U.S. 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
Commission file number: 333-66282
For the fiscal year ended December 31, 2001
TRI-UNION DEVELOPMENT CORPORATION
FORMERLY KNOWN AS TRIBO PETROLEUM CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-0381207
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NUMBER)
530 LOVETT BOULEVARD
HOUSTON, TEXAS 77006
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
(713) 533-4000
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(d)
OF THE ACT:
NONE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
COMMON STOCK $0.01 PAR VALUE
(TITLE OF CLASS)
INDICATE BY CHECK MARK WHETHER THE REGISTRANT: (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS.
YES X NO
---- ----
AS OF APRIL 1, 2002 THERE WERE 368,333 SHARES OF CLASS A COMMON STOCK, PAR VALUE
$0.01 PER SHARE AND 65,000 SHARES OF CLASS B COMMON STOCK, PAR VALUE $0.01 PER
SHARE, OUTSTANDING.
TRI-UNION DEVELOPMENT CORPORATION
(formerly Tribo Petroleum Corporation)
TABLE OF CONTENTS
Part I.
Item 1. Business......................................................................... 2
Item 2. Properties....................................................................... 4
Item 3. Legal Proceedings................................................................ 20
Item 4. Submission of Matters to a Vote of Security Holders.............................. 21
Part II.
Item 5. Market for Common Stock and Related Shareholder Matters.......................... 21
Item 6. Selected Financial Data.......................................................... 22
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations....................................................... 23
Item 7a. Qualitative and Quantitative Disclosures About Market Risks...................... 30
Item 8. Financial Statements and Supplementary Data...................................... 32
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................................ 32
Part III.
Item 10. Directors and Executive Officers of the Registrant............................... 33
Item 11. Executive Compensation........................................................... 34
Item 12. Security Ownership of Certain Beneficial Owners and Management................... 35
Item 13. Certain Relationships and Related Transactions................................... 36
Part IV.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K................. 38
Glossary of Selected Oil and Gas Terms................................................................. 39
Signatures............................................................................................. 42
Financial Statements
Reports of Independent Public Accounts........................................................ F-2
Reports of Independent Public Accounts........................................................ F-3
Consolidated Balance Sheets................................................................... F-4
Consolidated Statements of Operations and Comprehensive Income (Loss)......................... F-5
Consolidated Statements of Stockholder's Equity............................................... F-6
Consolidated Statements of Cash Flows......................................................... F-7
Notes to Consolidated Financial Statements.................................................... F-8
1
SUMMARY
Unless specified otherwise, references to "Tri-Union," "we," and "our" refer to
Tri-Union Development Corporation ("TDC") and Tri-Union Operating Company
("TOC"), our wholly owned subsidiary. The consolidated historical financial,
reserve, and operating data set forth include information for our subsidiary and
us on a consolidated basis. The information in this report gives effect to our
merger with our former parent corporation, Tribo Petroleum Corporation, on July
27, 2001. If you are not familiar with some of the oil and natural gas terms
used in this report, please read "Glossary of Selected Oil and Natural Gas
Terms" beginning on page 39.
PART I.
ITEM 1. BUSINESS
We are an independent oil and natural gas company engaged in the
acquisition, development, exploration and production of oil and natural gas
properties in three core areas. Our core areas are located onshore Gulf Coast,
primarily in Texas and Louisiana, offshore Gulf Coast in the shallow waters of
the Gulf of Mexico and in the Sacramento Basin of northern California. We have
established significant operating expertise in our core areas and, since 1999,
have achieved substantial production growth with a limited capital budget.
TOC's principal asset is a net profits interest in a field operated by us.
This interest is TOC's primary oil and natural gas property and represents less
than 5% of our consolidated proved reserves.
At December 31, 2001, we had net proved reserves of 191.7 Bcfe,
approximately 56% of which were natural gas, with a reserve life of 12.5 years.
Our reserve base is diversified across our three core areas, with 59.7% of our
proved reserves located onshore Gulf Coast, 10.6% offshore Gulf Coast and 29.6%
in California. Each of these core areas is characterized by years of stable,
historical production and numerous producing wells. We operate approximately 92%
of our proved reserves.
We own interests in 38 fields located onshore Gulf Coast, 36 producing
blocks offshore Gulf Coast and 15 fields located in California. During 2001,
these fields produced approximately 42 Mmcfe per day.
We have a large inventory of development projects that we have only recently
begun to exploit. Because we operate in older, more mature fields with long
production histories and many producing wells, we believe these projects
represent low-risk opportunities to add to our reserves. We completed 65 of
these projects during 1999, 2000 and 2001 for $24.2 million in development
capital expenditures for drilling and recompletions.
In our California region during 2001, we drilled 4 development wells,
conducted 33 sidetrack/deepening and stimulation projects of existing wells and
acquired approximately 33 square miles of 3-D seismic data. During 2001, we
identified 42 proved undeveloped locations and 28 proved non-producing
opportunities that we intend to exploit during 2002 and 2003. We are currently
evaluating the seismic data and expect the results to lead to a significant
number of additional opportunities.
At December 31, 2001, approximately 80% of our projected oil and natural gas
production from proved developed producing reserves (and the basis differential
attributable to approximately 80% of our projected proved developed producing
natural gas production from our California properties) was hedged through
December 31, 2003 at average swap prices of $3.96 per Mcf and $24.42 per Bbl, or
a weighted-average natural gas-equivalent price of approximately $4.01 per Mcfe.
In connection with the issuance of our senior secured notes, we agreed to
maintain, on a monthly basis, a rolling two-year hedge program until the
maturity of the notes, subject to certain conditions. In March 2002, we
terminated certain of our derivatives contracts and replaced them with contracts
providing for price floors at the prices specified under the terms of
the senior secured notes of $2.75 per MMBtu of natural gas (Henry Hub) and
$18.50 per barrel of crude oil (West Texas Intermediate). We believe this
hedging program will assist with the successful execution of our development
plans and profitably grow production from current levels.
We acquired our first significant reserves in 1996 with the Reunion
acquisition and have grown substantially since that time. Since January 1997,
our first full year following the Reunion acquisition, our reserves increased
from 46.9 Bcfe to 191.7 Bcfe. Similarly, annual production increased from 2.0
Bcfe in 1996 to 15.3 Bcfe in 2001. EBITDA increased from $2.7 million in 1996 to
$71.2 million in 2001. Since 1996 we have achieved growth profitably, investing
$131.6 million in acquisition and drilling capital expenditures.
On July 27, 2001, we were the surviving corporation in a merger with our
parent corporation, Tribo Petroleum Corporation. As a consequence of this
merger, we assumed all of the rights and obligations of Tribo.
2
OUR STRATEGY
Focus on our California properties. Oil and natural gas prices declined
during the latter half of 2001, adversely affecting our working capital and
requiring us to reduce our budgeted capital expenditures. As a consequence of
these limitations and other unpredictable events, our production declined during
the last two quarters of 2001. As a result of our capital limitations, coupled
with our obligation to pay approximately $28 million in interest and principal
on our senior secured notes on June 1, 2002, we determined to focus our future
efforts on our California gas assets. This strategic focus is warranted by our
current and historic successes in the area.
During the last half of 2001, we identified over five thousand feet (5000')
of behind pipe pay in numerous wellbores in the Sacramento Basin and began a
60-well recompletion program. In the third and fourth quarters of the year,
seventeen wells were successfully recompleted, adding over 6.2 Bcf of new
reserves at an average finding and development cost of less than $0.10 per Mcf.
In November, we also completed one proven undeveloped ("PUD") location, adding
1.2 Bcf gross or 565 Mmcf net booked reserves at an average finding and
development cost of $0.50 per Mcf. To date, we have successfully drilled and
completed 12 out of 13 wells in this region for a success rate of greater than
90%. We currently have an additional 40 PUD locations booked in the December 31,
2001 reserve report and have completed a 33 square mile 3-D seismic survey
covering over 23,000 acres that is expected to yield additional drilling
opportunities. Operating costs in the area have historically been well below the
industry average.
In order to fund our continued development efforts in the Sacramento Basin
and to provide the necessary cash to meet our obligations and the required
amortization payments on the senior secured notes, we intend to divest most or
all of our Gulf Coast onshore and offshore assets during 2002. We have retained
the services of an oil and gas marketing agent to assist us in the sales
process. Sales brochures have been distributed and a number of potential buyers
are currently evaluating the sale properties.
OUR BANKRUPTCY AND RECAPITALIZATION
In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation. Prior to the acquisition, we had
approximately $35 million in debt outstanding. We incurred approximately another
$63 million in debt in connection with the acquisition. A portion of this debt
was in the form of a short-term, amortizing bank loan. In August 1998, before we
were able to refinance our bank loan, commodity prices began falling, with oil
prices ultimately reaching a 12-year low in December 1998. The resultant
negative effect on our cash flow from the deterioration of commodity prices,
coupled with the required amortization payments on our bank loan, severely
restricted the amount of capital we were able to dedicate to development
drilling. Consequently, our oil and natural gas production declined, further
negatively affecting our cash flow. In October 1998, our short-term loan matured
and we arranged a forbearance agreement providing for interest payments to be
partially capitalized and providing us additional time to refinance our
obligations. In July 1999, the forbearance agreement terminated and we made
negotiated interest payments while attempting to negotiate a restructuring of
our obligations. By March 2000, the aggregate principal balance of our bank debt
had increased as a result of capitalized interest and expenses to approximately
$105 million. In February 2000, the bank declared a default on the loan,
demanded payment of all principal and interest and posted the shares of Tribo
Petroleum Corporation, our parent corporation and a guarantor of the loan, for
foreclosure. As a consequence of the bank's foreclosure action, on March 14,
2000, we chose to seek protection under Chapter 11 of the Bankruptcy Code in
U.S. Bankruptcy Court for the Southern District of Texas, Houston Division.
Tri-Union Operating continued to operate outside of bankruptcy.
As a result of the redeployment of funds formerly utilized for amortization
payments, we conducted a limited but highly successful development-drilling
program, which resulted in an increase of our average daily production. This
production increase, coupled with improved commodity prices, allowed us to
increase our cash position to approximately $66.7 million immediately prior to
closing of the offering of our senior secured notes from approximately $1.4
million on March 14, 2000. The notes were issued on June 18, 2001 as part of a
private unit offering, with each unit consisting of one note in the principal
amount of $1,000 and one share of class A common stock of our former parent
corporation, Tribo Petroleum Corporation, with which we merged on July 27, 2001.
The units were sold to
3
Jefferies & Company, Inc., as initial purchaser. The initial purchaser sold the
units to qualified institutional buyers in reliance on Rule 144A under the
Securities Act. The proceeds of the offering of the notes and our available cash
balances allowed us to satisfy all creditor claims in full, including interest,
in accordance with the amended plan of reorganization that we filed on May 9,
2001 and to exit bankruptcy on June 18, 2001.
SENIOR SECURED NOTES
The senior secured notes were issued under an indenture complying with the
Trust Indenture Act of 1939. U.S. Bank National Association (f/k/a Firstar Bank,
National Association) is the trustee under the indenture. The notes bear
interest at 12.5% per annum, payable semiannually on June 1 and December 1 of
each year. Principal is payable in installments beginning on June 1, 2002, with
final maturity on June 1, 2006. On June 1, 2002 and 2003, the Company is
required to pay installments equal to the greater of $20,000,000 or 15.3% of the
aggregate principal balance of the notes. On June 1, 2004, the Company is
required to pay an installment equal to the greater of $15,000,000 or 11.5% of
the aggregate principal balance of the notes. There are limits on the Company's
ability to redeem the notes, including penalties if redeemed prior to June 1,
2005.
Commencing with the quarter ended June 30, 2004, and continuing each quarter
thereafter, the Company is required to offer to apply fifty percent of its cash
flow in excess of $1,000,000 for the quarter to the pro rata redemption of the
notes.
The notes are senior secured obligations, secured by a first priority lien
on substantially all of the Company's oil and gas assets, and are
unconditionally guaranteed by the Company's only subsidiary, Tri-Union Operating
Company, which guarantee is secured by a first priority lien on substantially
all of the oil and gas assets of Tri-Union Operating Company. Under the terms of
an Intercreditor Agreement, the liens are held by a collateral agent for the
benefit of hedge counter parties and the holders of the notes. Proceeds from the
sale of collateral upon default are to be applied to the satisfaction of amounts
owing to hedge counter parties under approved hedge agreements before being
applied to interest and principal owing upon the notes.
