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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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
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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.
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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
========= ========== ==== ======= =======
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(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
===== ===== ===== ===== ====== =====
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(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
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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
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(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