Back to GetFilings.com
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE
ACT OF 1934 (Fee Required)
For Fiscal Year Ended December 31, 2000
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
Houston, Texas 77002
(Address of principal executive (Zip Code)
offices)
Registrant's telephone number, including area code is (713) 780-9494
Name of each exchange on
Title of each class which registered
------------------- ------------------------
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.20 par value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Series A Preferred Stock, $1.00 par NASDAQ Small Cap
value
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 21, 2001 there were 17,508,430 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 21, 2001 was
approximately $109,428,000 based on a closing price of $6.25 per share on the
New York Stock Exchange on such date.
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
PART I
Items 1 and 2. Business and Properties.
General
Goodrich Petroleum Corporation and subsidiaries ("Goodrich" or "the
Company") is an independent oil and gas company engaged in the exploration,
exploitation development and production of oil and natural gas properties in
the transition zone of south Louisiana and in north Louisiana, the Gulf Coast
of Texas and east Texas. The Company owns working and overriding royalty
interests in 130 active oil and gas wells located in 32 fields in six states.
At December 31, 2000 Goodrich had estimated proved reserves of approximately
6,789,000 barrels of oil and condensate and 29.5 Bcf of natural gas, or an
aggregate of 70.2 Bcfe with a pre-tax present value of future net revenues,
discounted at 10%, of $250.1 million and an after-tax Standardized Measure
value of $179.8 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 12, 2001 the Company had 15 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 one-half of the state of Louisiana, which is
one of the world's 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/West Delta Block 83 Fields. The Burrwood/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 48.8 million barrels of oil and 140 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 20 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.
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 263 million barrels of oil and 318 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 32 active
producing wells in the field.
In September 1999, the Company acquired an approximate 49% interest in the
Lafitte Field with regards 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%. Additionally, the Lafitte Field
has over 30 defined productive reservoirs, a large cumulative production
history of 1,890 Bcfe, a large acreage position of over 8,000 acres and then
current production of approximately 4,500 Mcfe per day. The Company has
drilled one new well and performed five workovers and recompletions,
increasing production from 4,500 Mcfe per day to approximately 9,000 Mcfe per
day currently.
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 seven producing wells, five 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 424 Bcf of natural gas and 3.5 million
barrels of oil from multiple Miocene aged sands ranging from 4,000 to 15,200
feet.
Other major operators in the area are Fina Oil and Chemical Company, Texaco
Exploration and Producing, Inc. and Bellwether Exploration Company.
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
352 Bcf of gas and 746,000 barrels of condensate. All of the field production
to date has come from normal pressured reservoirs. The Company is the operator
of five 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. 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,
these fields have produced in excess of 55 billion cubic feet of gas and 6.58
million barrels of oil and condensate.
Goodrich acquired its working 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 Humble Oil
and Refining Company ("Exxon") in 1949, with the field extended to the south
by Pan American ("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 833 billion
cubic feet of gas and 20 million barrels of oil and condensate.
3
Goodrich acquired its average 20% working interest in the field through a
farmout from MW Petroleum ("Apache") in July 1996 and a separate farmout from
Exxon. The Company controls approximately 1,079 acres in the field.
Ada Field. The Ada Field was discovered by Hope Producing Company in 1945.
The field is located in Bienville Parish, in north Louisiana. Geologically,
the field lies between two salt domes exhibiting a four-way anticline with two
main horst blocks, a main graben block, and several compensating faults. The
field has produced from numerous lower cretaceous sands and lime facies, with
the sands being predominately lenticular in deposition. The producing interval
for the field ranges from 4,500 to 10,000 feet, with the reservoir being
primarily a pressure depletion mechanism. Ada Field has produced over 657 Bcf
of natural gas and 5.2 million barrels of oil.
Goodrich owns an approximate 43% working interest in the six producing
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 Lafourche Parish, (v) Mosquito Bay Field, located in
Terrebonne Parish, (vi) South Pecan Lake Field located in Cameron Parish and
(vii) Kings Ridge Field, located in Lafourche 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 the 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,
discovered in 1953 by Sun Oil. Currently there are four producing wells in the
field with Goodrich, 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 514,073 barrels 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, (v) Mott Slough, located in Wharton County
and (vi) Cantillo Field, located in Nueces County.
Australia
Goodrich has interest in two exploration permits in the Carnarvon Basin of
Western Australia.
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.
4
EP-395. Goodrich Petroleum acquired a 20% 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.
Interpretation of this data has confirmed two separate prospects: West Boyd
and Lindsay. During 1999, Goodrich Petroleum farmed out its working interest
for a 6.9% carried interest through the drilling of the Boyd #1 well, which
was a dry hole. Currently, the partners are evaluating information from the
dry hole.
EP-397. This Permit is 160 square kilometers and 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, 2000 and 1999, 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, 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
========= ========== ==== ======= =======
December 31, 1999
Proved Developed 2,662,907 13,945,450 29.9 $ 50.50
Proved Undeveloped..... 3,076,090 6,904,142 25.4 41.91
--------- ---------- ---- -------
Total Proved........ 5,738,997 20,849,592 55.3 $ 92.41 $ 78.56
========= ========== ==== ======= =======
- --------
(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, 2000 used in such estimates
averaged $10.06 per Mcf of natural gas and $26.10 per Bbl of crude
oil/condensate.
5
Productive Wells
The following table set forth the number of active well bores in which the
Company maintains ownership interests as of December 31, 2000:
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............... 48.00 29.61 41.00 18.76 89.00 48.37
Michigan................ 2.00 0.26 5.00 0.05 7.00 0.31
New Mexico.............. -- -- 1.00 0.03 1.00 0.03
Texas................... 23.00 11.56 5.00 0.74 28.00 12.30
Wyoming................. 1.00 0.17 -- -- 1.00 0.17
----- ----- ----- ----- ------ -----
Total Productive
Wells................ 74.00 41.60 56.00 21.67 130.00 63.27
===== ===== ===== ===== ====== =====
- --------
(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, 2000.
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 14,780
Michigan................................................. 1,920 19
Texas.................................................... 5,358 1,912
Wyoming.................................................. 80 13
Undeveloped acreage
Offshore Australia....................................... 98,841 17,306
Louisiana................................................ 1,280 924
Michigan................................................. 640 50
Texas.................................................... 1,000 552
------- ------
Total.................................................. 134,486 36,124
======= ======
Undeveloped acreage is considered to be those lease acres on which wells
have not been drilled or completed to a point 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 by
producing natural gas or oil wells.
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 activity 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,
-------------------------------
2000 1999 1998
---------- --------- ----------
Gross Net Gross Net Gross Net
----- ---- ----- --- ----- ----
Development Wells:
Productive.............................. 3.00 1.77 1.00 .49 6.00 2.77
Non-Productive.......................... 1.00 .49 -- -- 2.00 1.47
---- ---- ---- --- ----- ----
Total................................. 4.00 2.26 1.00 .49 8.00 4.24
==== ==== ==== === ===== ====
Exploratory Wells:
Productive.............................. 2.00 .93 -- -- 7.00 1.49
Non-Productive.......................... 2.00 1.00 1.00 .12 8.00 2.87
---- ---- ---- --- ----- ----
Total................................. 4.00 1.93 1.00 .12 15.00 4.36
==== ==== ==== === ===== ====
Total Wells:
Productive.............................. 5.00 2.70 1.00 .49 13.00 4.26
Non-Productive.......................... 3.00 1.49 1.00 .12 9.00 4.34
---- ---- ---- --- ----- ----
Total................................. 8.00 4.19 2.00 .61 22.00 8.60
==== ==== ==== === ===== ====
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, 2000.
2000 1999 1998
--------- --------- ---------
Net Production:
Natural gas (Mcf)........................ 3,394,921 2,930,655 2,782,825
Oil (Bbls)............................... 571,766 394,442 316,768
Natural gas equivalents (Mcfe) (1)....... 6,825,517 5,297,307 4,683,433
Average Net Daily Production:
Natural gas (Mcf)........................ 9,301 8,029 7,624
Oil (Bbls)............................... 1,566 1,081 868
Natural gas equivalents (Mcfe) (1)....... 18,697 14,515 12,832
Average Sales Price Per Unit (2):
Natural gas (per Mcf).................... $ 3.95 2.41 2.18
Oil (per Bbl)............................ $ 25.55 16.88 11.88
Other Data:
Lease operating expense (per Mcfe)....... $ 0.69 0.45 0.37
Production taxes (per Mcfe).............. $ 0.32 0.23 0.24
- --------
(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 year 2000 results. Hedging activity for 1999 did not have a
significant effect on these results.