The indenture contains certain covenants, including covenants that limit the
Company's ability to incur additional debt, to sell or transfer its assets and
covenants that require the board of directors to consist of no fewer than three
individuals, at least 60% of which are required to be independent. Additionally,
the Company is required to hedge its oil and natural gas production so as to
maintain a hedged revenue to interest expense ratio of at least three to one.
The Company is not permitted to hedge more than 80% of its projected proved
developed producing volumes of oil and natural gas, except under price floor
contracts or options, and the Company is not required to enter into hedges when
certain benchmark prices are less than $2.75 per MMBtu or $18.50 per Bbl.
ITEM 2. PROPERTIES
Our oil and natural gas properties are primarily located in three core areas
of operation: (1) onshore Gulf Coast, primarily in Texas and Louisiana; (2)
offshore Gulf Coast in the shallow waters of the Gulf of Mexico; and (3) in the
Sacramento Basin of northern California. All of our oil and natural gas
properties are subject to the lien of the indenture that secures the senior
secured notes, as well as liens imposed by operation of law, such as mechanic's
liens and liens for property taxes not yet due. None of our properties has an
attached payment or performance obligation.
Our onshore Gulf Coast properties accounted for 59.7% of our proved reserves
at December 31, 2001 and 62.6% of our production during 2001. Our onshore Gulf
Coast proved reserves were distributed among 38 fields and approximately 350
producing wells and a number of undeveloped locations. Most of our onshore Gulf
Coast producing wells have been on production for several years and their
respective production decline rates are relatively slow and well established.
Our working interests in the fields range from 0.16% to 100% with an average
working interest of 70%. We operate 24 of our 38 fields in the onshore Gulf
Coast area and 11 of our 21 top value properties are located in the area. Each
of these top value properties are operated by us and, in aggregate, accounted
for 85% of the production from the area during 2001 and 91% of our proved
reserves in the area at December 31, 2001.
Our offshore Gulf Coast properties accounted for 10.6% of our proved
reserves and 16.9% of our production for the year ended December 31, 2001. Our
offshore Gulf Coast proved reserves were distributed among 30 fields. Our
working interests in the fields range from 4% to 100%. We operate 10 of our 30
fields in the area. Six of our 21 top value properties are located in the area.
These six properties accounted for approximately 54% of the production from the
area during 2001 and 77% of our proved reserves in the area December 31, 2001.
Our California properties accounted for 29.6% of our proved reserves and
20.5% of our production for the year ended
4
December 31, 2001. At December 31, 2001, our proved reserves in the area were
distributed among 15 fields. Most of our producing wells in California benefit
from long production histories and well established decline curves.
Additionally, we have benefited from a net sales price for our natural gas
production in this area that has consistently exceeded NYMEX natural gas prices.
Our working interests in California range from approximately 2.5% to 100% with
an average working interest of 57%. We operate 9 of our 15 fields in the area.
Four of our 21 top value properties are located in California. We operate all
four of these properties, which account for approximately 59.0% of the
production from the area during 2001 and 95.6% of our proved reserves in the
area at December 31, 2001. Recently, we identified approximately 57 behind pipe
objectives in existing well bores that we believe represent significant reserve
potential in addition to our proved reserves. We conducted a 3-D seismic survey
covering approximately 33 square miles of our leasehold, which was completed in
January 2002. We anticipate that the 3-D seismic survey will confirm specific
locations for previously identified development prospects and may additionally
yield opportunities to drill exploratory wells in our Grimes and Sutter City
fields. Our $4.6 million capital budget for the area during 2002 includes
recompletion and low-risk development drilling projects targeting 12.2 Bcfe of
proved undeveloped reserves.
The following table and discussion provides proved reserves, PV-10 values,
2001 production and descriptive information for our three core areas and the
principal properties within each core area. These principal properties accounted
for approximately 91.2% of our estimated proved reserves at December 31, 2001.
These same properties accounted for 74.5% of our total oil and natural gas
production during 2001, averaging 31.3 MMcfe per day.
Net Proved % of Net
Reserves % of Net Proved
Field (Mmcfe)(1) PV-10 Value(1) Production(2) Reserves(1)
-------------------------------- ------------------ --------------------- ------------------ ------------------
(in thousands)
Onshore Gulf Coast:
Hastings Complex............. 53,803 $ 26,480 27.3% 28.1%
Constitution................. 7,179 8,138 11.1 3.7
Word......................... 9,981 7,414 1.1 5.2
AWP.......................... 5,212 1,412 2.0 2.7
Clear Branch................. 10,258 9,001 1.2 5.4
Sour Lake.................... 1,996 1,957 2.5 1.0
Scott........................ 2,104 3,685 4.0 1.1
North Alvin.................. 1,500 2,129 0.9 0.8
South Liberty................ 5,577 3,800 2.3 2.9
Barber's Hill................ 5,098 6,101 0.4 2.7
McFaddin..................... 2,053 1,634 0.4 1.1
Other........................ 9,748 8,125 9.3 5.1
---------- ------------- -------- --------
Subtotal.............. 114,510 79,876 62.6 59.7
Offshore Gulf Coast:
South Pass 27................ 5,781 5,296 0.1 3.0
Eugene Island 277............ 922 931 2.6 0.5
South Timbalier 162.......... 2,687 1,632 1.5 1.4
South Marsh Island 255....... 2,530 3,773 3.9 1.3
High Island 537.............. 2,414 2,944 0.0 1.3
Matagorda Island A-4......... 1,426 1,677 1.1 0.7
Other........................ 4,625 (985) 7.8 2.4
---------- ------------ -------- --------
Subtotal.............. 20,385 15,268 16.9 10.6
California:
Sutter Buttes................ 24,899 14,832 4.9 13.0
Grimes ...................... 8,231 9,787 4.6 4.3
Sycamore..................... 17,575 15,636 1.9 9.2
Greeley...................... 3,543 5,520 0.7 1.8
Other ...................... 2,512 2,886 8.4 1.3
---------- ------------- -------- --------
Subtotal.............. 56,759 48,661 20.5 29.6
---------- ------------- -------- --------
Total................. 191,654 $ 143,805 100.0% 100.0%
========== ============= ========= =========
- ----------
(1) Based on our PV-10 Value and proved reserve estimates as of December 31,
2001.
(2) For the twelve months ended December 31, 2001
5
Onshore Gulf Coast
Hastings Complex. The Hastings Complex includes three fields, encompasses
approximately 8,800 gross acres and is located approximately 30 miles south of
Houston in Brazoria County, Texas. In March 1998 we acquired working interests
in the three fields ranging from 68.3% to 100%. The fields produce from multiple
Miocene and Frio reservoirs at depths ranging from 2,000 feet to 7,000 feet. At
the time of our acquisition, the fields had produced in excess of 4,351 Bcfe
since discovery in 1934 by Stanolind Oil and Gas Co. Net production from the
fields was approximately 11,484 Mcfe per day during 2001.
Since assuming operations in August 1998, we have increased production and
reduced operating expenses in the field. We were able to achieve this with
minimal capital investment by re-engineering the field's artificial lift system,
exploiting behind pipe opportunities and eliminating uneconomic wells. At
December 31, 2001 we had proved reserves of 53,803 MMcfe. During 2002, we intend
to continue our production and cost optimization efforts and drill one proved
undeveloped Frio location.
Constitution Field. In March 1998 we acquired our working interests in the
Constitution field, which is located in Jefferson County, Texas. Our working
interests range from 25.0% to 100.0%. The field produces from the Yegua
reservoir at depths ranging from 13,500 feet to 15,011 feet. As of the date we
assumed operations, the net daily production from the field was approximately
339 Mcfe. During 2000 we recompleted our Westbury Farms #1 well to the Yegua
Sand and then fracture stimulated the reservoir. Initial net production after
stimulation was approximately 10,013 Mcfe per day. Our success in the Westbury
Farms #1 resulted in reserve additions from four additional proved undeveloped
locations. Net daily production from the Constitution field during 2001 was
4,672 Mcfe and at December 31, 2001 we had proved reserves of 7,179 MMcfe.
During 2002 we intend to drill two proved undeveloped Yegua locations.
Word Field. The Word field is located in Lavaca County, Texas and produces
from the Lower Wilcox and Edwards Limestone reservoirs at depths from 8,100 feet
to 13,200 feet. In March 1998 we acquired working interests that range from
87.5% to 100.0%. At the time of our acquisition, the field had produced over 47
Bcfe since its discovery in 1944 and was then producing at a net daily rate of
702 Mcfe per day. Net daily production from the field during 2001 averaged 447
Mcfe per day and at December 31, 2001 we had proved reserves of 9,981 MMcfe,
including reserves from one proved behind pipe objective and five proved
undeveloped Edwards locations.
AWP Field. Our interest in the AWP field covers 5,144 acres in McMullen
County, Texas. The field produces from the Olmos and Wales reservoirs at depths
ranging from 5,775 feet to 8,950 feet. In March 1998 we acquired our working
interest in the field, which ranges from 97.2% to 100.0%. At the time of our
acquisition, the field had produced over 430 Bcfe since its discovery in 1981.
Net daily production from our acreage in the field in 2001 averaged
approximately 829 Mcfe and we had proved reserves of 5,212 MMcfe at December 31,
2001, including reserves attributable to eight proved undeveloped Olmos
locations. During recent years, the field has experienced a resurgence of
activity by other operators due to advances in fracture stimulation technology.
Consequently, we believe that significant low-risk drilling and refracturing
opportunities exist on our acreage.
Clear Branch Field. We acquired our working interests in the Clear Branch
field in July 1997. We operate the two active wells in the field and our working
interests range from 84.4% to 99.0%. The field produces from the Hosston
reservoir at depths ranging from 9,700 to 9,900 feet. Net daily production from
the wells during 2001 averaged approximately 486 Mcfe and we had proved reserves
of 10,258 MMcfe at December 31, 2001, including reserves attributable to two
proved undeveloped Hosston locations. Additional proved reserves are
attributable to two behind pipe objective that will be completed following
depletion of the current producing intervals.
Sour Lake Field. The Sour Lake field, discovered in 1902, is the second
oldest oil field in Texas. It is located 15 miles west of Beaumont, Texas in
Hardin County and produces from the Miocene, Frio and Yegua reservoirs at depths
ranging from 800 feet to 7,577 feet. Our acreage was acquired from Apache in
March 1998. Apache had acquired the acreage from Texaco, who discovered the
field. We own 100% of the working interest and mineral estate in fee under 930
acres in the field. Our largest contiguous lease position in the field, 815
acres, is situated over the structural high and is the field's most prolific
area. Net daily production from the field during 2001 averaged approximately
1,047 Mcfe and we had proved reserves of 1,996 MMcfe at December 31, 2001,
including reserves attributable to five proved behind pipe objectives and ten
proved undeveloped locations.
Scott Field. The Scott field is located in Lafayette Parish, Louisiana and
produces from the Stutes and Bol Mex
6
reservoirs at depths ranging from 11,500 feet to 15,200 feet. We acquired our
working interests, which range from 11.5% to 27.4% in June 1997. At the time of
our acquisition, the field had been on production since the 1980's and had
recovered over 11.0 Bcfe, but had never been exploited with the benefit of
modern 3-D seismic data and production had declined to 633 Mcfe per day. In the
fourth quarter of 1999, after completing a 3-D seismic evaluation, we drilled
the Falcon #2 and completed the well in the Bol Mex V reservoir. Net daily
production from the field during 2001 averaged approximately 1,685 Mcfe and we
had proved reserves of 2,104 MMcfe at December 31, 2001, including reserves
attributable to one proved behind pipe objective and one proved undeveloped Bol
Mex location. During 2002, our capital budget provides $275,000 for deepening
the Falcon #1 to recover net proved undeveloped reserves of 434 MMcfe.
North Alvin Field. In 1996, as part of the Reunion acquisition, we acquired
working interests ranging from 34.3% to 41.6% in the North Alvin field, located
in Brazoria County, Texas. The field produces from Frio sandstones at depths
ranging from 7,900 feet to 8,600 feet. At the time of our acquisition the field
had produced over 28.4 Bcfe. Net daily production from the field in 2001
averaged approximately 375 Mcfe and we had proved reserves of 1,500 MMcfe at
December 31, 2001. The proved reserves in the field include undeveloped reserves
attributable to four reservoirs that we believe can be accessed by one drilling
well.
