ======== ======= Average year end prices: Natural gas (per Mcf).......................... $ 2.51 10.06 2.63 Crude oil (per Bbl)............................ $ 17.91 26.10 25.16
41 GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 2001 The following are the principal sources of change in the standardized measure of discounted net cash flows for the years shown:
Year Ended December 31, ---------------------------- 2001 2000 1999 ---------- ------- ------- (in thousands) Net changes in prices and production costs related to future production................... $ (209,020) 91,250 33,360 Sales and transfers of oil and gas produced, net of production costs............................ (21,100) (21,100) (10,144) Net change due to revisions in quantity estimates...................................... (26) 4,112 (10,277) Net change due to extensions, discoveries and improved recovery.............................. 19,930 33,974 -- Net change due to purchase and sales of minerals-in-place.............................. 1,562 39,485 33,476 Development costs incurred during the period.... 11,767 1,127 338 Net change in income taxes...................... 64,557 (56,485) (13,845) Accretion of discount........................... 25,011 9,241 4,064 Change in production rates (timing) and other... 661 (385) 954 ---------- ------- ------- $(106,658) 101,219 37,926 ========== ======= =======
42 GOODRICH PETROLEUM CORPORATION Consolidated Quarterly Income Information (Unaudited)
First Second Third Fourth Quarter Quarter Quarter Quarter Total ---------- --------- ---------- ---------- ---------- 2001 Revenues.............. $9,405,690 7,336,497 7,748,452 5,404,140 29,894,779 Costs and Expenses.... 5,936,133 6,375,295 5,650,079 7,725,735 25,687,242 Gain (loss) on sale of assets............... 38,380 33,606 -- (45,207) 26,779 Income taxes.......... 1,227,778 348,172 734,432 (823,312) 1,487,070 Net income (Loss)..... 2,280,159 646,636 1,363,941 (1,543,490) 2,747,246 Preferred stock dividends............ 2,534,908 158,367 154,798 154,799 3,002,872 Income (Loss) applicable to common Stock................ (254,749) 488,269 1,209,143 (1,698,289) (255,626) Basic earnings (Loss) per average common share................ (.02) .03 .07 (.09) (.01) Diluted earnings (Loss) per average common share......... $ (.02) .02 .06 (.09) (.01) 2000 Revenues.............. $4,673,790 6,678,141 8,686,376 8,451,083 28,489,391 Costs and Expenses.... 4,705,059 5,261,415 6,792,255 7,953,789 24,712,518 Gain on sale of assets............... 563 273,261 33,475 -- 307,299 Income taxes.......... -- -- (1,655,032) -- (1,655,032) Net income (Loss)..... (30,706) 1,689,987 3,582,628 497,294 5,739,204 Preferred stock dividends............ 307,607 295,945 295,562 294,654 1,193,766 Income (Loss) applicable to common Stock................ (338,313) 1,394,042 3,287,066 202,640 4,545,436 Basic earnings (Loss) per average common share................ (.05) .16 .31 .02 .46 Diluted income (Loss) per average common share................ (.05) .12 .23 .01 .35
The fourth quarter of 2001 and 2000 amount includes impairment of oil and gas properties of $1,801,000 and $1,835,000, respectively. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None 43 PART III Item 10. Directors and Executive Officers of the Registrant. * Item 11. Executive Compensation. * Item 12. Security Ownership of Certain Beneficial Owners and Management. * Item 13. Certain Relationships and Related Transactions. * -------- * Reference is made to information under the captions "Election of Directors", "Executive Compensation", "Security Ownership of Certain Beneficial Owners and Management", and "Certain Relationships and Related Transactions", in the Company's Proxy Statement for the 2002 Annual Meeting of Stockholders. 44 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. (a) 1. Financial Statements The following consolidated financial statements of Goodrich Petroleum Corporation are included in Part II, Item 8:
Page ----- Independent Auditors' Report............................................ 20 Consolidated Balance Sheets--December 31, 2001 and 2000................. 21 Consolidated Statements of Operations--Years ended December 31, 2001, 2000 and 1999.......................................................... 22 Consolidated Statements of Cash Flows--Years ended December 31, 2001, 2000 and 1999.......................................................... 23 Consolidated Statements of Stockholders' Equity and Comprehensive Income--Years ended December 31, 2001, 2000 and 1999................... 24 Notes to Consolidated Financial Statements--Year ended December 31, 2001................................................................... 25-42 Consolidated Quarterly Income Information (Unaudited)................... 43