7
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, that NGV 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,
----------------
2000 1999 1998
---- ---- ----
Seaber Corporation of Louisiana............................ 48% 37% 47%
Genesis Crude Oil, L.P..................................... 27% 27% 12%
Gulfmark Energy, Inc....................................... 10% 10% --
Equiva Trading............................................. 8% 27% 12%
Texla Energy Management.................................... -- 10% --
Navajo Refining Company.................................... 4% 7% 11%
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 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.
8
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, 2000, 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 in its early stages 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 22, 2001 the number of holders of record of the Company's common
stock without determination of the number of individual participants in
security position was 3,063 with 17,508,430 shares outstanding. High and low
sales prices for the Company's common stock for each quarter during the
calendar years 2000 and 1999 are as follows:
2000 1999
---------- ---------
Quarter Ended High Low High Low
------------- ----- ---- ---- ----
March 31............................................. $6.25 2.63 1.50 .69
June 30.............................................. $5.56 4.25 1.88 .94
September 30......................................... $6.25 4.50 2.69 .94
December 31.......................................... $6.50 5.00 3.06 2.19
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, 2000, 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,
-----------------------------------------------------------
2000 1999 1998 1997 1996
----------- ---------- ---------- ---------- ----------
Revenues................ $28,489,391 14,020,574 10,591,873 12,901,361 9,769,383
Depletion, Depreciation
and Amortization....... 5,953,641 4,743,608 4,094,447 4,862,754 3,788,292
Exploration............. 2,813,332 1,656,158 6,010,425 3,205,730 1,149,240
Interest Expense........ 4,390,331 2,810,576 1,909,849 1,416,675 828,394
Total Costs and
Expenses............... 24,712,518 15,330,062 18,311,421 14,978,629 9,476,366
Gain (Loss) on sale of
assets................. 307,299 (519,495) 4,206 688,304 88,428
Income taxes............ (1,655,032) -- -- -- --
Net Income(Loss)........ 5,739,204 (1,828,983) (7,715,342) (1,388,964) 381,445
Preferred Stock
Dividends.............. 1,193,768 1,249,343 1,255,638 1,205,210 644,800
Income(Loss) Applicable
to Common Stock........ 4,545,436 (3,078,326) (8,970,980) (2,594,174) (263,355)
Basic Income(Loss) Per
Average Common Share... .46 (.58) (1.71) (.50) (.05)
Diluted Income(Loss) Per
Average Common Share... $ .35 (.58) (1.71) (.50) (.05)
Average Common Shares
Outstanding Basic...... 9,903,248 5,288,011 5,243,105 5,229,307 5,225,564
Average Common Shares
Outstanding Diluted.... 13,116,641 5,288,011 5,243,105 5,229,307 5,225,564
Year Ended December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
----------- ---------- ---------- ---------- ----------
Selected Balance Sheet
Data:
Total Assets.......... $65,343,594 56,258,552 44,036,588 37,537,918 22,398,984
Total Long Term
Debt(a).............. 22,965,000 36,953,117 29,500,000 18,500,000 10,000,000
Stockholders'
Equity............... $32,605,216 6,411,044 4,959,388 14,332,676 9,135,200
- --------
(a) Includes current maturities
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, 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 gas sales. Oil and
gas sales were $28,014,000 for the twelve months ended 2000, compared to
$13,735,000, or
11
$14,279,000 higher due to higher oil and gas prices and higher oil and gas
production volumes associated with the Burrwood/West Delta 83 Field
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 and production taxes were $6,914,000 for 2000
compared to $3,592,000 for 1999, or $3,322,000 higher, due primarily to higher
oil and gas sales, additional costs associated with the Company's
Burrwood/West Delta 83 Field and Lafitte Field acquisitions, and higher base
operating costs associated with certain mature oil and gas fields. 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 a 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.
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, 2000, the Company was current as to
dividends on both series of preferred stock. During 1999, no preferred stock
dividends were declared, however, dividends on the Company Series A and Series
B preferred stock did accumulate to an amount equal to $1,249,000. The Company
also accrued non-cash dividends on its Goodrich--Louisiana Series A Preferred
units of $38,000 and $73,000 that is reflected as preferred dividends of
subsidiary in the statement of operations for the 2000 and 1999 periods
respectively.
Year ended December 31, 1999 versus year ended December 31, 1998--Total
revenues in 1999 amounted to $14,021,000 and were $3,429,000 (32%) higher than
total revenues in 1998 due primarily to higher oil and gas revenues. Oil and
gas sales were $3,898,000 higher due to higher oil and gas prices, higher oil
and gas production volumes and additional oil volumes associated with the
Lafitte Field acquisition in September 1999.
12
The following table reflects the production volumes and pricing information
for the periods presented:
1999 1998
------------------------ ------------------------
Production Average Price Production Average Price
---------- ------------- ---------- -------------
Gas (Mcf)............... 2,930,655 $ 2.41 2,782,825 $ 2.18
Oil (Bbls).............. 394,442 $16.88 316,768 $11.88
Lease operating expense and production taxes were $3,592,000 for 1999
compared to $2,822,000 for 1998, or $770,000 higher substantially due to costs
related to the Lafitte Field properties. Depletion, depreciation and
amortization was $4,744,000 in 1999 versus $4,094,000 in 1998, or $650,000
higher due to increased oil and gas production including volumes associated
with the Lafitte Field properties.
The Company incurred $1,656,000 of exploration expense in 1999 compared to
$6,010,000 in 1998. Included in the 1999 exploration expense is $120,000 of
costs related to dry holes during the period versus $3,684,000 of such costs
related to dry holes in 1998.
The Company recorded an impairment in the recorded value of certain oil and
gas properties in 1999 in the amount of $465,000 due to the complete depletion
of the reserves on three one well non-core fields. This compares to an
impairment of $1,076,000 recorded in 1998.
Interest expense was $2,811,000 in 1999 compared to $1,910,000 (47% higher)
in 1998 due to the Company having higher average debt outstanding as a result
of the September 23, 1999 private placement and a higher effective interest
rate in 1999 compared to 1998. The 1999 interest expense includes financing
costs and non-cash expense due to the amortization of the valuation of
detachable common stock purchase warrants issued in connection with the 1999
private placement.
General and administrative expenses amounted to $1,990,000 for 1999 versus
$2,399,000 in 1998.
During 1999, no preferred stock dividends were declared, however, dividends
on the Company Series A and Series B preferred stock accumulated to an amount
equal to $1,249,000 for 1999. The preferred stock dividends are cumulative and
the Company was prohibited from paying dividends on its Series A and B
preferred stock by its bank loan agreement. The Company also accrued non-cash
dividends on its Goodrich--Louisiana Series A Preferred units of $73,000 that
is reflected as preferred dividends of subsidiary in the statement of
operations for 1999.
Liquidity and Capital Resources
Net cash provided by operating activities was $12,641,000 in 2000 compared
to $1,065,000 in 1999 and $3,740,000 in 1998. The Company's net cash provided
by operations increased in 2000 due primarily to the Company earning
approximately $5,700,000 in net income. The Company's net cash flow provided
by operating activities decreased in 1999 from 1998 due to the use of part of
the proceeds from the 1999 private placement of securities to pay down
accounts payable by $5,052,000. 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 $15,881,000 in 2000
compared to $6,407,000 in 1999 and $14,182,000 in 1998. The net cash used in
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 used in investing
activities for year ended December 31, 1998 is composed almost entirely of
cash paid for exploration and drilling capital expenditures of $14,102,000.
13
Net cash provided by financing activities was $842,000 in 2000 compared to
$11,176,000 in 1999 and $9,744,000 in 1998. 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 $4,126,000. 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 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. The 1998 amount includes the borrowing of $11,500,000 by the
Company under its line of credit offset by paydowns during the year of
$500,000. Preferred stock dividends in 1998 amounted to $1,256,000 (Series A
and Series B).