South Liberty Field. The South Liberty field is located 35 miles east of
Houston in Liberty County, Texas. We own a 100% working interest in the field.
We acquired our interest in South Liberty in March 1998 and at the time of the
acquisition the field had produced over 632 Bcfe since its discovery in 1925.
The field produces from Miocene, Frio, Yegua and Cook Mountain reservoirs at
depths ranging from 1,500 feet to 11,000 feet. Net daily production from the
field during 2001 averaged approximately 977 Mcfe and we had proved reserves of
5,577 MMcfe at December 31, 2001.
Barber's Hill Field. We acquired our 100% working interest in the Barber's
Hill field in 1998 with the Apache acquisition. Net daily production from the
field during 2001 averaged 187 Mcfe per day and we had 5,098 Mmcfe of proved
reserves at December 31, 2001, which includes one proved undeveloped Yegua
location. To further develop the Yegua sand reserves in the field, a 3-D seismic
program completed in 2001 delineated this PUD location, offsetting previous
Texaco Yegua wells in the field.
McFaddin Field. The McFaddin Field was acquired in the Apache acquisition in
1998. We own a 100% working interest in the deep rights of the field. Net daily
production from the field during 2001 averaged 186 Mcfe and we had 2,053 Mmcfe
of proved reserves in the field at December 31, 2001. Included in our reserves
are 13 identified behind-pipe opportunities and two proved undeveloped
locations.
Offshore Gulf Coast
South Pass 27 Field. In 1997, we acquired non-operating working interests
ranging from 27% to 41% in the South Pass 27 field from Statoil. The field is
located in federal waters offshore Louisiana in approximately 120 feet of water.
We have proved reserves of 5,781 MMcfe at December 31, 2001. The proved reserves
in the field include undeveloped reserves attributable to nine reservoirs, to be
developed in two proved undeveloped locations and two recompletions.
Eugene Island 277 Field. We acquired a 100% working interest in the Eugene
Island 277 field in 1997. The field is located in federal waters offshore
Louisiana in approximately 300 feet of water. During 2001, we completed a
successful plug-back of the DU Sand in the #2 well to return the field to
production. Net daily production from the field during 2001 averaged
approximately 1,095 Mcfe and we had proved reserves of 922 MMcfe at December 31,
2001.
South Timbalier 162 Field. We acquired a 100% working interest in the South
Timbalier 162 Field in 1997. The field was originally developed by Shell Oil and
Amoco during the 1960's. Production has come from over 10 productive reservoirs
ranging from 6,000' to 10,000'. Net production during 2001 was 615 Mcfe per day
and we have 2,687 Mmcfe of reserves at December 31, 2001. We have three
reservoirs with proved behind pipe reserves in two wells currently shut-in.
South Marsh Island 255 Field. We own a 25% working interest in this Ocean
Energy operated field. We produced 1,645 Mcfe per of day during 2001 from this
dually-completed well and have 2,530 Mmcfe of proved reserves at December 31,
2001. The reserves include one non-producing plugback in the current wellbore.
High Island 537 Field. We own a 100% working interest in this field as a
result of a late 1997 acquisition. We have 2,414 Mmcfe behind-pipe reserves in
two reservoirs in one well in the field.
Matagorda Island A-4 Field. We own a 45% working interest in this one-well
field. During 2001, we produced 447 Mcfe per day and have net reserves of 1,426
Mmcfe in the field at December 31, 2001.
7
California
Sutter Buttes Field. Our largest contiguous operation in California is in
the Sutter Buttes field in northern California, located approximately 40 miles
north of Sacramento in Sutter and Colusa Counties. Our working interests range
from 53.2% to 100%. The Sutter Buttes field is comprised of over 43,000
contiguous gross acres of leasehold with approximately 60 producing wells, which
we operate. At December 31, 2001 we owned 38,000 net acres in the field. We have
extensive operating expertise in this area and significant experience with the
Forbes and Kione producing reservoirs. From November 1998 to February 2002, we
drilled 13 development wells targeting the Forbes and Kione reservoirs at depths
of 3,100 feet to 7,100 feet. Twelve of the wells were successful and resulted in
significant increases in our production and cash flow. Our net daily production
during 2001 averaged 2,064 Mcfe and our proved reserves at December 31, 2001
were 24,899 MMcfe. Our planned capital budget for 2002 includes $3.4 million to
drill 6 development wells targeting the Forbes reservoir and 6.6 Bcfe of net
proved undeveloped reserves. Additionally, we conducted a 3-D Seismic survey on
15 square miles in the Sutter City Field. The Sutter City leases have produced
exclusively from the shallower Kione sands. The 3-D seismic survey will evaluate
the deeper Forbes interval that has been prolific on our adjacent acreage.
Grimes Field. Our Grimes field, also acquired in 1996, is located to the
southwest of Sutter Buttes and also produces from the Forbes sandstone. Our
working interests range from 6.3% to 96.0%. Net daily production during 2001
averaged 1,952 Mcfe and we had proved reserves of 8,231 MMcfe at December 31,
2001. There has been limited development in the field during recent years.
During 2001 we successfully conducted an 18 square mile 3-D survey over our
acreage in the Grimes field. We believe that the 3-D survey will result in
multiple development and exploitation drilling opportunities similar to those
that we have completed in the Sutter Buttes area since late 1998.
Sycamore Field. We acquired our 80% working interest in this field in the
Reunion Acquisition in 1996. Net daily production from the field during 2001
averaged 780 Mcfe per day. This field has had significant plugback work
completed during 2001. Daily production volumes have increased substantially
during the last half of 2001. We have continued our workover efforts into 2002.
Proved reserves in the field are 17,575 Mmcfe at December 31, 2001, which
includes 20 PUD locations and 4 behind-pipe opportunities.
Greeley Field. The Greeley field is located in Kern County, California and
is our only oil producing property in California. We own an 85.4% working
interest in this field. Unlike most California properties, the Greeley field
produces light, sweet crude oil from the Olcese Sand at a depth of approximately
10,500 feet. Net daily production during 2001 averaged 292 Mcfe and we had
proved reserves of 3,543 MMcfe at December 31, 2001.
OIL AND NATURAL GAS RESERVES
The following table sets forth information with respect to our estimated net
proved oil and natural gas reserves and the related present values of such
reserves at the dates shown. The reserve and present value data for our existing
properties as of December 31, 1999 and 2000 was prepared by Huddleston & Co.,
Inc. and by DeGolyer and MacNaughton as of December 31, 2001.
At December 31,
-------------------------------------------------
1999 2000 2001
-------------- -------------- ---------------
Proved Developed Reserves
Oil and condensate (MBbls)................................ 12,957 12,290 11,306
Natural gas (MMcf)........................................ 58,265 45,575 45,767
Total (MMcfe).................................... 136,007 119,315 113,603
Proved Reserves:
Oil and condensate (MBbls)................................ 15,851 15,073 14,115
Natural gas (MMcf)........................................ 110,092 89,699 106,965
Total (MMcfe)............................................. 205,198 180,137 191,654
PV-10 Value (in thousands)(1)................................. $292,495 $630,002 $143,805
Standardized Measure (in thousands)(2)........................ $231,564 $472,279 $128,231
Reserve life (in years)....................................... 14.8 11.0 12.5
- ----------
(1) The average prices used in calculating PV-10 Value as of December 31, 2001
were $2.54 per Mcf and $18.53 per Bbl. Assuming the inclusion of average
swap prices of $3.96 per Mcf and $24.42 per Bbl through December 31, 2003
associated with hedged oil and natural gas volumes, our PV-10 Value would
have been $160,807 at December 31, 2001.
(2) Represents PV-10 Value adjusted for the effects of future estimated income
tax expense.
8
Effective February 1, 2001, we gained an incremental 3.3 Bcfe of proved
reserves, estimated at December 31, 2001, in our Hastings Complex due to the
resolution of certain litigation which resulted in an assignment of additional
interests.
Estimated quantities of proved reserves and future net revenues are affected
by oil and natural gas prices, which have fluctuated widely in recent years.
There are numerous uncertainties inherent in estimating oil and natural gas
reserves and their values, including many factors beyond the control of the
producer. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact manner. 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 of different engineers, including those used by us, may
vary. In addition, estimates of reserves are subject to revision based upon
actual production, results of future development and exploration activities,
prevailing oil and natural gas prices and operating costs. Accordingly, reserve
estimates are often different from the quantities of oil and natural gas that
are ultimately recovered and are highly dependent upon the accuracy of the
assumptions upon which they are based.
In general, the volume of production from oil and natural gas properties
declines as reserves are depleted. Except to the extent we acquire properties
containing proved reserves or conduct successful exploration and development
activities, or both, our proved reserves will decline as reserves are produced.
Our future oil and natural gas production is, therefore, highly dependent upon
our level of success in finding or acquiring additional reserves. Exploring for,
developing or acquiring new reserves requires substantial amounts of capital.
We file reports of our estimated oil and natural gas reserves with the
Department of Energy. The reserves reported to this agency are required to be
reported on a gross operated basis and therefore are not comparable to the
reserve data reported herein.
NET PRODUCTION, UNIT PRICES AND COSTS
The following table sets forth certain information with respect to oil and
natural gas production, prices and costs attributable to all of our oil and
natural gas property interests for the periods shown:
Years Ended December 31,
1999 2000 2001
------------ ------------- -------------
Production Volumes:
Oil and condensate (MBbls).................. 1,145 1,333 1,245
Natural gas (MMcf).......................... 7,007 8,314 7,869
Total (MMcfe)............................ 13,874 16,313 15,337
Average Daily Production:
Oil and condensate (Bbls)................... 3,136 3,643 3,410
Natural gas (Mcf)........................... 19,196 22,716 21,559
Total (Mcfe)............................. 38,011 44,574 42,017
Average Realized Prices: (1)
Oil and condensate (per Bbl)................ $ 17.27 $ 28.95 $ 25.81
Natural gas (per Mcf)....................... 2.36 4.19 6.15
Per Mcfe................................. 2.61 4.50 5.25
Expenses (per Mcfe):
Lease operating (excluding workover
expenses and production taxes)........... $ 1.12 $ 1.19 $ 1.30
Workover.................................... 0.17 0.41 0.39
Production taxes............................ 0.05 0.12 0.11
Depletion, depreciation and amortization.... 0.80 0.83 0.79
General and administrative, net............. 0.38 0.27 0.45
- ----------
(1) Reflects the actual realized prices received, including the results of
hedging activities. Please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
9
PRODUCING WELLS
The following table sets forth the number of productive wells in which we
owned an interest as of December 31, 2001:
Gross Wells Net Wells
----------- ---------
Oil..................................... 447.0 285.4
Natural gas............................. 182.0 90.4
------ ------
Total.......................... 629.0 375.8
===== =====
Productive wells consist of producing wells and wells capable of production,
including natural gas wells awaiting pipeline connections and oil wells awaiting
connection to production facilities. Wells that are completed in more than one
producing horizon are counted as one well.
ACREAGE
The following table sets forth our developed and undeveloped gross and net
leasehold acreage as of December 31, 2001:
Gross Net
----- ---
Developed............................... 14,770 9,377
Undeveloped............................. 217,543 91,339
------- -------
Total.............................. 232,313 100,716
======= =======
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether or not such acreage
contains proved reserves.
DRILLING ACTIVITIES
The table below sets forth our drilling activity on our properties for the
periods ending December 31, 1999, 2000, and 2001:
Years Ended December 31,
---------------------------------------------------------------------------------
1999 2000 2001
------------------------- ------------------------- -------------------------
Gross Net Gross Net Gross Net
----------- ----------- ----------- ----------- ----------- -----------
Development wells:
Productive........................... 4.00 2.38 5.00 3.95 5.00 1.66
Non-productive....................... 3.00 1.70 - - - -
----------- ----------- ----------- ----------- ----------- -----------
Total....................... 7.00 4.08 5.00 3.95 5.00 1.66
=========== =========== =========== =========== =========== ===========
Exploratory wells:
Productive........................... - - 1.00 0.15 - -
Non-productive....................... - - - - - -
----------- ----------- ----------- ----------- ----------- -----------
Total....................... - - 1.00 0.15 - -
=========== =========== =========== =========== =========== ===========
OIL AND NATURAL GAS MARKETING AND HEDGING
The revenues generated by our operations are highly dependent upon the
prices of and demand for oil and natural gas. The price we receive for our oil
and natural gas production depends on numerous factors beyond our control.