2. Financial Statement Schedules The schedules for which provision is made in Regulation S-X are not required under the instructions contained therein, are inapplicable, or the information is included in the footnotes to the financial statements. (b) Reports on Form 8-K None (c) Exhibits 3(I).1 Amended and Restated Certificate of Incorporation of the Company dated August 15, 1995, and filed with the Secretary of State of the State of Delaware on August 15, 1995 (Incorporated by reference to Exhibit 3.1 of the Company's Quarterly Report filed on Form 10-Q for the three months ended September 30, 1995). 3(I).2 Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation dated March 12, 1998. (Incorporated by reference to Exhibit 3(i)2 of the Company's Annual Report on Form 10- K for the year ended December 31, 1998). 3(ii).1 Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 3.2 of the Company's Quarterly Report filed on Form 10-Q for the three months ended September 30, 1995). 4.1 Specimen Common Stock Certificate. (Incorporated by reference to Exhibit 4.6 of the Company's Registration Statement filed February 20, 1996 on Form S-8 (File No. 33-01077)). 4.2 Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated November 9, 2001. Filed herewith. 10.1 Goodrich Petroleum Corporation 1995 Stock Option Plan (Incorporated by reference to Exhibit 10.21 to the Company's Registration Statement filed June 13, 1995 on Form S-4 (File No. 33-58631)). 10.2 Patrick Petroleum Company 1993 Stock Option Plan (Incorporated by reference to Exhibit 10.11 to the Company's Registration Statement filed June 13, 1995 on Form S-4 (File No. 33-58631)). 10.3 Consulting Services Agreement between Patrick E Malloy and Goodrich Petroleum Corporation dated June 1, 2001. Filed herewith.
45 10.4 Goodrich Petroleum Corporation 1997 Director Compensation Plan (Incorporated by reference to the May 20, 1998 Proxy). 10.5 Form of Subscription Agreement dated September 27, 1999 (Incorporated by reference to Exhibit 4.1 of the Company's Form 8-K filing dated September 23, 1999). 10.6 Registration Rights Agreement (2000 Private Placement) (Incorporated by reference to Exhibit 10.11 of the Company's Annual Report on Form 10-K for the year ended December 31, 1999). 10.7 Purchase and Sale Agreement between Malloy Energy Company, LLC, and Goodrich Petroleum Company, LLC, dated March 12, 2002. Filed herewith. 21 Subsidiaries of the Registrant Goodrich Petroleum Corporation, Inc. of Louisiana--incorporated in the state of Nevada Goodrich Petroleum Company LLC--incorporated in state of Louisiana Goodrich Petroleum Lafitte, LLC--incorporated in state of Louisiana Subsidiaries of Goodrich Petroleum Company of Louisiana Drilling & Workover Company, Inc.--incorporated in state of Louisiana LECE, Inc.--incorporated in the state of Texas National Marketing Company--incorporated in state of Delaware 23 Consent of KPMG LLP.
46 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. GOODRICH PETROLEUM CORPORATION (Registrant) /s/ Walter G. Goodrich By __________________________________ Date: March 28, 2002 Walter G. Goodrich President, Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: Date: March 28, 2002
Signature Title --------- ----- /s/ Walter G. Goodrich Chief Executive Officer and Director ______________________________________ (Principal Executive Officer) Walter G. Goodrich /s/ Roland L. Frautschi Senior Vice President, Treasurer ______________________________________ Roland L. Frautschi /s/ Lonnie J. Shaw Vice President (Principal Accounting ______________________________________ Officer) Lonnie J. Shaw /s/ Sheldon Appel Director ______________________________________ Sheldon Appel /s/ Henry Goodrich Director ______________________________________ Henry Goodrich /s/ Arthur A. Seeligson Director ______________________________________ Arthur A. Seeligson /s/ Donald M. Campbell Director ______________________________________ Donald M. Campbell /s/ Mike McGovern Director ______________________________________ Mike McGovern /s/ Michael J. Perdue Director ______________________________________ Michael J. Perdue /s/ Patrick E. Malloy, III Director ______________________________________ Patrick E. Malloy, III
47