Conversion of Private Placement Securities
On September 23, 1999, the Company and two of its subsidiaries, Goodrich
Petroleum Company, L.L.C. ("Goodrich-Louisiana") and Goodrich Petroleum
Company-Lafitte, L.L.C. ("Goodrich-Lafitte"), completed a private placement of
$15 million of convertible securities consisting of $12,000,000 in convertible
notes and $3,000,000 in preferred units.
On February 17, 2000, all of the holders of the 300,000 outstanding
preferred units of Goodrich Petroleum Company, L.L.C.'s Series A Preferred
Units converted their units into approximately 1,550,000 shares of the
Company's common stock. The conversion of the preferred units 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 increased stockholders' equity by approximately $10,130,000,
inclusive of approximately $1,033,000 in remaining deferred loan financing
costs, which were eliminated.
The Company arranged a stand-by underwriting to finance the purchase of the
convertible notes from noteholders that elected not to convert their notes
into the Company's common stock. Notes purchased by the underwriters were
subsequently converted into shares of the Company's common stock on the same
terms as the notes originally tendered for conversion. Two of the underwriters
are, or are affiliates of, members of the Company's board. Each underwriter
received 15,000 shares of the Company's common stock as compensation for their
services. In addition, one of the underwriters received an additional 15,000
shares of common stock for their role as agent for the noteholders. The
Company issued 60,000 shares of common stock as consideration for underwriting
and noteholder agent assistance relative to the conversion of the notes, which
resulted in a charge to interest expense of $280,500.
Burrwood/West Delta 83 Field Acquisition
As described in Note F to the Consolidated Financial Statements, on March
2, 2000, the Company completed its acquisition of working interests in the
Burrwood and West Delta 83 Fields, comprising approximately 8,600 acres, in
Plaquemines Parish, Louisiana for a net purchase price of $1,198,000 and the
assumption of the fields plugging and abandonment obligation estimated at
$4,500,000. The Company acquired an approximate 95% working interest of all
rights from the surface to approximately 10,600 feet and an approximate 47.5%
working interest in the deep rights below 10,600 feet. In connection with the
acquisition, 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. In addition,
as part of the purchase agreement, the Company has agreed to shoot a 3-D
seismic survey over the fields by June 30, 2001 or remit payment to the seller
in the amount of $3,500,000. The 3-D seismic
14
survey began in July 2000 and the Company anticipates that the seismic survey
will be completed and processed on or before June 30, 2001. The cost of the
seismic survey is expected to be approximately $2,500,000 and the Company has
incurred seismic study costs of approximately $1,250,000 through December 31,
2000.
Financing Transactions
In October 2000, the Company completed the sale of 1,000,000 shares of its
common stock for gross proceeds of $5.0 million.
In September 2000, the Company paid an aggregate of approximately $1.8
million of dividend arrearages and $296,000 of regular quarterly dividends on
its Series A and Series B preferred stock. These payments brought the Company
current on its dividend payments on both of its series of preferred stock.
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
Restructuring of Credit Agreement
On January 31, 2001, the Company amended its Credit Agreement with Compass
Bank. The amended credit facility provides for an initial borrowing base,
subject to semi-annual redeterminations each April and October based on a
review of the Company's reserves, of $30,000,000. For the period from February
1, 2001 through February 28, 2001, the borrowing base will be $23,800,000. The
borrowing base will then reduce by $1,550,000 each calendar month thereafter
through and including the month of April, 2001. For each calendar month
thereafter, the redetermined borrowing base shall be reduced by $550,000.
Interest on the credit facility will accrue at a rate calculated at the option
of the Company as either the Compass Bank prime rate, or LIBOR plus 1.75%--
2.00% depending on borrowing base utilization. Interest is payable monthly.
The credit facility will mature on April 1, 2003. The credit facility requires
that the Company pay a commitment fee each quarter based on the Company's
borrowing base utilization. The fee is equal to 0.375% to 0.50% per annum
based on the 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 and restricts the Company from declaring or paying
dividends on its common stock without the lenders consent. Substantially all
the Company's assets are pledged to secure the credit facility.
Additionally, the Company has a $1 million letter of credit facility in
place with Compass Bank that expires in April 2003. There were no outstanding
letters of credit as of December 31, 2000.
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
15
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 will be
reflected as a preferred stock dividend to arrive at net income applicable to
common stock and will not have an affect on stockholders' equity.
Stock Listing
The Company is currently below certain of the New York Stock Exchange's
("NYSE's") continued listing critera. The Company has been trading pursuant to
an approved business plan to return to compliance within a 12-month time
frame. The business plan covered the period through August 2000. The NYSE has
determined to forbear from initiating any formal removal action in view of the
fact that the Company has successfully met one half of the conjunction test
requiring that the Company return to $50 million each in stockholders' equity
and market capitalization and has made substantial progress on meeting the
other component of the test. The Company's market capitalization at March 19,
2001 was in excess of $100 million. This extension of the business plan has
been made in light of evidence that the Company has provided that shows the
Company successfully meeting the $50 million equity requirement, though in a
delayed time frame.
Accounting Matters
The Financial Accounting Standards Board FASB issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, in June 1997.
This statement established accounting and reporting standards for derivative
instruments and hedging activities. In June 2000, the FASB issued SFAS No.
138, which amended certain provisions of SFAS No. 133. Effective January 1,
2001, the Company must recognize the fair value of all derivative instruments
as either assets or liabilities in its Consolidated Balance Sheet. A
derivative instrument meeting certain conditions may be designated as a hedge
of a specific exposure; accounting for changes in a derivative's fair value
will depend on the intended use of the derivative and the resulting
designation. Changes in a derivative fair value for a qualifying hedge of
forecasted transactions will be deferred and recorded as a component of
accumulated comprehensive income until the forecasted transaction occurs, at
which time the derivative value will be recognized in earnings. Transition
adjustments resulting from adopting this statement will be reported in net
income or other comprehensive income, as appropriate, as the cumulative effect
of a change in accounting principal. As described under the heading
"Quantitative and Qualitative Disclosures About Market Risk" below, the
Company makes use of derivative instruments to hedge specific market risks.
The Company has determined that the adoption of SFAS No. 133 will decrease
other comprehensive income by approximately $2,523,000 and the overall affect
on net income from adoption of this standard will not be significant.
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, 2000, a hypothetical 2%
increase in the interest rates would increase interest expense by
approximately $459,000.
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
16
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--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 will not 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 contacts. 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 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, 2000, the Company's open forward position on its
outstanding crude oil was as follows:
(a) 500 barrels of oil per day with a no cost "collar" of $20.00 and
$28.40 per barrel through December 2001; and
(b) 300 barrels of oil per day with a no cost "collar" of $23.00 and
$29.55 per barrel through December 2001;
The fair value of the crude oil hedging contracts in place at December 31,
2000, resulted in a liability of $20,000.
As of December 31, 2000, the Company's natural gas hedging contracts were
as follows:
(a) 5000 Mmbtu per day with a no cost collar of $3.05 and $4.45 per
Mmbtu through December 31, 2001;
(b) 5000 Mcf per day "swap" at $7.75 per Mcf for January 2001;
(c) 5000 Mcf per day "swap" at $7.42 per Mcf for February 2001; and
(d) 5000 Mcf per day "swap" at $7.60 per Mcf for March 2001.
The fair value of the natural gas hedging contracts in place at December
31, 2000, would result, if not accounted for as hedges, in a liability of
$3,881,000.
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 contacts.