Historically the markets for oil and natural gas have been volatile and are
likely to continue to be volatile in the future. Prices for oil and natural gas
are subject to wide fluctuation in response to relatively minor changes in the
supply and demand for oil and natural gas, market uncertainty and a variety of
additional factors. These factors include the level of consumer product demand,
weather conditions, domestic and foreign governmental regulations, the price and
availability of alternative fuels, political conditions in the Middle East, the
actions of OPEC, the foreign supply of oil and natural gas and overall economic
conditions. It is impossible to predict future oil and natural gas price
movements with any certainty.
We, from time to time, use swap and option contracts to mitigate the
volatility of price changes on commodities we produce and sell, as well as to
lock in prices to protect the economics related to certain capital projects.
At December 31, 2001, approximately 80% of our projected oil and natural gas
production from proved developed
10
producing reserves (and the basis differential attributable to approximately
80% of our projected proved developed producing natural gas production from our
California properties) is hedged through December 31, 2003 at swap prices that
average $3.96 per Mcf and $24.42 per Bbl, or a weighted-average natural
gas-equivalent price of approximately $4.01 per Mcfe. In connection with the
issuance of the notes, we agreed to maintain, on a monthly basis, a rolling
two-year hedge program until the maturity of the notes, subject to certain
conditions. In March 2002, we terminated certain of our derivatives contracts
and replaced them with contracts providing for price floors at the prices
specified required under the terms of the senior secured notes of $2.75 per
MMBtu of natural gas (Henry Hub) and $18.50 per barrel of crude oil (West Texas
Intermediate).
The table below sets forth the results of our hedge for the period ending
December 31, 2001. Our production was not hedged at December 31, 2000:
Hedged Unhedged Total
------------ ------------- -------------
Production Volumes:
Oil and condensate (MBbls)............................. 516 729 1,245
Natural gas (MMcf)..................................... 3,326 4,543 7,869
Total (MMcfe)....................................... 6,422 8,915 15,337
Average Realized Prices:
Oil and condensate (per Bbl)........................... $ 25.30 $ 26.16 $ 25.81
Natural gas (per Mcf).................................. 4.23 7.55 6.15
Per Mcfe............................................ 4.22 5.99 5.25
Revenue: (in thousands)
Oil and condensate..................................... $13,059 $ 19,067 $ 32,126
Natural gas............................................ 14,069 34,321 48,390
Total............................................... 27,128 53,388 80,516
RISKS RELATING TO OUR BUSINESS, FINANCES AND OPERATIONS
Our bankruptcy may adversely affect our ability to conduct our future
operations.
On June 18, 2001, we exited bankruptcy under Chapter 11 of the U.S.
Bankruptcy Code. Our prior bankruptcy may adversely affect the conduct of our
future operations by causing vendors and others from whom we purchase goods or
services to be reluctant to do business with us. These vendors may request
payment in advance, refuse to extend us credit, or give us terms less favorable
than our competitors. We currently do business with certain vendors that require
us to pay in advance for goods or services. These limitations make us more
susceptible to timing differences between our receipt of payment and our
expenditures, which requires us to carefully manage our collections and
disbursements, and may hinder our ability to adjust rapidly to changing market
conditions. In addition, our recourse to bankruptcy protection were we to
require it is limited for the 6 years following the date we filed bankruptcy,
March 14, 2000, unless we waive the benefits of our past discharge.
Our significant leverage and lack of capital resources may affect our ability to
successfully operate and service our debt obligations.
Our level of indebtedness as of December 31, 2001, was $110.1 million as
compared to adjusted EBITDA for the year ended December 31, 2001 of $71.2
million. Under the indenture we are permitted to incur, subject to certain
conditions, up to $20.0 million of additional secured debt through the issuance
of additional notes and additional amounts by other means.
Our level of indebtedness and lack of capital resources could have several
important effects on our future operations, which in turn could have important
consequences to you as a holder of the notes, including, without limitation:
o impairing our ability to obtain additional financing for working
capital, capital expenditures or general corporate or other purposes in
the future;
o placing us at a competitive disadvantage relative to competitors that
have less indebtedness, by requiring us to dedicate a substantial
portion of our cash flow from operations to payments on our indebtedness
and thereby reducing the availability of our cash flow to fund working
capital, capital expenditures, general corporate expenditures and other
purposes;
o causing us to be unable to satisfy our amortization payments due on the
notes on June 1, 2002, 2003 and 2004;
11
o causing us to be unable to repurchase, upon a change of control, all of
the outstanding notes, together with any accrued and unpaid interest to
the date of repurchase;
o causing us to be unable to repurchase notes pursuant to an asset sale
offer or an excess cash flow offer; and
o limiting or hindering our ability to adjust rapidly to changing market
conditions, making us more vulnerable in the event of a downturn in
general economic conditions or our business.
Our ability to make scheduled payments of principal and interest with
respect to our indebtedness, including the notes, or to refinance such
obligations will depend on our financial and operating performance, which, in
turn, will be subject to prevailing economic conditions and to certain
financial, business and other factors beyond our control. If our near-term cash
flow is consumed by our debt service, we may be forced to reduce or delay
planned capital expenditures, sell assets, obtain additional equity capital or
attempt to restructure our indebtedness.
Historically, we have financed acquisition, exploration and development
activities primarily through various credit facilities and with internally
generated funds. Our ability to expend the capital necessary to undertake or
complete future activities may be limited and we may not have adequate funds
available to us to carry out our growth strategy. Please read "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources," beginning on page 23, and our consolidated
financial statements and the related notes.
Our estimates of oil and natural gas reserves and future net revenue are
uncertain and inherently imprecise.
This prospectus contains estimates of our proved reserves and the estimated
future net revenues from our proved reserves. Estimating oil and natural gas
reserves and their values involves numerous uncertainties, including many
factors beyond our control. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and natural gas, which cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves and of future net revenues necessarily depend upon a number
of variable factors and assumptions, including the following:
o historical production from the area compared with production from other
producing areas;
o the assumed effects of regulation by governmental agencies; and
o assumptions concerning future oil and natural gas prices, future
operating costs, severance and excise taxes, development costs and
workover and remedial costs.
Because of the variable factors and assumptions involved in the estimation
of reserves, different engineers or the same engineers at different times may
reach substantially different results in their estimates of the economically
recoverable quantities of oil and natural gas attributable to any particular
group of properties, their classification of reserves based on risk recovery and
their estimates of the future net revenues expected from reserves. In addition,
reserve estimates may be adjusted downward or upward because of changes in such
factors and assumptions.
Because all reserve estimates are subjective to some degree, each of the
following items may differ materially from those assumed in the estimated
reserves:
o the quantities of oil and natural gas that are ultimately recovered;
o the production and operating costs incurred;
o the amount and timing of future development expenditures; and
o future oil and natural gas prices.
The present values of estimated future net revenues referred to in this
prospectus should not be construed as the current market value of the estimated
oil and natural gas reserves attributable to our properties. In accordance with
applicable requirements of the SEC, the estimated discounted future net revenues
from proved reserves are generally based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower. Actual future net revenues also will be affected by factors such as:
o the amount and timing of actual production;
12
o supply and demand for oil and natural gas;
o curtailments or increases in consumption by natural gas purchasers; and
o changes in governmental regulations or taxation.
The timing of actual future net revenues from proved reserves, and their
actual present value, will be affected by both the timing of the production and
the incurrence of expenses in connection with development and production of oil
and natural gas properties. In addition, the calculation of the present value of
the future net revenues using a 10% discount, as required by the SEC, is not
necessarily the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with our reserves or the oil and
natural gas industry in general.
Oil and natural gas prices are volatile. A decline in prices could adversely
affect our financial results, cash flows, access to capital and ability to pay
debt.
The price we receive for our oil and natural gas production has a
significant effect on our financial results, profitability, future rate of
growth and the carrying value of our oil and natural gas properties. Prices also
affect the amount of cash flow available to pay debt, to make capital
expenditures and our ability to borrow money or obtain other forms of financing.
Historically, prices for oil and natural gas have been volatile and may continue
to be volatile in the future. Additionally, oil and natural gas prices may vary
significantly by geographic region and have been particularly volatile in
California where much of our natural gas is produced and sold. Wide fluctuations
in oil and natural gas prices may result from relatively minor changes in the
supply of and demand for oil and natural gas, market uncertainty and other
factors beyond our control including:
o worldwide and domestic supplies of oil and natural gas;
o weather conditions;
o the level of consumer demand;
o the price and availability of alternative fuels;
o the availability of pipeline capacity;
o the price and level of foreign imports;
o domestic and foreign governmental regulations and taxes;
o the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;
o political instability or armed conflict in oil producing regions; and
o the overall economic environment.
These factors and the volatility of the energy markets generally make it
extremely difficult to predict future oil and natural gas price movements with
any certainty. Declines in oil and natural gas prices would not only reduce
revenue, but could reduce the amount of oil and natural gas that we can produce
economically and, as a result, could adversely effect both our financial
condition and our oil and natural gas reserves. Recent weaknesses in commodity
prices has contributed to declines in our cash flows which, in conjunction with
out debt service obligations, has caused us to limit our capital expenditures.
Please read "Management's Discussion and Analysis of Financial Condition and
Results of Operation - Liquidity and Capital Resources", beginning on page 23,
and our consolidated financial statements and the related notes.
Drilling involves numerous risks, including the risk that no commercially
productive oil or natural gas reservoirs will be encountered.
Our success is significantly affected by risks associated with drilling and
other operational activities. We do not ourselves conduct the actual drilling
operations, but hire drilling companies at standard industry rates. Perhaps the
most
13
significant drilling risk is the risk that no oil or natural gas will be found
that can be produced at a profit. New wells we drill may be unproductive or we
may not be able to recover all or any portion of our investment in wells
drilled. The seismic data and other technologies we may use do not allow us to
know conclusively prior to drilling a well that oil or natural gas is present or
may be produced economically. The cost of drilling, completing and operating a
well is often uncertain, and cost factors can adversely affect the economics of
a project. Our efforts will be unprofitable if we drill dry holes or wells that
are productive but do not produce enough reserves to return a profit after
drilling, operating and other costs. If we are not successful in finding
productive oil and natural gas reservoirs or drilling productive oil and natural
gas wells, or if drilling costs are significantly higher than projected, our
financial results may suffer. Further, drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors, including the
following:
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents;
o adverse weather conditions;
o compliance with environmental and other governmental requirements;
o title problems; and
o costs of, shortages of or delays in the availability or delivery of
equipment or qualified operating personnel.
Hedging transactions may limit our potential profits from operations.
To manage our exposure to price risks in the marketing of our oil and
natural gas production, we have in the past and will be required in the future
under the terms of the indenture, subject to certain conditions, to enter into
oil and natural gas price hedging arrangements with respect to a portion of our
expected production. Our hedging arrangements may include futures contracts on
the NYMEX. Our hedging transactions may limit our potential profits if oil and
natural gas prices were to rise substantially over the price established by the
hedge.
Hedging transactions may expose us to the risk of loss in certain
circumstances, including instances in which:
o our production is materially less than expected;
o there is volatility of price differentials between delivery points for
our production and the delivery point assumed in the hedge arrangement
or the sales prices for the quality of our oil and natural gas and the
sales price of the quality assumed in the hedge; or
o the counterparties to our future contracts fail to perform the
contracts.
If we are unable to adequately replace our reserves, our ability to sustain
production and our long-term financial performance will be adversely impacted.
The volume of production from oil or natural gas properties generally
decreases as more oil and natural gas is produced from a property and reserves
are depleted. The rate at which the decrease occurs depends upon the geologic
characteristics of a particular property. If we do not find new oil and natural
gas production either by our exploration and development efforts or acquisition,
then our proved reserves will decrease as we produce oil and natural gas. Our
future oil and natural gas production rates are therefore highly dependent upon
our level of success in finding, developing or acquiring additional reserves.