For the fourth quarter of 1999, the Company had 305,000 Mcf (44%) of the
Company's gas hedged. The Company received $2.41 per Mcf of gas during this
period versus an average NYMEX gas price of $2.40. For the first quarter of
2000, the Company had 72,800 barrels (66%) of its oil hedged and 455,000 Mcf
(64%) of its gas hedged. The Company received $24.18 per barrel of oil and
$2.58 per Mcf during this period versus an average NYMEX price of $30.21 per
barrel of oil and $2.57 per Mcf. For the second quarter of 2000, the Company
had 85,000 barrels (56%) of its oil hedged and 455,000 Mcf (59%) or its gas
hedged. The Company received $24.12 per barrel of oil and $3.74 per Mcf during
this period versus an average NYMEX price of $28.64 per barrel of oil and
$3.88 per Mcf. For the third quarter of 2000, the Company had 92,000 barrels
(53%) of its oil hedged and 460,000 Mcf (48%) of its gas hedged. The Company
received $26.33 per barrel of oil and $4.27 per Mcf during this period versus
an average NYMEX price of $31.46 per barrel of oil and $4.29 per Mcf. For the
fourth quarter of 2000, the Company had 92,000 barrels (68%) of its oil hedged
and 753,000 Mcf (80%) of its gas hedged. The Company received $27.24 per
barrel of oil and $4.94 per Mcf during this period versus an average NYMEX
price of $31.24 per barrel of oil and $5.57 per Mcf.
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
17
natural gas prices can change dramatically primarily as a result of the
balance between supply and demand. The trend since 1998 has been upward, with
an average natural gas price received for the year ending December 31, 2000,
of $4.91 per Mcf, up from $2.94 per Mcf in 1999 and $2.18 per Mcf in 1998. The
Company's average oil price received for the year ended December 31, 2000, was
$27.24, up from an average price received of $16.88 in 1999 and $11.88 in
1998. 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.
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.
18
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, 2000 and 1999, and
the related consolidated statements of operations, stockholders' equity and
comprehensive income and cash flows for each of the years in the three year
period ended December 31, 2000. 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, 2000 and 1999, and
the results of their operations and their cash flows for each of the years in
the three year period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States of America.
KPMG LLP
Shreveport, Louisiana
March 16, 2001
19
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, December 31,
2000 1999
------------ ------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents......................... $ 3,531,763 5,929,229
Accounts receivable
Trade and other, net of allowance............... 241,659 669,741
Accrued oil and gas revenue..................... 4,553,863 1,937,711
Prepaid insurance and other....................... 238,647 53,806
------------ -----------
Total current assets............................ 8,565,932 8,590,487
------------ -----------
PROPERTY AND EQUIPMENT
Oil and gas properties............................ 79,252,980 65,401,168
Furniture, fixtures and equipment................. 240,150 213,524
------------ -----------
79,493,130 65,614,692
Less accumulated depletion, depreciation and
amortization..................................... (26,044,257) (19,566,835)
------------ -----------
Net property and equipment...................... 53,448,873 46,047,857
------------ -----------
OTHER ASSETS
Restricted Cash................................... 1,240,000 --
Deferred taxes.................................... 1,694,675 --
Other............................................. 394,114 1,620,208
------------ -----------
Total Other Assets.............................. 3,328,789 1,620,208
------------ -----------
TOTAL ASSETS.................................... $ 65,343,594 56,258,552
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current portion of long term debt................. $ -- 3,600,000
Accounts payable.................................. 3,043,477 2,711,746
Accrued liabilities............................... 1,231,965 1,326,995
Current portion of other noncurrent liabilities... 820,454 1,182,306
------------ -----------
Total current liabilities....................... 5,095,896 8,821,047
------------ -----------
LONG TERM DEBT...................................... 22,965,000 33,353,117
OTHER NONCURRENT LIABILITIES
Production payment payable........................ 969,870 1,630,784
Accrued abandonment costs......................... 3,707,612 3,108,281
Accrued interest on long term debt................ -- 251,154
------------ -----------
Total liabilities............................... 32,738,378 47,164,383
------------ -----------
PREFERRED STOCKHOLDERS EQUITY IN A SUBSIDIARY
COMPANY............................................ -- 2,683,125
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 796,318 shares (liquidating preference $10
per share, aggregating to $7,919,680)........... 791,968 796,318
Series B convertible preferred stock, par value
$1.00 per share; issued and outstanding 660,839
and 665,759 shares (liquidation preference $10
per share, aggregating to $6,608,390)........... 660,839 665,759
Common stock, par value $0.20 per share;
authorized 25,000,000 shares;issued and
outstanding 13,318,920 and 5,417,171 shares...... 2,663,784 1,083,434
Additional paid-in capital........................ 39,348,013 18,156,114
Accumulated deficit............................... (10,859,388) (14,290,581)
------------ -----------
Total stockholders' equity...................... 32,605,216 6,411,044
------------ -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.... $ 65,343,594 56,258,552
============ ===========
See notes to consolidated financial statements.
20
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31,
-----------------------------------
2000 1999 1998
----------- ---------- ----------
REVENUES
Oil and gas sales....................... $28,014,245 13,734,691 9,836,863
Other................................... 475,146 285,883 755,010
----------- ---------- ----------
Total revenues........................ 28,489,391 14,020,574 10,591,873
----------- ---------- ----------
COSTS AND EXPENSES
Lease operating expense and production
taxes.................................. 6,913,968 3,591,427 2,821,515
Depletion, depreciation and
amortization........................... 5,953,641 4,743,608 4,094,447
Exploration............................. 2,813,332 1,656,158 6,010,425
Impairment of oil and gas properties.... 1,834,654 465,465 1,075,853
Interest expense........................ 4,390,331 2,810,576 1,909,849
General and administrative.............. 2,518,228 1,989,703 2,399,332
Other................................... 250,000 -- --
Preferred dividend requirements of
subsidiary............................. 38,364 73,125 --
----------- ---------- ----------
Total costs and expenses.............. 24,712,518 15,330,062 18,311,421
----------- ---------- ----------
GAIN (LOSS) ON SALES OF ASSETS............ 307,299 (519,495) 4,206
----------- ---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES......... 4,084,172 (1,828,983) (7,715,342)
Income Taxes............................ (1,655,032) -- --
----------- ---------- ----------
NET INCOME (LOSS)......................... 5,739,204 (1,828,983) (7,715,342)
Preferred stock dividends............... 1,193,768 1,249,343 1,255,638
----------- ---------- ----------
INCOME (LOSS) APPLICABLE TO COMMON STOCK.. 4,545,436 (3,078,326) (8,970,980)
=========== ========== ==========
BASIC INCOME (LOSS) PER AVERAGE COMMON
SHARE.................................... $ .46 (.58) (1.71)
=========== ========== ==========
DILUTED INCOME (LOSS) PER AVERAGE COMMON
SHARE.................................... $ .35 (.58) (1.71)
=========== ========== ==========
AVERAGE COMMON SHARES OUTSTANDING BASIC... 9,903,248 5,288,011 5,243,105
AVERAGE COMMON SHARES OUTSTANDING--
DILUTED.................................. 13,116,641 5,288,011 5,243,105
See notes to consolidated financial statements.
21
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
---------------------------------------
2000 1999 1998
------------ ----------- ------------
OPERATING ACTIVITIES
Net income(loss)..................... $ 5,739,204 (1,828,983) (7,715,342)
Adjustments to reconcile net
income(loss) to net cash provided by
operating activities:
Depletion, depreciation and
amortization........................ 5,953,641 4,743,607 4,094,447
Amortization of leasehold costs...... 1,007,636 1,103,219 1,016,649
Other................................ 250,000 -- --
Amortization of deferred debt
financing costs..................... 331,042 109,088 --
Deferred tax benefit................. (1,655,032) -- --
Impairment of oil and gas
properties.......................... 1,834,654 465,465 1,075,853
Accrued interest and other charges
on private placement borrowings..... 973,631 -- --
Amortization of debt discount........ 357,016 142,500 --
Amortization of production payment
discount............................ 230,649 251,154 --
Preferred dividends of subsidiary.... 38,364 73,125 --
(Gain)Loss on sale of asset.......... (307,299) 519,495 (4,206)
Director stock grant................. 30,000 30,000 --
Dry hole costs....................... 475,130 119,800 3,605,417
Payment of contingent liability...... -- (68,636) (160,518)
Payment of other liabilities......... -- -- (107,625)
Net change in:
Accounts receivable................. (2,188,070) 678,953 (289,660)
Prepaid insurance and other......... (181,323) 195,975 (71,550)
Accounts payable.................... 331,731 (5,051,761) 2,975,821
Accrued liabilities................. (95,030) (418,092) (679,620)
Other liabilities................... (484,525) -- --
------------ ----------- ------------
Net cash provided by operating
activities........................ 12,641,416 1,064,909 3,739,666
------------ ----------- ------------
INVESTING ACTIVITIES
Proceeds from sales of assets........ 459,526 249,487 49,091
Acquisition of oil and gas
properties.......................... (1,198,631) (4,099,956) (129,325)
Capital expenditures................. (15,141,818) (2,556,901) (14,101,522)
------------ ----------- ------------
Net cash used in investing
activities........................ (15,880,923) (6,407,370) (14,181,756)
------------ ----------- ------------
FINANCING ACTIVITIES
Proceeds from private placement of
common stock........................ 9,150,000 -- --
Principal payments of bank
borrowings.......................... (4,125,617) (2,409,383) (500,000)
Proceeds from bank borrowings........ -- -- 11,500,000
Preferred stock dividends............ (2,308,011) -- (1,255,638)
Proceeds from private placement
borrowings.......................... -- 12,000,000 --
Proceeds from preferred stock issue.. -- 3,000,000 --
Exercise of stock purchase warrants.. 249,322 -- --
Exercise of employee stock options... 191,444 3,909 --
Exercise of director stock options... 9,875 -- --
Net change in restricted cash........ (1,240,000) -- --
Payment of debt and equity financing
costs............................... (431,557) (1,303,496) --
Production payments.................. (653,415) (114,970) --
------------ ----------- ------------
Net cash provided by financing
activities........................ 842,041 11,176,060 9,744,362
------------ ----------- ------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS..................... (2,397,466) 5,833,599 (697,728)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD................... $ 5,929,229 95,630 793,358
------------ ----------- ------------
CASH AND CASH EQUIVALENTS AT END OF
PERIOD............................... 3,531,763 5,929,229 95,630
============ =========== ============
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 --
Accrued Capital Expenditures and
Financing Costs..................... -- -- 1,981,276
See notes to consolidated financial statements.
22
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
Years Ended December 31, 2000, 1999 and 1998
Accumulated
Other Comprehensive
Income-Unrealized
Additional Gain (Loss) on
Series A Series B Paid-In Accumulated Marketable Equity
Preferred Stock* Preferred Stock* Common Stock Capital Deficit Securities
------------------ ------------------ ---------------------- ------------ -------------- -------------------
Balance at
January 1,
1998............ 796,318 796,318 750,000 750,000 5,232,403 1,046,481 15,146,095 (3,490,618) 84,400
Net loss........ -- -- -- -- -- -- -- (7,715,342) --
Unrealized
Change in
Marketable
Securities...... -- -- -- -- -- -- -- -- (485,300)
Total
Comprehensive
Income (Loss)... -- -- -- -- -- -- -- -- --
Preferred stock
dividends....... -- -- -- -- -- -- -- (1,255,638) --
Employee and
director stock
grants.......... -- -- -- -- 15,302 3,060 79,932 -- --
------- --------- ------- --------- ---------- ----------- ------------ -------------- ----------
Balance at
December 31,
1998............ 796,318 $ 796,318 750,000 $ 750,000 5,247,705 $ 1,049,541 $ 15,226,027 $ (12,4 61,598) $ (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) $ --
======= ========= ======= ========= ========== =========== ============ ============== ==========
Total
Stockholders'
Equity
-------------
Balance at
January 1,
1998............ 14,332,676
Net loss........ (7,715,342)
Unrealized
Change in
Marketable
Securities...... (485,300)
-------------
Total
Comprehensive
Income (Loss)... (8,200,642)
Preferred stock
dividends....... (1,255,638)
Employee and
director stock
grants.......... 82,992
-------------
Balance at
December 31,
1998............ $ 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
=============
- -----
*dividends are cumulative and arrearages amounted to $1,249,343 or $0.23 per
share at December 31, 1999
See notes to consolidated financial statements
23
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2000
NOTE A--Description of Business
The Company is in the primary business of exploration and production of
crude oil and natural gas. The subsidiaries have interests in such operations
in seven states, primarily in Louisiana and Texas.
NOTE B--Summary of Significant Accounting Policies
Principals of Consolidation--The consolidated financial statements include
the financial statements of Goodrich Petroleum Corporation, its wholly-owned
subsidiaries, and one of its wholly-owned subsidiary's wholly-owned
subsidiaries. Significant intercompany balances and transactions have been
eliminated in consolidation.
Revenue Recognition--Revenues from the production of natural gas properties
in which the Company has an interest with other producers are recognized on
the entitlements method. 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 2000, 1999 and 1998 in the amounts of $1,835,000, $465,000
and $1,076,000 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.
24
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
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. The Company sold its marketable equity
securities in January 1999.
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 Financial Instruments--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. Gains and losses from derivatives designated as hedges of sales are
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 are amortized over the life of the contracts as a reduction
to oil and gas sales.
Accounting Matters--The Financial Accounting Standards Board FASB issued
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, in
June 1997. This statement established accounting and reporting standards for
derivative instruments and hedging activities. In June 2000, the FASB issued
SFAS No. 138, which amended certain provisions of SFAS No. 133. Effective
January 1, 2001, the Company must recognize the fair value of all derivative
instruments as either assets or liabilities in its Consolidated Balance Sheet.
A derivative instrument meeting certain conditions may be designated as a
hedge of a specific exposure; accounting for changes in a derivative's fair
value will depend on the intended use of the derivative and the resulting
designation. Changes in a dervative fair value for a qualifying hedge of
forecasted transactions will be deferred and recorded as a component of
accumulated comprehensive income until the forecasted transaction occurs, at
which time the dervative value will be recognized in earnings. Transition
adjustments resulting from adopting this statement will be reported in net
income or other comprehensive income, as appropriate, as the cumulative effect
of a change in accounting principal. The Company makes use of derivative
instruments to hedge specific market risks. The Company has determined that
the adoption of SFAS No. 133 will decrease other comprehensive income by
approximately $2,523,000 and the overall affect on net income from adoption of
this standard will not be significant.
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.
25
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
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.
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 generally accepted accounting
principals. Actual results could differ from those estimates.
NOTE C--Subsequent Events
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.
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 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 will be reflected as a preferred stock dividend to arrive at net
income applicable to common stock and will not have an affect on total
stockholders equity.
NOTE D--Indebtedness
Indebtedness at December 31, 2000 and 1999 consists of the following:
2000 1999
----------- ----------
Bank Debt
Borrowings under credit facility, interest, at Compass
Prime plus 5/8% (see below) (weighted average rate at
December 31, 2000--9.9%); principal due April 1, 2003.. $22,965,000 27,090,617
Convertible Notes Payable at the Subsidiary Level
Goodrich Petroleum Company, LLC $6,000,000 face amount,
interest at 8% maturing in 2004; (effective interest
rate of 13.0%)......................................... -- 4,931,250
Goodrich Petroleum Company--Lafitte LLC $6,000,000 face
amount, interest at 8% maturing in 2004; (effective
interest rate of 13.0%)................................ -- 4,931,250
----------- ----------
22,965,000 36,953,117
Less current portion.................................... -- 3,600,000
----------- ----------
Long-term debt, excluding current portion............... $22,965,000 33,353,117
=========== ==========
26
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
Compass Credit Facility
On January 31, 2001, the Company amended its Credit Agreement with Compass
Bank. The amended credit facility provides for an initial borrowing base,
subject to semi-annual redeterminations each April and October based on a
review of the Company's reserves, of $30,000,000. For the period from February
1, 2001 through February 28, 2001, the borrowing base will be $23,800,000. The
borrowing base will then reduce by $1,550,000 each calendar month thereafter
through and including the month of April, 2001. For each calendar month
thereafter, the redetermined borrowing base shall be reduced by $550,000.
Interest on the credit facility will accrue at a rate calculated at the option
of the Company as either the Compass Bank prime rate, or LIBOR plus 1.75%--
2.00% depending on borrowing base utilization. Interest is payable monthly.
The credit facility will mature on April 1, 2003. The credit facility requires
that the Company pay a commitment fee each quarter based on the Company's
borrowing base utilization. The fee is equal to 0.375% to 0.50% per annum
based on the 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 and restricts the Company from declaring or paying
dividends on its common stock without the lenders consent. Substantially all
the Company's assets are pledged to secure the credit facility.