Finding, developing or acquiring additional reserves requires significant
capital expenditures. At December 31, 2001, approximately 41% of our total
estimated proved reserves were undeveloped. By their nature, undeveloped
reserves are less certain than developed reserves and recovery of such reserves
will require greater capital expenditures and successful drilling operations. If
we do not make significant capital expenditures, we may not be able to replace
produced reserves.
Historically, we have funded our capital expenditures primarily through
various credit facilities and with internally generated funds. Future cash flows
are subject to a number of variables, such as the level of production from
existing wells, prices of oil and natural gas and our success in developing and
producing new reserves. If revenue were to decrease as a result of lower oil and
natural gas prices or decreased production, and our access to capital were
limited,
14
we would have a reduced ability to replace our reserves. Due to our limited
capital resources and required debt repayment, if revenue were to decrease as a
result of lower oil and natural gas prices or decreased production, we might not
be able to make sufficient capital investments to replace our oil and natural
gas reserves. Even if funds are available, we may not be able to successfully
find, develop or acquire additional oil and natural gas proved reserves that are
economically recoverable.
Our business involves operating hazards and uninsured risks.
Our drilling and production and other operations, and the transportation of
production by others, also involve a number of hazards and risks such as fires,
natural disasters, explosions, blowouts and spills. If any of these risks occur,
we could sustain substantial losses as a result of:
o injury or loss of life;
o severe damage or destruction to property, natural resources and
equipment;
o pollution or other environmental damage;
o clean-up responsibilities;
o regulatory investigations and penalties; and
o suspension of operations.
We are not fully insured against some of these risks, either because the
insurance is not available or because of high premium costs. If a significant
accident or other event happens and is not fully covered by insurance, we could
be required to pay some or all of the costs associated with the accident or
event, which may require us to divest resources needed for other purposes. Also,
we cannot predict the continued availability of insurance at premium levels
that, in our sole discretion, justify its purchase.
Our industry is extremely competitive and many of our competitors have superior
resources.
The energy industry is extremely competitive. This is especially true with
regard to exploration for, and development and production of, new sources of oil
and natural gas. As an independent producer of oil and natural gas, we encounter
substantial competition in acquiring properties suitable for exploration, in
contracting for drilling equipment and other services, in marketing oil and
natural gas and in securing trained personnel. We frequently compete against
companies that have substantially larger financial resources, staffs and
facilities. If we directly compete against one of those larger companies in a
desired acquisition of oil and natural gas properties or in the hiring of
experienced and skilled personnel, we may not have the resources available to
obtain the desired result.
We depend heavily on the services of key personnel and the loss of their
services could have an adverse effect on our ability to operate.
We depend to a large extent on the services of Richard Bowman, Jeffrey T.
Janik and Suzanne R. Ambrose. The loss of the services of these key personnel
could impair our ability to manage our business and properties. We do not
currently have employment contracts with these key personnel and do not
currently maintain key man life insurance on their lives. We believe that our
success is also dependent upon our ability to continue to employ and retain
skilled technical personnel.
Higher oil and natural gas prices adversely affect the cost and availability of
drilling and production services.
Higher oil and natural gas prices generally stimulate increased demand and
result in increased prices for drilling rigs, crews and associated supplies,
equipment and services. We have occasionally experienced significantly higher
costs and reduced availability for drilling rigs and other related services.
Our operations are subject to significant government regulation that may change
over time.
Our oil and natural gas operations are subject to various federal, state and
local governmental laws and regulations that may change in response to economic
or political conditions. Matters subject to regulation include discharge permits
for drilling operations, drilling and abandonment bonds or other financial
responsibility requirements, reports concerning
15
operations, the spacing of wells, utilization and pooling of properties,
taxation and the environment. From time to time, regulatory agencies have
imposed price controls and production limitations to conserve supplies of oil
and natural gas. A significant portion of our production of natural gas is from
our properties in the Sacramento Basin in California. As a result of the recent
energy crises in California, certain bills are currently being considered by the
California legislature which could impose civil and criminal penalties on
producers of natural gas or electric power who curtail production or sell energy
"at prices above marginal cost." We cannot determine at this time the effect, if
any, that such legislation, were it enacted, would have on our operations. We
are not aware that any similar legislation is currently proposed by any other
state in which we operate.
In addition, the production, handling, storage, transportation and disposal
of oil and natural gas, their by-products and other substances and wastes
generated, produced or used in connection with oil and natural gas operations
are regulated under federal, state and local laws and regulations relating to
the protection of health and the environment. These laws and regulations may
impose increasingly strict requirements for water and air pollution control,
spill cleanups and solid waste management. Our failure to meet any of the
foregoing requirements could result in a suspension of our operations, as well
as administrative, civil, and even criminal penalties.
We may not be able to profitably sell all of the oil and natural gas we produce.
The marketability of our oil and natural gas production depends upon the
availability and capacity of natural gas gathering systems, pipelines and
processing facilities. If such capacity is not available, we might have to
shut-in producing wells or delay or discontinue development plans for
properties. In addition, federal and state regulation of oil and natural gas
production and transportation, general economic conditions and changes in supply
and demand could adversely affect our ability to produce and market our oil and
natural gas on a profitable basis.
Our earnings may not be sufficient to cover fixed charges.
For purposes of computing the ratio of earnings to fixed charges, earnings
are computed as income after reorganization costs and before income taxes plus
interest expense, including amortization of premiums, discounts, and capitalized
expenses related to indebtedness. Fixed charges represent interest expense
(including amortization of deferred finance charges and an estimated portion of
rentals representing interest costs). Our earnings were insufficient to cover
fixed charges by $15.8 million, $9.2 million and $5.8 million for the years
ended December 31, 1998, 1999 and 2000, respectively. Earnings of $16.5 million
for the year ended December 31, 2001, were sufficient to cover fixed charges.
If, in the future, our earnings are insufficient to cover our fixed charges, we
may be unable to satisfy our obligations under the notes and indenture or may be
required to dedicate a substantial portion of our cash reserves and other
resources to cover these charges, reduce or delay planned capital expenditures,
sell assets, obtain additional equity capital or attempt to restructure our
indebtedness.
Competition and Markets
Competition in intense in all areas of our operations. Major and independent
oil and natural gas companies and oil and natural gas syndicates actively bid
for desirable oil and natural gas properties, as well as for the equipment and
labor required to operate and develop such properties. Many of our competitors
have financial resources and acquisition, exploration and development budgets
that are substantially greater than ours, which may adversely affect our ability
to compete with these companies. Many of our competitors have been engaged in
the energy business for a much longer time than us. Such companies may be able
to pay more for productive oil and natural gas properties and exploratory
prospects and to define, evaluate, bid for and purchase a greater number of
properties and prospects that our financial or human resources permit. Our
ability to acquire additional properties and to discover reserves in the future
will depend on our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment.
The market for oil and natural gas produced by us depends on factors beyond
our control, including domestic and foreign political conditions, the overall
level of supply of and demand for oil and natural gas, the price of imports of
oil and natural gas, weather conditions, the price and availability of
alternative fuels, the proximity and capacity of natural gas pipelines and other
transportation facilities and overall economic conditions. The oil and natural
gas industry as a whole also competes with other industries in supplying the
energy and fuel requirements of industrial, commercial and individual consumers.
REGULATION
General. Various aspects of our oil and natural gas operations are subject
to extensive and continually changing
16
regulation, as legislation affecting the oil and natural gas industry is under
constant review for amendment or expansion. Numerous departments and agencies,
both federal and state, are authorized by statute to issue, and have issued,
rules and regulations binding upon the oil and natural gas industry and its
individual members. The Federal Energy Regulatory Commission ("FERC") regulates
the transportation and sale of natural gas in interstate commerce pursuant to
the Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978
("NGPA"). In the past, the federal government has regulated the prices at which
oil and natural gas could be sold. While sales by producers of natural gas and
all sales of crude oil, condensate and natural gas liquids can currently be made
at uncontrolled market prices, Congress could reenact price controls in the
future. Deregulation of wellhead sales in the natural gas industry began with
the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural Gas
Wellhead Decontrol Act (the "Decontrol Act"). The Decontrol Act removed all
remaining NGA and NGPA price and nonprice controls affecting wellhead sales of
natural gas effective January 1, 1993.
Regulation of Sales and Transportation of Natural Gas. Our sales of natural
gas are affected by the availability, terms and cost of transportation. The
price and terms for access to pipeline transportation are subject to extensive
regulation. In recent years, the FERC has undertaken various initiatives to
increase competition within the natural gas industry. As a result of initiatives
like FERC Order No. 636, issued in April 1992, the interstate natural gas
transportation and marketing system has been substantially restructured to
remove various barriers and practices that historically limited non-pipeline
natural gas sellers, including producers, from effectively competing with
interstate pipelines for sales to local distribution companies and large
industrial and commercial customers. The most significant provisions of Order
No. 636 require that interstate pipelines provide firm and interruptible
transportation service on an open access basis that is equal for all natural gas
supplies. In many instances, the results of Order No. 636 and related
initiatives have been to substantially reduce or eliminate the interstate
pipelines' traditional role as wholesalers of natural gas in favor of providing
only storage and transportation services. While the United States Court of
Appeals upheld most of Order No. 636, certain related FERC orders, including the
individual pipeline restructuring proceedings, are still subject to judicial
review and may be reversed or remanded in whole or in part. While the outcome of
these proceedings cannot be predicted with certainty, we do not believe that we
will be affected materially differently than our competitors.
The FERC has also announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-service
rate making methodology to establish the rates interstate pipelines may charge
for their services. A number of pipelines have obtained FERC authorization to
charge negotiated rates as one such alternative. In February 1997, the FERC
announced a broad inquiry into issues facing the natural gas industry to assist
the FERC in establishing regulatory goals and priorities in the post-Order No.
636 environment. Similarly, the Texas Railroad Commission has been reviewing
changes to its regulations governing transportation and gathering services
provided by intrastate pipelines and gatherers. While the changes being
considered by these federal and state regulators would affect us only
indirectly, they are intended to further enhance competition in natural gas
markets. We cannot predict what further action the FERC or state regulators will
take on these matters, however, we do not believe that any action taken will
affect us materially differently than other natural gas producers with whom we
compete.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue.
Oil Price Controls and Transportation Rates. Our sales of crude oil,
condensate and natural gas liquids are not currently regulated and are made at
market prices. The price we receive from the sale of these products may be
affected by the cost of transporting the products to market.
Environmental Matters. Extensive federal, state and local laws regulating
the discharge of materials into the environment or otherwise relating to the
protection of the environment affect our oil and natural gas operations.
Numerous governmental departments issue rules and regulations to implement and
enforce such laws, which are often difficult and costly to comply with and which
carry substantial administrative, civil and even criminal penalties for failure
to comply. These laws, rules and regulations may require the acquisition of
certain permits, restrict or prohibit the types, quantities and concentration of
substances that can be released into the environment in connection with drilling
and production, restrict or prohibit drilling activities that could impact
wetlands, endangered or threatened species or other protected natural resources
and impose substantial liabilities for pollution resulting from our operations.
Some laws, rules and regulations relating to protection of the environment may,
in certain circumstances, impose strict liability for environmental
contamination, rendering a person liable for environmental damages and cleanup
costs without regard to negligence or fault on the part of such person. Other
laws, rules and regulations may restrict the rate of oil and natural gas
production below the rate that would otherwise exist. In addition, state laws
often require various forms of remedial
17
action to prevent pollution, such as closure of inactive pits and plugging of
abandoned wells. The regulatory burden on the oil and natural gas industry
increases our cost of doing business and consequently affects our profitability.
We believe that we are in substantial compliance with current applicable
environmental laws, rules and regulations, that we have no material commitments
for capital expenditures to comply with existing environmental requirements and
that continued compliance with existing requirements will not have a material
adverse impact on our operations. However, environmental laws, rules and
regulations have been subject to frequent changes over the years, and the
imposition of more stringent requirements could have a material adverse effect
upon our capital expenditures, earnings or competitive position as well as those
of the oil and gas industry in general.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund Law," and analogous state laws impose
liability without regard to fault or the legality of the original conduct on
certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include
the current or former owner or operator of the site or sites where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site. Under CERCLA, such persons may be
subject to joint and several liability for the costs of investigating and
cleaning up hazardous substances that have been released into the environment,
for damages to natural resources and for the costs of certain health studies. In
addition, companies that incur liability frequently also confront third party
claims because it is not uncommon for neighboring landowners and other third
parties to file claims for personal injury and property damage allegedly caused
by hazardous substances or other pollutants released into the environment.