Additionally, the Company has a $1 million letter of credit facility in
place with Compass Bank that expires in April 2003. There were no outstanding
letters of credit as of December 31, 2000.
Interest paid during 2000, 1999 and 1998 amounted to $2,182,724, $2,338,840
and $1,904,809 respectively.
Convertible Notes Payable
The convertible notes issued by two of the Company's subsidiaries in a
private placement in September 1999 accrued interest at 8% per annum, monthly
in arrears. The principal and interest on the notes were convertible into the
common stock of the Company at the rate of $4.00 per share. The purchasers of
these notes received one warrant to purchase a share of the common stock of
the Company at $.9375 (the closing price on the date the transaction was
negotiated) for every $4.00 of notes issued.
On August 17, 2000, the holders of approximately $12,943,000 of principal
and accrued interest on the convertible notes converted their notes into
3,235,647 shares of the Company's common stock under the original terms of the
notes. The conversion of the notes increased stockholders equity by
approximately $10,130,000, inclusive of approximately $1,033,000 in remaining
deferred loan financing costs which were eliminated.
The Company arranged a stand-by underwriting to finance the purchase of the
convertible notes from noteholders that elected not to convert their notes
into the Company's common stock. Notes purchased by the underwriters were
subsequently converted into shares of the Company's common stock on the same
terms as the notes originally tendered for conversion. Two of the underwriters
are, or are affiliates of, members of the Company's board. Each underwriter
received 15,000 shares of the Company's common stock as compensation for their
services. In addition, one of the underwriters received an additional 15,000
shares of common stock for their role as agent for the noteholders. The
Company issued 60,000 shares of common stock as consideration for underwriting
and noteholder agent assistance relative to the conversion of the notes, which
resulted in a charge to interest expense of $280,500.
27
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
Note E--Preferred Stockholders Equity in a Subsidiary Company
During 1999, Goodrich-Louisiana issued $3,000,000 of preferred interests
consisting of 300,000 preferred units with a par value and liquidation
preference of $10 per share. The fair value of the preferred units was
recorded as preferred stockholders' equity in a subsidiary company in the
accompanying financial statements. Dividends on the preferred units accrued
quarterly in arrears at 8% per annum through September 30, 2002 at which time
the rate increased 2% per year, not to exceed 20%. Goodrich-Louisiana had the
right to redeem the units at any time. The preference amount and accrued
dividends were convertible by the holder at any time into the common stock of
the Company at $2.00 per share. Each preferred unit holder was also issued one
warrant to purchase a share of common stock of the Company for every $10 of
preference value. The warrants are exercisable at $1.50 per share at any time
before their expiration on September 30, 2006. Issuance costs of $180,000 were
allocated to and offset against the carrying value of the preferred units.
On February 17, 2000, all of the holders of the Preferred Units converted
the units into approximately 1,550,000 shares of the common stock of Goodrich
Petroleum Corporation. The conversion of the preferred units increased the
Company's stockholders equity by approximately $2,700,000.
NOTE F--Acquisition of Oil and Gas Properties
On March 2, 2000, the Company completed its acquisition of working
interests in the Burrwood and West Delta 83 Fields, comprising approximately
8,600 acres, in Plaquemines Parish, Louisiana for net purchase price of
$1,198,000 and the assumption of the fields plugging and abandonment
obligation estimated at $4,300,000 and the obligation to shoot 3-D seismic
over the fields at a cost of approximately $2,500,000. The Company acquired an
approximate 95% working interest of all rights from the surface to
approximately 10,600' and an approximate 47.5% working interest in the deep
rights below 10,600 feet.
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, 2000,
1999 and 1998. The following table reconciles the weighted average shares
outstanding used for these computations.
Year Ended December 31,
------------------------------
2000 1999 1998
---------- --------- ---------
Basic Method..................................... 9,903,248 5,288,011 5,243,105
Dilutive Stock Warrants.......................... 2,842,858 -- --
Dilutive Stock Options........................... 370,535 -- --
Convertible Debt................................. -- -- --
---------- --------- ---------
Diluted Method................................... 13,116,641 5,288,011 5,243,105
========== ========= =========
Both series of the Company's convertible preferred stock and its stock
options are considered to be potential common stock. Additionally, stock
purchase warrants issued in the 1999 Private Placement and the convertible
debt are also considered potential common stock. Approximately 798,000 stock
options and 1,067,000 shares issuable in connection with the convertible
preferred stock have not been included in the computation of diluted income
per share in 2000 because to do so would have been antidilutive. No potential
common stock amounts have been included in the computation of diluted per
share in 1999 and 1998 because to do so would have been antidilutive. The
calculation of the dilutive effects of potentially dilutive securities has
been calculated using the treasury stock method.
28
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
NOTE H--Income Taxes
Income tax expense for the years ending December 31, 2000, 1999 and 1998
consists of:
Current Deferred Total
------- ---------- ----------
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................................... -- -- --
------- ---------- ----------
-- -- --
======= ========== ==========
Year Ended December 31, 1998:
U.S. Federal............................ $14,643 (14,643) --
State................................... -- -- --
------- ---------- ----------
14,643 (14,643) --
======= ========== ==========
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,
2000, 1999 and 1998:
2000 1999 1998
----------- -------- ----------
U.S. Statutory Income Tax.................. 1,429,460 (640,144) (2,700,370)
Increase in deductible temporary
differences for which no benefit
recorded.................................. -- 640,144 2,669,509
Change in the beginning of the year balance
of the valuation allowance allocated to
income tax expense (3,089,767) -- --
Nondeductible expenses..................... 5,275 -- 30,681
----------- -------- ----------
(1,655,032) -- --
=========== ======== ==========
29
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at December
31, 2000 and 1999 are presented below.
December 31, December 31,
2000 1999
------------ ------------
Deferred tax assets:
Differences between book and tax basis of:
Contingent liabilities...................... $ 132,349 132,349
Other......................................... 157,247 8,750
Operating loss carryforwards.................. 14,383,974 13,384,419
Statutory depletion carryforward.............. 6,407,941 5,974,726
AMT Tax credit carryforward................... 1,477,872 1,477,872
Investment tax credit carryforward............ 2,108 2,108
----------- -----------
Total gross deferred tax assets............... 22,561,491 20,980,224
Less valuation allowance...................... (16,816,199) (19,784,669)
----------- -----------
Net deferred tax assets....................... 5,745,292 1,195,555
----------- -----------
Deferred tax liability:
Differences between book and tax basis of:
Property and equipment...................... (4,050,617) (1,155,912)
----------- -----------
Total gross deferred liability................ (4,050,617) (1,155,912)
----------- -----------
Net deferred tax asset........................ $ 1,694,675 39,643
=========== ===========
The valuation allowance for deferred tax assets decreased $2,968,470 and
increased $680,000 for the years ended December 31, 2000 and 1999,
respectively. 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, 2000. 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.
30
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
The following table summarizes the amounts and expiration dates of
operating loss and investment tax credit carryforwards:
Operating loss
carryforwards Investment tax credit carryforwards
-------------- -----------------------------------
Amount Expires Amount Expires
------ ------- ------------------ ------------------
$ 973,053 2005 $2,108 2001
7,093,823 2006
8,860,622 2007
4,285,746 2008
3,247,494 2009
5,480,870 2010
600,706 2011
1,939,496 2012
4,530,029 2018
2,546,445 2019
1,538,785 2020
-----------
$41,097,069
===========
As a result of the August 15, 1995 business combination, the Company's
annual utilization of its net operating loss and statutory depletion
carryforwards generated prior to the business combination are limited under
Internal Revenue Code Section 382. Such limitation is determined annually and
is comprised of a base amount of $1,682,797 plus any recognized "built in
gains" existing at August 15, 1995.
Additionally, as a result of the conversion of the preferred units and
private placement on February 18, 2000, the combined annual limitation of the
Company's existing net operating losses and statutory depletion carryforwards
will be approximately $2,671,000 plus any recognized "built in gains" existing
at February 18, 2000. Such limitation amounted to $23,511,000 in 1999 and is
estimated to be $26,733,000 in 2000. The Company's statutory depletion
carryforwards and AMT credit carryovers have no expiration date.