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation,
transportation, storage, treatment and disposal of hazardous wastes and can
require cleanup of hazardous waste disposal sites. RCRA currently excludes
drilling fluids, produced waters and other wastes associated with the
exploration, development or production of oil and natural gas from regulation as
"hazardous waste." Disposal of such non-hazardous oil and natural gas
exploration, development and production wastes usually are regulated by state
law. Other wastes handled at exploration and production sites or generated in
the course of providing well services may not fall within this exclusion.
Moreover, stricter standards for waste handling and disposal may be imposed on
the oil and natural gas industry in the future. From time to time legislation is
proposed in Congress that would revoke or alter the current exclusion of
exploration, development and production wastes from the RCRA definition of
"hazardous wastes" thereby potentially subjecting such wastes to more stringent
handling, disposal and cleanup requirements. State initiatives to further
regulate the disposal of oil and natural gas wastes and naturally occurring
radioactive materials could have a similar impact on us. If such legislation
were enacted it could have a significant impact on our operating costs, as well
as those of the oil and natural gas industry in general. The impact of future
revisions to environmental laws and regulations cannot be predicted.
We own or lease, and have in the past owned or leased, properties that have
been used for the exploration and production of oil and natural gas. Although we
have utilized operating and disposal practices that were standard in the
industry at the time, hydrocarbons or other wastes may have been disposed of or
released on or under these properties or on or under other locations where such
wastes have been taken for storage or disposal. In addition, many of these
properties have been operated by third parties whose treatment and release of
hydrocarbons or other wastes was not under our control. These properties and the
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, we could be required to remove or remediate previously released
wastes or property contamination.
The Oil Pollution Act of 1990 ("OPA") and rules and regulations promulgated
pursuant thereto impose a variety of obligations on "responsible parties" with
respect to the prevention of oil spills and liability for damages resulting from
such spills. A "responsible party" includes the owner or operator of an onshore
facility, vessel, or pipeline or the lessee or permittee of the area in which an
offshore facility is located. Under OPA, a person owning or operating a facility
from which there is a discharge or threat of a discharge of oil into navigable
waters or adjoining shorelines is subject to strict joint and several liability
for all containment and cleanup costs and certain other damages, including
natural resource damages. OPA establishes a liability limit for onshore
facilities of $350 million and for offshore facilities, all removal costs plus
$75 million; however, a party cannot take advantage of this liability limit if
the spill is caused by gross negligence or willful misconduct, resulted from a
violation of a federal safety, construction, or operating regulation, or if a
party fails to report a spill or cooperate in the cleanup. Few defenses exist to
the liability imposed by OPA. OPA also imposes ongoing requirements on a
responsible party, including preparation of an oil spill contingency plan and
proof of financial responsibility to cover a substantial portion of
environmental cleanup and restoration costs that could be incurred by
governmental entities in connection with an oil spill. Under OPA and rules
adopted by the Minerals Management Service ("MMS"), responsible parties of
covered offshore facilities that have a worst case oil spill of more than 1,000
barrels must demonstrate financial responsibility in amounts ranging from at
least $10 million in state waters to at least $35 million in Outer Continental
Shelf ("OCS") waters, with higher amounts of up to $150 million in certain
limited circumstances where
18
the MMS believes such a level is justified by the risks posed by the operations
or if the worst case oil spill discharge volume possible at the facility may
exceed applicable threshold volumes specified in the MMS's rules. We believe
that we are in substantial compliance with OPA, including having appropriate
spill contingency plans and certificates of financial responsibility in place.
We have resolved claims by the MMS relating to civil penalties for
incidences of noncompliance with certain regulatory requirements on certain of
our offshore platforms, as discussed under the heading "Legal Proceedings --
Minerals Management Service."
The Federal Water Pollution Control Act ("FWPCA") and analogous state laws
impose strict controls regarding the discharge of pollutants, including produced
waters and other oil and natural gas wastes, into state waters or waters of the
United States. The discharge of pollutants into regulated waters is prohibited,
except in accord with the terms of a permit issued by EPA or the state.
Sanctions for unauthorized discharges include administrative, civil and criminal
penalties, as well as injunctive relief. We believe we are in substantial
compliance with applicable FWPCA requirements and that any non-compliance would
not have a material adverse effect on us.
Our operations are also subject to the Clean Air Act ("CAA") and comparable
state and local requirements. Amendments to the CAA were adopted in 1990 and
contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. We may be required to incur certain capital expenditures in the next
several years for air pollution control equipment in connection with obtaining
and maintaining operating permits and approvals for air emissions. However, we
believe our operations will not be materially adversely affected by any such
requirements, and the requirements are not expected to be any more burdensome to
us than to other similarly situated companies involved in oil and natural gas
exploration and production activities.
We maintain insurance against "sudden and accidental" occurrences, which may
cover some, but not all, of the risks described above. The insurance we maintain
may not cover the risks described above. There can be no assurance that such
insurance will continue to be available to cover all such costs or that such
insurance will be available at premium levels that justify its purchase. The
occurrence of a significant event not fully insured or indemnified against could
have a material adverse effect on our financial condition and operations.
Regulation of Oil and Natural Gas Exploration and Production. Our
exploration and production operations are subject to various types of regulation
at the federal, state and local levels. Such regulations include requiring
permits and drilling bonds for the drilling of wells, regulating the location of
wells, the method of drilling and casing wells, and the surface use and
restoration of properties upon which wells are drilled. Many states also have
statutes or regulations addressing conservation matters, including provisions
for the utilization or pooling of oil and natural gas properties, the
establishment of maximum rates of production from oil and natural gas wells and
the regulation of spacing, plugging and abandonment of such wells. Some state
statutes limit the rate at which oil and natural gas can be produced from our
properties.
EMPLOYEES
As of March 31, 2002, we had 59 full time salaried employees and
approximately 9 contract employees. None of our employees are subject to a
collective bargaining agreement. In addition to our employees, we may utilize
the services of independent geological, engineering, land and other consultants
from time to time.
TITLE TO PROPERTIES
We have obtained title reports on substantially all of our producing
properties and believe that we have satisfactory title to such properties in
accordance with standards generally accepted in the oil and natural gas
industry. As is customary in the oil and natural gas industry, we perform a
minimal title investigation before acquiring undeveloped properties. We also
obtain title opinions prior to the commencement of drilling operations on such
properties. Our properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens
which we believe do not materially interfere with the use of or materially
affect the value of such properties.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are party to litigation or other legal proceedings
that we consider to be a part of the ordinary course of our business. Other than
as set forth below, we are not involved in any legal proceedings nor are we
party to any pending or threatened claims that could reasonably be expected to
have a materially adverse effect on our
19
financial condition, cash flow or results of operations.
Bankruptcy filing
On March 14, 2000, we filed a voluntary petition under Chapter 11 of the
U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern
District of Texas, Houston Division. We filed our amended plan of reorganization
in the bankruptcy proceeding on May 9, 2001. Our plan provided for payment in
cash, or segregation of funds for the payment, to each creditor of its full,
allowed claim, including interest, on the closing date of the original offering.
Our plan was confirmed by a court order on May 23, 2001, subject to the
completion of the offering of the senior secured notes. Upon the closing of the
offering, we paid or segregated funds for the payment of all allowed claims in
accordance with our plan and the court order and, except as specifically
discussed below, lawsuits, administrative actions and other proceedings that
arose prior to the confirmation were dismissed as to us. If claims are resolved
for less than the amount segregated by us, we will receive the balance of the
funds.
Credit Lyonnais and Credit Lyonnais Securities
In March 2000, we and Richard Bowman filed suit against Credit Lyonnais, New
York Branch and Credit Lyonnais Securities (USA), Inc. in the 16th Judicial
District Court of Harris County, Texas asserting claims for violations of the
Federal Bank Tying Act, fraud and tortious interference. Credit Lyonnais filed a
counterclaim against us seeking repayment of monies loaned by Credit Lyonnais to
us, interest and attorney's fees. At the time these claims arose, Credit
Lyonnais was our senior secured lender. Specifically, we alleged that we were
wrongfully induced into incurring additional secured indebtedness associated
with the acquisition of certain oil and natural gas properties from Apache
Corporation. This additional indebtedness was to be refinanced on a short-term
basis by a debt or equity offering underwritten or privately placed by Credit
Lyonnais and/or its securities affiliate, Credit Lyonnais Securities, Inc. We
alleged that Credit Lyonnais advised us that it would not increase our credit
facility to an amount necessary to consummate the acquisition from Apache unless
we entered into an agreement with Credit Lyonnais Securities to act as our
exclusive financial advisor for such an offering. We agreed to enter into such
an arrangement based upon representations made to us regarding the ability,
experience and expertise of Credit Lyonnais Securities to assist us in such an
offering. We further alleged that no meaningful effort was made on the part of
Credit Lyonnais or Credit Lyonnais Securities to assist us in raising the funds
necessary to refinance our credit facility.
As part of the confirmation of our plan we and Richard Bowman reached a
settlement of this litigation in May 2001. The terms of the settlement included
a reduction in the amount of the secured claim of Credit Lyonnais in the
approximate amount of $3.3 million and our agreement not to dispute, other than
for arithmetic error, the remainder of Credit Lyonnais' secured claim, in the
approximate amount of $127.3 million, including principal, interest, fees and
expenses as of May 31, 2001. Richard Bowman assigned his interest in the
settlement to us.
Chieftain International
On March 31, 1999, Chieftain International (U.S.), Inc. ("Chieftain") filed
suit against us in the United States District Court for the Eastern District of
Louisiana (the "District Court") alleging that we owed certain joint interest
expenses in the approximate amount of $3.0 million, together with accrued
interest, attorney's fees, and costs, in connection with Chieftain's operation
of two offshore mineral leases. Chieftain took no action with regard to its
lawsuit during our bankruptcy, as the litigation in the District Court was
stayed pursuant to 11 U.S.C. Section 362. Since emerging from bankruptcy,
Chieftain successfully re-opened the litigation in the District Court and has
claimed that we now owe approximately $5.1 million, together with accrued
interest, attorneys' fees, and costs. However, pursuant to our confirmed plan of
reorganization, approximately $5.5 million was segregated in an interest bearing
account pending the trial and/or non-judicial resolution of our dispute with
Chieftain. Recently, we have come to an agreement with Chieftain to stay the
litigation for a six-month period in which we will conduct an audit of
Chieftain's books and records relating to the litigation. However, $5 million of
the funds segregated pending the trial and/or non-judicial resolution of our
dispute with Chieftain will be transferred to Chieftain prior to the
commencement of our audit. We will maintain $500,000 in the segregated account
pending a resolution of the audit, but all additional funds in the segregated
account due to interest accumulation will be distributed to us. If Chieftain's
lawsuit is not successfully resolved in the audit process, the lawsuit will be
reopened in the District Court and any of Chieftain's remaining claims will be
litigated, along with our counterclaims against Chieftain for conducting
operations in an imprudent manner.
Seitel Data, Ltd. and DDD Energy, Inc.
On December 13, 2000, Seitel Data, Ltd., and DDD Energy, Inc., filed suit
against Tribo Petroleum Corporation in the 334th Judicial District of Harris
County, Texas, alleging that Tribo owed approximately $0.8 million in damages,
together
20
with interest and attorney's fees for goods and services delivered for our
benefit. We paid the full amount of this claim, together with interest, in
accordance with our plan.
Minerals Management Service
In June 2001, we have reached a settlement with the MMS that resolved a
civil enforcement action first brought against us in August 2000, with respect
to certain alleged violations of MMS rules relating to the operation of our
offshore facilities prior to the commencement of our bankruptcy proceedings. As
part of the settlement, we have agreed to pay civil penalties in the amount of
$506,500, with $25,325 paid out initially, and the remaining $481,175 paid out
in quarterly installments over a two-year period. We have also agreed to provide
the MMS with approximately $9.8 million in operators bonds. The settlement
between the MMS and us is not an admission of liability with respect to the
violations alleged by the MMS.