The Company paid income taxes of $4,344 in 1998.
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, 2000 the remaining
principal amount was $2,172,000 and the recorded liability was $1,691,000.
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, 2000, based on expected
production and prices and expected discount amortization is that projected
payments will decrease the recorded liability as follows: 2001, $561,000;
2002, $592,000 and 2003, $538,000.
31
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
NOTE J --Stockholders' Equity
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 were 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.
Approximately $2,300,000 of the proceeds from issuance of the convertible
notes and preferred units as part of the 1999 Private Placement was allocated
to additional paid in capital as the fair value of the warrants issued in
connection with the securities. The proceeds allocable to additional paid-in
capital were being amortized as additional interest cost over the original
term of the related notes until their conversion in August 2000, (See Note D).
Additional interest costs related to the amortization of proceeds amounted to
$359,000 and $142,500 for 2000 and 1999, respectively.
Common Stock--At December 31, 2000 unissued shares of Goodrich common stock
were reserved in the amount of 3,348,000 shares for the exercise of stock
warrants issued in connect with the private placement transaction of September
23, 1999 and 762,188 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 has 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. During 2000
holders of 84,241 shares of Series B Preferred Stock opted to convert their
shares into 94,216 shares of common stock of the Company. 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
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 C), the Company
exchanged all 660,839 shares of its Series B preferred stock into 1,189,510
shares of common stock.
32
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
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, 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, Goodrich 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 762,168 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
2000, 1999 and 1998 was $3.16, $2.17 and $2.57 on the date of grant using the
Black Scholes option-pricing model with the following weighted-average
assumptions: 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; 1998--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:
2000 1999 1998
---------- ---------- ----------
Net Income(loss)................ As reported $5,739,204 (1,828,983) (7,715,342)
Pro forma 5,040,410 (2,109,357) (7,906,618)
Income(loss) applicable to...... As reported 4,545,436 (3,078,326) (8,970,980)
common stock ................. Pro forma 3,846,642 (3,358,700) (9,162,256)
Basic income(loss)
per average common share...... As reported 0.46 (0.58) (1.71)
Pro forma 0.39 (0.64) (1.75)
Diluted income(loss)
per average common share...... As reported 0.35 (0.58) (1.71)
Pro forma 0.29 (0.64) (1.75)
33
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
Stock option transactions during 2000, 1999 and 1998 were as follows:
Weighted
Weighted Average
Number of Average Remaining
Options Exercise Price Range of Exercise Price Contractual Life
----------------- -------------- -------------------------------- -----------------
Patrick Patrick Patrick
Total Only Total Only Total Patrick Only Total Only
-------- ------- ------ ------- --------------- ---------------- -------- --------
Outstanding January 1,
1998 .................. 341,442 70,817 9.60 18.60 $5.50 to $24.00 $16.00 to $24.00 7.4 yrs. 4.2 yrs.
======== =======
Granted--1995 Stock
Option Plan........... 144,000 -- 5.98 --
Granted--1997 Director
Compensation Plan .... 10,000 -- 5.98 --
Expiration of Options
...................... (62,190) (5,625) 7.88 19.33
-------- -------
Outstanding December 31,
1998 .................. 433,252 65,192 -- -- $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
Stock Option ......... 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 35,625 -- -- $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--1995 Non-
Employee Director
Stock Option Plan .... 12,000 -- 4.88 --
Exercised--1995 Stock
Option Plan........... (245,698) -- .78 --
Exercised--1997
Director Stock Option
Plan.................. (12,500) -- .79 --
Expiration of Options
...................... (64,500) -- 4.35 --
-------- -------
Outstanding December 31,
2000 .................. 762,186 35,625 -- -- $0.75 to $24.00 $16.00 to $24.00 8.9 yrs. 1.9 yrs.
======== =======
Exercisable December 31,
1998 .................. 208,379 65,192 $10.86 18.54
Exercisable December 31,
1999 .................. 71,438 35,625 $ 9.95 19.00
Exercisable December 31,
2000 .................. 129,356 35,625 $ 7.59 19.00
NOTE J--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 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 will not engage in speculative activity
not supported by production.
34
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
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 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, 2000, the Company's open forward position on its
outstanding crude oil was as follows:
(a) 500 barrels of oil per day with a no cost "collar" of $20.00 and
$28.40 per barrel through December 2001;
(b) 300 barrels of oil per day with a no cost "collar" of $23.00 and
$29.55 per barrel through December 2001; and
The fair value of the crude oil hedging contracts in place at December 31,
2000, resulted in a liability of $20,000.
As of December 31, 2000, our natural gas hedging contracts were as follows:
(e) 5000 MMbtu per day with a no cost collar of $3.05 and $4.45 per
MMbtu through December 31, 2001;
(f) 5000 Mcf per day "swap" at $7.75 per Mcf for January 2001;
(g) 5000 Mcf per day "swap" at $7.42 per Mcf for February 2001; and
(h) 5000 Mcf per day "swap" at $7.60 per Mcf for March 2001.
The fair value of the natural gas hedging contracts in place at December
31, 2000, would result, if not accounted for as hedges, in a liability of
$3,881,000.
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 our open contacts. 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.
35
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
NOTE K--Fair Value of Financial Instruments
The following presents the carrying amounts and estimated fair values of
the Company's financial instruments at December 31, 2000 and 1999.
December 31, 2000 December 31, 1999
---------------------- ---------------------
Carrying Carrying
Amount Fair Value Amount Fair Value
----------- ---------- ---------- ----------
Financial liabilities--
Long-term debt
(including current
maturities)........... $22,965,000 22,965,000 27,090,617 27,090,617
Notes payable.......... $ -- -- 9,862,500 9,862,500
Production payment
liability............. $ 1,691,050 1,691,050 2,113,000 2,113,000
Hedges Asset
(Liability)--
Oil.................... $ -- -- -- (338,000)
Gas.................... $ -- (3,881,000) -- 300,000
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.
NOTE L--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,
----------------
2000 1999 1998
---- ---- ----
Seaber Corporation of Louisiana............................ 48% 37% 47%
Genesis Crude Oil, L.P..................................... 27% -- --
Gulfmark Energy, Inc....................................... 10% -- --
Equiva Trading............................................. 8% 27% 12%
Texla Energy Management.................................... -- 10% --
Navajo Refining Company.................................... 4% 7% 11%
NOTE M--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
36
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
approximately 3.05%. As of December 31, 2000, 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. In addition,
as part of the purchase agreement, the Company has agreed to shoot a 3-D
seismic survey over the fields by June 30, 2001 or remit payment to the seller
in the amount of $3,500,000. The 3-D seismic survey began in July 2000 and the
Company anticipates that the seismic survey will be completed on or before
June 30, 2001. The cost of the seismic survey is expected to be approximately
$2,500,000 and the Company has incurred seismic study costs of approximately
$1,250,000 through December 31, 2000.
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 in its early stages 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.
NOTE N--Natural Gas and Crude Oil Cost Data
The following reflects the Company's capitalized costs related to natural
gas and oil activities at December 31, 2000, and 1999:
2000 1999
----------- -----------
Proved properties.............................. $74,778,157 61,527,593
Unproved properties............................ 4,474,823 3,873,575
----------- -----------
79,252,980 65,401,168
Less accumulated depreciation and depletion.... (25,908,724) (19,398,287)
----------- -----------
Net property and equipment..................... $53,344,256 46,002,881
=========== ===========
37
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
The following table reflects certain data with respect to natural gas and
oil property acquisitions, exploration and development activities:
Year Ended December 31,
---------------------------------------
2000 1999 1998
----------- ---------- ----------
Property acquisition
Proved.......................... $ 1,198,631(a) 10,136,298(b) 129,325
Unproved........................ 820,200 498,391 2,446,474
Exploration....................... 2,797,642 1,634,299 8,718,682
Development....................... 13,862,296 1,960,371 8,169,741
----------- ---------- ----------
$18,678,769 14,229,359 19,464,222
=========== ========== ==========
- --------
(a) Burrwood/West Delta 83 Field acquisition.
(b) Primarily Lafitte Field acquisition inclusive of liabilities assumed in
connection with the purchase.
NOTE O--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.
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.
38
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
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 $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, and $9.37 per Bbl and
$2.24 per Mcf, respectively as of December 31, 1998.
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, 2000.
Schedule 1--Estimated Net Proved Gas Reserves (Mcf)
Year Ended December 31,
----------------------------------
2000 1999 1998
---------- ---------- ----------
Proved:
Balance, beginning of period...... 20,849,592 28,144,310 37,570,614
Revisions of previous estimates... 708,580 (6,069,885) (8,393,772)
Purchase of minerals in place..... 5,955,477 1,705,822 226,778
Extensions, discoveries, and other
additions........................ 5,546,322 -- 1,656,200
Production........................ (3,394,921) (2,930,655) (2,782,825)
Sales of minerals in place........ 154,371 -- (132,685)
---------- ---------- ----------
Balance, end of period............ 29,510,679 20,849,592 28,144,310
========== ========== ==========
Proved developed:
Beginning of period............... 13,945,540 21,481,946 16,600,669
End of period..................... 22,251,970 13,945,450 21,481,946
Schedule 2--Estimated Net Proved Oil Reserves (Barrels)
Year Ended December 31,
-------------------------------
2000 1999 1998
--------- --------- ---------
Proved:
Balance, beginning of period......... 5,738,997 3,092,810 4,098,390
Revisions of previous estimates...... 74,369 (12,989) (988,611)
Purchase of minerals in place........ 891,334 3,053,618 --
Extensions, discoveries, and other
additions........................... 665,911 -- 299,799
Production........................... (571,766) (394,442) (316,768)
Sale of minerals in place............ (9,487) -- --
--------- --------- ---------
Balance, end of period............... 6,789,358 5,738,997 3,092,810
========= ========= =========
Proved, developed:
Beginning of period.................. 2,662,907 2,266,854 2,292,626
End of period........................ 3,196,330 2,662,907 2,266,854
39
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
December 31, 2000
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,
--------------------------------
2000 1999 1998
---------- ---------- ----------
Estimated Net Proved Reserves (Mcfe):
Total Proved......................... 70,246,827 55,283,574 46,701,170
Proved Developed..................... 41,429,950 29,922,892 35,083,070
Schedule 3--Standardized Measure of Discounted Future Net Cash Flows Related
to Proved Oil and Gas Reserves
Year Ended December 31,
---------------------------
2000 1999 1998
--------- ------- -------
(in thousands)
Future cash inflows.............................. $ 452,310 182,292 86,449
Production costs................................. (55,948) (31,647) (18,617)
Development costs................................ (25,201) (15,458) (5,722)
Future income tax expense(a)..................... (101,113) (21,534) --
--------- ------- -------
Future net cash flows............................ 270,048 113,653 62,110
10% annual discount for estimated timing of cash
flows........................................... (90,268) (35,092) (21,475)
--------- ------- -------
Standardized measure of discounted future net
cash flows...................................... $ 179,780 78,561 40,635
========= ======= =======
Average year end prices:
Natural gas (per Mcf).......................... $ 10.06 2.63 2.24
Crude oil (per Bbl)............................ $ 26.10 25.16 9.37
========= ======= =======
- --------
(a) Taxable income for 1998 period was entirely offset by available net
operating loss carry forwards.
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,
--------------------------
2000 1999 1998
-------- ------- -------
(in thousands)
Net changes in prices and production costs related
to future production............................. $ 91,250 33,360 (31,820)
Sales and transfers of oil and gas produced, net
of production costs.............................. (21,100) (10,144) (7,015)
Net change due to revisions in quantity
estimates........................................ 4,112 (10,277) (12,464)
Net change due to extensions, discoveries and
improved recovery................................ 33,974 -- 3,006
Net change due to purchase and sales of minerals-
in-place......................................... 39,485 33,476 82
Development costs incurred during the period...... 1,127 338 2,198
Net change in income taxes........................ (56,485) (13,845) 14,093
Accretion of discount............................. 9,241 4,064 7,810
Change in production rates (timing) and other..... (385) 954 742
-------- ------- -------
$101,219 37,926 (23,368)
======== =======
40
GOODRICH PETROLEUM CORPORATION
Consolidated Quarterly Income Information
(Unaudited)
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
----------- --------- ---------- --------- ----------
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 earnings
(Loss) per average
common share......... $ (.05) .12 .23 .01 .35
1999
Revenues.............. $ 2,941,696 2,829,530 3,631,762 4,617,586 14,020,574
Costs and Expenses.... 3,458,450 3,405,546 3,283,633 5,182,433 15,330,062
Loss on sale of
assets............... (519,495) -- -- -- (519,495)
Net income (Loss)..... (1,036,249) (576,016) 348,129 (564,847) (1,828,983)
Preferred stock
dividends............ 313,912 313,912 313,912 307,607 1,249,343
Income (Loss)
applicable to common
Stock................ (1,350,161) (889,928) 34,217 (872,454) (3,078,326)
Basic income (Loss)
per average common
share................ (.26) (.17) .01 (.16) (.58)
Diluted income (Loss)
per average
common share......... $ (.26) (.17) .01 (.16) (.58)
The fourth quarter of 2000 and 1999 amount includes impairment of oil and
gas properties of $1,835,000 and $465,000, respectively.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure.
None
41
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 2001 Annual Meeting of Stockholders.
42
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............................................. 18
Consolidated Balance Sheets--December 31, 2000 and 1999.................. 20
Consolidated Statements of Operations--Years ended December 31, 2000,
1999 and 1998........................................................... 21
Consolidated Statements of Cash Flows--Years ended December 31, 2000,
1999 and 1998........................................................... 22
Consolidated Statements of Stockholders' Equity and Comprehensive Income
--Years ended December 31, 2000, 1999 and 1998.......................... 23
Notes to Consolidated Financial Statements--Year ended December 31,
2000.................................................................... 24
Consolidated Quarterly Income Information (Unaudited).................... 41
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 3.1a of the Company's registration statement filed on Form
S-1 (No. 333-47078)).
3(I).2 Certificate of Amendment of Restated Certificate of Incorporation of
Goodrich Petroleum Corporation dated March 12, 1998. (Incorporated by
reference to Exhibit 3.16 of the Company's registration statement on
Form S-1 (No. 333-47078)).
3(ii).1 Bylaws of the Company, as amended and restated (Incorporated by
reference to Exhibit 3.3 of the Company's registration statement filed
on Form S-1 (No. 333-47078)).
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 Series B Convertible Preferred Stock Certificate of Designations.
(Incorporated by reference to Exhibit 4.6 of the Company's Annual
Report on Form 10-K for the year ended December 31, 1996).
4.3 Credit Agreement among Goodrich Petroleum Company, L.L.C., Compass
Bank and other lenders dated January 31, 2001.
4.4 Letter of Credit Agreement among Goodrich Petroleum Company, L.L.C.,
Compass Bank and other lenders dated January 31, 2001.
4.5 Amendment to the Letter of Credit Agreement among Goodrich Petroleum
Company, L.L.C., Compass Bank and other lenders dated March 13, 2001.
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 Consulting Services Agreement between Leo E. Bromberg and Goodrich
Petroleum Corporation (Incorporated by reference to Exhibit 10.1 to
the Company's Quarterly Report filed on Form 10-Q for the three months
ended September 30, 1995).
43
10.3 Goodrich Petroleum Corporation 1997 Director Compensation Plan
(Incorporated by reference to the May 20, 1998 Proxy).
10.4 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).
10.5 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).
10.6 Registration Statement on Form S-1 filed on September 29, 2000
(Registration No. 333-47078)
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.
44
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)
Date: March 28, 2001 By /s/ Walter G. Goodrich
___________________________________
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, 2001
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 and Chief
______________________________________ Financial Officer (Principal Financial
Roland L. Frautschi Officer)
/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/ Jeff Benhard Director
______________________________________
Jeff Benhard
/s/ Mike McGovern Director
______________________________________
Mike McGovern
/s/ Michael J. Perdue Director
______________________________________
Michael J. Perdue
/s/ Patrick E. Malloy, III Director
______________________________________
Patrick E. Malloy, III
45