Arch W. Helton, Helton Properties, Inc., and Linda Barnhill
On May 28, 1997, Arch W. Helton and Helton Properties, Inc., filed suit
against us in the 80th Judicial District Court of Harris County, Texas ("state
court"). Subsequently, Linda Barnhill joined as a plaintiff. The suit alleges
that we owe additional royalties on oil and natural gas produced from February
1987 to date as to certain completions in oil and natural gas properties located
in Alvin, Texas, that oil and natural gas was drained from approximately 18
acres in which they claim interests and seeks the recovery of attorneys' fees.
This suit has been dismissed from state court. The plaintiff's proof of claim in
our bankruptcy is all that remains. This claim is currently pending in the
United States Bankruptcy Court for the Southern District of Texas, Houston
Division. We intend to continue to vigorously defend this suit. Funds in the
amount of approximately $1.0 million have been segregated in accordance with our
plan pending the resolution of this dispute by the bankruptcy court. We believe
these funds are sufficient to cover our net interest in the full proof of claim
filed in the amount of $3.0 million.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II.
ITEM 5. MARKET FOR COMMON STOCK AND RELATED SHAREHOLDER MATTERS.
An aggregate of 433,333 shares of our common stock were issued and
outstanding on December 31, 2001, consisting of 368,333 shares of class A common
stock and 65,000 shares of class B common stock. There is no market for our
common stock. We have not paid and have no intention of paying dividends on our
common stock.
The following description of the capital shares does not purport to be
complete or to give full effect to the provisions of statutory or common law and
is subject in all respects to the applicable provisions of our Certificate of
Incorporation.
Effective June 15, 2001, the Company was authorized to issue two classes of
common stock, class A and class B. The holders of the common stock are entitled
to one vote for each share on all matters voted upon by shareholders, including
the election of directors. Such holders are not entitled to vote cumulatively
for the election of directors. Holders of a majority of the shares of common
stock entitled to vote in any election of directors may elect all of the
directors standing for election, subject to the rights of holders of class B
common stock described below.
Holders of class A and class B common stock are together entitled to
participate pro rata in such dividends as may be declared in the discretion of
the board of directors out of funds legally available therefore. Holders of
class A and class B common stock together are entitled to share ratably in the
net assets of the Company upon liquidation after payment or provision for all
liabilities and any preferential rights. Holders of common stock have no
preemptive rights to purchase shares of stock of the Company. Shares of common
stock are not subject to any redemption provisions and are not convertible into
any other securities of the Company, except that each share of class B common
stock is convertible into one share of class A common stock under certain
circumstances.
Special Rights of Class B Common Stock
In addition to the rights of the holders of common stock set forth above,
the holders of a majority of the class B common stock, voting together as a
single class, are entitled to designate one person to serve as a non-voting
advisory observer to the Company's board of directors, and further, at any time,
to cause the Company to increase the size of its
21
board of directors and to immediately elect to the board of directors a number
of directors (having full voting power) nominated by a majority of the holders
of the class B common stock sufficient to constitute a majority of the board of
directors. Until there are no outstanding shares of class B common stock, the
board of directors may not consist of more than seven directors other than those
nominated by the holders of the class B common stock in accordance with the
foregoing. Only the holders of the class B common stock may remove the directors
that such holders are entitled to designate.
In addition to any vote required by law, all matters submitted to a vote of
the Company's shareholders will require the approval of the holders of a
majority of the issued and outstanding shares of class B common stock, voting
separately as a single class. In addition, any amendment to the Company's Bylaws
will require the approval of the holders of the majority of the issued and
outstanding shares of class B common stock.
ITEM 6. SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
The following tables set forth our selected consolidated historical
financial data for the periods shown. The following information should be read
in conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the consolidated financial statements and related
notes included in this prospectus.
Years Ended December 31,
---------------------------------------------------------------------------
1997 1998 1999 2000 2001
------------ ------------ ------------ ------------- ------------
(in thousands, except per share and ratio data)
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
Total revenues....................................... $ 13,296 $ 26,352 $ 37,766 $ 74,476 $ 93,239
Expenses.............................................
Lease operating.................................. 4,845 17,450 15,542 19,485 19,948
Workover......................................... 687 600 2,410 6,649 5,916
Production taxes................................. 305 639 705 1,968 1,740
Depreciation, depletion and amortization......... 3,037 12,398 11,040 13,506 12,189
General and administrative....................... 2,276 3,327 5,237 4,328 6,973
Interest......................................... 1,410 7,734 11,981 12,758 21,145
------------ ------------ ------------ ------------- ------------
Total expenses.............................. 12,560 42,147 46,916 58,695 67,911
Income (loss) before reorganization costs
and income taxes................................. 736 (15,795) (9,150) 15,780 25,329
Reorganization costs................................. - - - 21,487 8,834
------------ ------------ ------------ ------------- ------------
Income (loss) before income taxes.................... 736 (15,795) (9,150) (5,707) 16,494
Provision for income taxes........................... 925 - - 79 -
------------ ------------ ------------ ------------- ------------
Net income (loss).................................... $ (189) $ (15,795) $ (9,150) $ (5,786) $ 16,494
============ ============ ============ ============= ============
Net income (loss) per share - basic and
diluted.......................................... $ (0.79) $ (66.27) $ (38.39) $ (24.28) $ 48.01
============ ============ ============ ============= ============
Weighted average shares outstanding.................. 238,333 238,333 238,333 238,333 343,580
============ ============ ============ ============= ============
OTHER FINANCIAL DATA:
Capital expenditures - oil and natural gas
properties....................................... $ 20,457 $ 71,992 $ 13,572 $ 10,878 $ 13,598
Adjusted EBITDA(1)................................... 5,183 4,337 13,871 42,045 71,161
Adjusted EBITDA to cash interest(2).................. 3.68x 0.56x 1.16x 3.30x 5.08x
Earnings to fixed charges(3)......................... 1.44x NM 0.31x 0.60x 1.74x
Cash flows from operating activities................. $ 2,516 $ 7,168 $ 12,127 $ 40,695 $ (21,603)
Cash flows from investing activities................. (24,196) (71,926) (11,943) (10,118) (13,161)
Cash flows from financing activities................. 23,324 65,153 (42) (401) 6,538
At December 31,
---------------------------------------------------------------------------
1997 1998 1999 2000 2001
------------ ------------ ------------ ------------- ------------
(in thousands, except per share and ratio data)
CONSOLIDATED BALANCE SHEET DATA:
Net property and equipment........................... $ 28,810 $ 89,194 $ 89,897 $ 87,308 $ 86,672
Total assets......................................... 41,831 104,130 108,903 152,594 151,152
Stockholder's equity (capital deficit)............... 592 (15,203) (24,352) (30,139) 11,577
ACNTA(4)............................................. 101,050 116,319 283,562 617,387 159,000
Notes payable, including current maturities.......... 35,184 101,480 105,058 104,657 110,138
ACNTA to indebtedness................................ 2.87x 1.15x 2.70x 5.90x 1.44x
22
- ----------
(1) EBITDA means earnings before interest expense, income taxes, depreciation,
depletion and amortization. Adjusted EBITDA means EBITDA before impairment
of oil and natural gas properties, reorganization costs and gains or losses
on derivative contracts. EBITDA is commonly used by debt holders and
financial statement users as a measurement to determine the ability of an
entity to meet its interest obligations. EBITDA is not a measurement
presented in accordance with generally accepted accounting principles
("GAAP") and is not intended to be used in lieu of GAAP presentation of
results of operations and cash provided by operating activities. Our
definition of adjusted EBITDA may not be identical to similarly entitled
measures used by other companies.
(2) Cash interest excludes non-cash interest for amortization of bond discount
and bond issuance costs, which are included in determining interest expense
in accordance with GAAP.
(3) For purposes of computing the ratio of earnings to fixed charges, earnings
are computed as income after reorganization costs and before income taxes
plus interest expense including amortization of premiums, discounts, and
capitalized expenses related to indebtedness. Fixed charges represent
interest expense and capitalized interest (including amortization of
deferred finance charges and an estimated portion of rentals representing
interest costs). Earnings were insufficient to cover fixed charges by $15.8
million, $9.2 million and $5.8 million for the years ended December 31,
1998, 1999 and 2000, respectively. Earnings of $16.5 million were
sufficient to cover fixed charges for the year ended December 31, 2001. NM
means, "not measured."
(4) ACNTA means Adjusted Consolidated Net Tangible Assets, as defined in
"Description of the Senior Secured Notes -- Certain Definitions." ACNTA is
calculated using oil and natural gas prices utilized in our year-end
reserve report. NM means, "not measured."
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion of our results of operations and financial
condition includes the results of operations and financial condition of our
subsidiary and us on a consolidated basis. Our consolidated financial statements
and the related notes contain additional detailed information that should be
referred to when reviewing this material.
GENERAL
We are an independent oil and natural gas company engaged in the
acquisition, development, exploration and production of oil and natural gas
properties in three core areas.
We commenced operations in 1992 and from our inception until mid-1996 we
primarily acquired and developed properties onshore in south and southeast
Texas. We expanded into the Sacramento Basin of northern California with our
acquisition of Reunion in 1996. We established a core area of operation in the
shallow waters of the Gulf of Mexico in 1997 with acquisitions from Apache and
Statoil. In 1998 we expanded our onshore Gulf Coast properties by completing our
largest acquisition to date, the $63.0 million acquisition of onshore Texas oil
and natural gas properties from Apache. We have since focused our efforts and
capital resources on developing our assets.
We have one subsidiary, Tri-Union Operating Company, which is wholly owned
by us. Tri-Union Operating's principal asset is a net profits interest in a
field in California, operated by us. This interest is the only oil and natural
gas property of Tri-Union Operating and represents less than 5% of our
consolidated proved reserves.
In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation with the proceeds from a short-term,
amortizing bank loan. In August 1998, before we were able to refinance our bank
loan, commodity prices began falling, with oil prices ultimately reaching a
12-year low in December 1998. The resultant negative effect on our cash flow
from the deterioration of commodity prices, coupled with the required
amortization payments on our bank loan, severely restricted the amount of
capital we were able to dedicate to development drilling. Consequently, our oil
and natural gas production declined, further negatively affecting our cash flow.
In October 1998, our short-term loan matured and we arranged a forbearance
agreement providing for interest payments to be partially capitalized. On July
1999, this forbearance agreement terminated and we made negotiated interest
payments while attempting to negotiate a restructuring of our obligations.
On March 14, 2000, we chose to seek protection under Chapter 11 of the U.S.
Bankruptcy Code. Tri-Union Operating continued to operate outside of bankruptcy.
On July 18, 2001, we sold in a private unit offering $130,000,000 of old
23
notes, each unit consisting of one old note in the principal amount of $1,000
and one share of class A common stock of Tribo Petroleum Corporation, our former
parent corporation. The proceeds from this offering and our available cash
balances were sufficient to allow us to pay or segregate funds for the payment
of all creditor claims in full, including interest, and to exit bankruptcy on
June 18, 2001.
As of December 31, 2001, we had $110.1 million of debt outstanding (net of
bond discounts), as compared to adjusted EBITDA of $71.2 million for the
year ended December 31, 2001.
At December 31, 2000, our net proved reserves were 180.1 Bcfe with a PV-10
Value of $630.0 million. At December 31, 2001, our net proved reserves were
191.7 Bcfe with a PV-10 Value of $143.8 million and $160.8 million including our
hedge position value at such date. Our total proved reserve quantities at
December 31, 2001 increased by 6% versus those at December 31, 2000. The
increase in total proved reserves was primarily due to two factors. First, based
on recent drilling and recompletion successes, we have been able to add a number
of additional PUD's and behind-pipe locations on our California assets.
Secondly, a recent 3-D seismic survey conducted over our Barber's Hill property
has enabled us to delineate and add a PUD location in that field. Our capital
budget has been primarily focused on converting proved developed non-producing
and proved undeveloped reserves to production.
During 1999, 2000 and 2001, our capital expenditures on oil and natural gas
activities totaled approximately $13.6 million, $10.9 million and $13.6 million,
respectively. These expenditures related to operations in our three core areas.
In 1998, 87% of our capital expenditures were related to the acquisition of
reserves. In 1999 and 2000, 44%, or $10.6 million, of our capital expenditures
were for development drilling and recompletions. The remaining 56% was incurred
on items such as platform and pipeline improvements that were identified at the
time of our acquisition of the properties, compressor installations and on 3-D
seismic surveys. During 1999 and 2000 our development capital investments of
$10.6 million were expended to complete 28 development wells, exploitation
wells and recompletions. During 2001, our developmental capital investments of
$13.6 million were expended on a large offshore recompletion, the plugging of
our four offshore facilities and the recompletion or drilling of 35 other
projects.
On July 27, 2001, we were the surviving corporation in a merger with our
parent corporation, Tribo Petroleum Corporation. As a consequence of this
merger, we assumed all of the rights and obligations of Tribo, including those
under the indenture. The financial information in this prospectus is the
consolidated financial information for Tribo, us and our subsidiary as of the
periods indicated.
We use the full cost method of accounting for oil and natural gas property
acquisition, exploration and development activities. Under this method, all
productive and nonproductive costs incurred in connection with the acquisition
of, exploration for and development of oil and natural gas reserves are
capitalized. Capitalized costs include lease acquisitions, geological and
geophysical work, delay rentals and the costs of drilling, completing and
equipping oil and natural gas wells. Gains or losses are recognized only upon
sales or dispositions of significant amounts of oil and natural gas reserves.
Proceeds from all other sales or dispositions are treated as reductions to
capitalized costs.
RESULTS OF OPERATIONS
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
For the year ended December 31, 2001, consolidated net income was
$16,494,151, a $22,280,177 increase from the consolidated net loss of $5,786,026
for the year ended December 31, 2000.
Oil and Natural Gas Revenues. Oil and natural gas revenues increased
$7,064,221, or 10%, to $80,516,275 for the year ended December 31, 2001 from
$73,452,054 for the year ended December 31, 2000. Although production volumes
decreased 976 Mcfe, or 6% to 15,337 Mcfe for the year ended December 31, 2001
from 16,313 Mcfe for the year ended December 31, 2000, oil and natural gas
revenue increased as a result of an increase in the average price received for
sales of natural gas during the period. Our decline in production is partially
attributable to a reduction to production in our Westbury Farm #1 well in the
Constitution Field due to 2 wells drilled on adjoining acreage, not owned or
operated by us, directly offsetting our production. Further contributing to our
production decline were two wells which watered-out in our Ord Bend Field in
California. After watering out, these 2 wells were recompleted during 2001 to
new zones at reduced production rates. Additionally, two recompletion in our
West Hastings unit depleted during the last half of 2001 and have not been
brought into production. The following table summarizes the consolidated results
24
of oil and natural gas production and related pricing for the years ended
December 31, 2000 and 2001:
Years Ended December 31,
---------------------------------------------
2000 2001 % Change
------------- ------------- -------------
Oil production volumes (Mbbls) 1,333 1,245 -7%
Gas production volumes (Mmcf) 8,314 7,869 -5
Total (Mmcfe) 16,313 15,337 -6
Average oil price (per Bbl) $28.95 $25.81 -11%
Average gas price (per Mcf) 4.19 6.15 47
Average price (per Mcfe) 4.50 5.25 17
Loss on Marketable Securities. Losses on marketable securities were $556,735
for the year ended December 31, 2001. In satisfaction of certain related party
transactions, we entered into an agreement whereby we transferred to Atasca
certain minor oil and gas properties and trading securities owned by Tribo
Petroleum Corporation. The marketable securities were sold during July 2001 and
proceeds in the amount of $102,458 were transferred to Atasca. The sale of these
trading securities resulted in a loss, with the change in fair value recognized
during the period included in earnings.
Gain on Derivatives Contract. In connection with the issuance of the senior
secured notes, we agreed to maintain, subject to certain conditions, on a
monthly basis, a rolling two-year derivatives contract until the maturity of the
notes on approximately 80% of our projected oil and natural gas production from
proved developed producing reserves and the basis differential attributable to
approximately 80% of our projected proved developed producing natural gas
production from our California properties. At December 31, 2001,we had
derivative contracts in place through, December 31, 2003 at estimated net
realized prices that we expect will exceed $3.96 per Mcf and $24.42 per Bbl, or
a weighted natural gas-equivalent price of approximately $4.01 per Mcfe. The
estimated fair value of this derivatives contract at December 31, 2001 resulted
in the recording of a gain on derivatives contract of $12,498,944. Our
production was not hedged at December 31, 2000.
Other Income. Other income increased $752,563 to $780,967 for the year
ended December 31, 2001 from $28,404 for the year ended December 31, 2000. The
increase was primarily the result of the sale of emission reduction credits from
our Hastings Field. The income recognized as a result of the sales of the
emission credits was offset by a loss on the sale of zero coupon U.S. Treasury
Bonds with a 2019 maturity, purchased and held in trust and pledged to the
Minerals Management Service ("MMS") for the plugging and abandonment ("P&A") of
certain wells and the decommissioning of offshore platforms. These zero coupon
U.S. Treasury Bonds were sold to satisfy a re-bonding requirement as stipulated
by the MMS during our bankruptcy. New bonds in the amount of approximately $9.8
million were issued during June 2001 with the cash proceeds from the sale of the
zero coupon U.S. Treasury bonds. These proceeds were deposited into a restricted
interest bearing money market account as collateral for the new P&A performance
bonds.
Lease Operating Expenses. Lease operating expenses increased $462,613 or 2%,
to $19,947,972 for the year ended December 31, 2001 from $19,485,359 for the
year ended December 31, 2000. Lease operating expense was $1.30 per Mcfe for the
year ended December 31, 2001, an increase of 9% from $1.19 per Mcfe for the year
ended December 31, 2000. The increase was primarily the result of higher
electricity and fuel costs, and the result of MMS required compliance work at
our Matagorda Island A-4 and Brazos 104 facility during the first half of 2001.
The increase in lease operating expense was partially offset as a result of the
sale of our Ship Shoal 58 field in June 2001 and the P&A of the West Cameron
531, South Marsh Island 232 and Brazos 476 wells and platform, where lease
operations have ceased.
Workover Expense. Workover expenses decreased $732,718, or 11%, to
$5,916,356 for the year ended December 31, 2001 from $6,649,074 for the year
ended December 31, 2000. Workover expense was $0.39 per Mcfe for the year ended
December 31, 2001, a decrease of 5% from $0.41 per Mcfe for the year ended
December 31, 2000. During the last half of 2000 and the first half of 2001, an
accelerated workover program was completed which returned several marginal
shut-in wells to production. During the last half of 2001, workover expenses
have returned to a more normal level of expenditure.
Production Taxes. Production taxes decreased $228,180 or 12%, to $1,740,162
for the year ended December 31, 2001 from $1,968,342 for the year ended December
31, 2000. Production taxes were $0.11 per Mcfe for the year ended December 31,
2001, a decrease of 8% from $0.12 per Mcfe for the year ended December 31, 2000.
Production taxes are computed by multiplying produced volumes or revenues by a
tax rate specified by the taxing authority. Decreases in oil and natural gas
volumes during the year ended December 31, 2001 contributed to the decrease in
the amount of production taxes paid during the period.
Depreciation, Depletion and Amortization Expense. DD&A decreased $1,317,636,
or 10%; to $12,188,841 for the
25
year ended December 31, 2001 from $13,506,477 for the year ended December 31,
2000. DD&A was $0.79 per Mcfe for the year ended December 31, 2001, a decrease
of 5% from $0.83 per Mcfe for the year ended December 31, 2000. An decrease in
oil and natural gas volumes produced during the year ended December 31, 2001
resulted in an decrease in the amount of depletion computed on those volumes.
General and Administrative Expense. G&A increased $2,644,186, or 61%, to
$6,972,544 for the year ended December 31, 2001 from $4,328,358 for the year
ended December 31, 2000. G&A was $0.45 per Mcfe for the year ended December 31,
2001, an increase of 67% from $0.27 per Mcfe for the year ended December 31,
2000. The increase was primarily the result of an increase in salary, director
fees and related expenses of $254,460, an increase in legal and audit and tax
service fees of $762,515 and an increase in bad debt expense of $1,562,041.
Interest Expense. Interest expense increased $8,387,094, or 66%, to
$21,144,957 for the year ended December 31, 2001 from $12,757,863 for the year
ended December 31, 2000. The increase was primarily the result of non-cash
amortization of bond discount and deferred loan costs to interest expense of
$3,922,434 and $3,208,149 respectively, for the year ended December 31, 2001.
Reorganization Costs. Tri-Union Development Corporation filed for bankruptcy
protection on March 14, 2000. We incurred reorganization costs of $21,487,191
for the year ended December 31, 2000 and $8,834,468 for the year ended December
31, 2001. Reorganization costs primarily included the following:
Rejection of fixed-price physical delivery contract -- The bankruptcy
court approved a motion to reject a fixed-price physical delivery contract.
A claim was filed by the damaged party resulting in a liability of
$17,559,272 (see Note 10). During the years ended December 31, 2000 and
2001, the Company incurred reorganization expenses related to this claim of
$17,559,272 and $737,022, respectively.
Professional fees and other -- The Company was required to hire certain
legal and accounting professionals to help the Company and its Creditors in
its bankruptcy proceedings. These fees were $3,611,760 during 2000 and
$3,781,716 during 2001.
Retention costs -- In an effort to maintain certain key employees
through the bankruptcy period, the Company incurred retention bonuses of
$855,000 and $301,740 during the years ended December 31, 2000 and 2001,
respectively. During August 2001, we paid the retention bonus to our
employees.
Interest expense - The Company paid interest expense of $2,974,270 as a
result of our emergence from bankruptcy during 2001.
Atasca transaction - As a condition of TDC's plan of reorganization, the
Company agreed to transfer all of the oil and natural gas properties and
certain marketable securities owned by Tribo Petroleum Corporation, as of
May 1, 2001 to its affiliate, Atasca Resources, Inc., at their net book
values of approximately $1,098,000 and $102,000, respectively. In connection
with this transaction, all balances owing to and from the Company by its
affiliates on May 1, 2001 were forgiven. These balances aggregated to a net
receivable from the affiliates of $785,000. As a consequence of these
transactions, the Company recorded a one-time reorganization expense of
$1,985,442 in 2001.
Interest Income -- The Company earned interest income of $538,841 from
March 14, 2000 through December 31, 2000, and $945,722 from January 1, 2001
through June 18, 2001.
Provision for Income Taxes. A $79,000 provision for income tax was made for the
year ended December 31, 2000, primarily as a result of alternative minimum tax
considerations. No provision for federal income tax was required for the year
ended December 31, 2001.
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
For the year ended December 31, 2000, consolidated net loss was $5,786,026,
a 37% decrease in the consolidated net loss of $9,150,034 for the year ended
December 31, 1999.
Oil and Natural Gas Revenues. Oil and natural gas revenues increased
$37,181,711, or 103%, to $73,452,054 for the year ended December 31, 2000 from
$36,270,343 for the year ended December 31, 1999. The increase in oil and
26
natural gas revenues was the result of an increase in production volumes as a
consequence of a successful capital expenditure and workover program and an
increase in the average price received for sales of oil and natural gas during
the period. The following table summarizes the consolidated results of oil and
natural gas production and related pricing for the years ended December 31, 2000
and 1999:
Years Ended December 31,
---------------------------------------------
1999 2000 % Change
------------- ------------- -------------
Oil production volumes (Mbbls) 1,145 1,333 16%
Gas production volumes (Mmcf) 7,007 8,314 19
Total (Mmcfe) 13,874 16,313 18
Average oil price (per Bbl) $17.27 $28.95 68%
Average gas price (per Mcf) 2.36 4.19 78
Average price (per Mcfe) 2.61 4.50 72
Gain on Marketable Securities. Gains on marketable securities were $995,180
for the year ended December 31, 2000. Certain marketable securities were bought
and held principally for the purpose of selling them in the near term and are
classified as trading securities. Trading securities are recorded at fair value
on the balance sheet as current assets, with the change in fair value recognized
during the period included in earnings.
Other Income. Other income decreased $1,466,989, or 98%, to $28,404 for the
year ended December 31, 2000 from $1,495,393 for the year ended December 31,
1999. The decrease was primarily the result of a change in accounting method for
the year ended December 31, 2000, by which interest income was recorded as an
offset to reorganization costs in accordance with SOP 90-7 and the non-recurring
revision of prior year estimated accruals in 1999.
Lease Operating Expenses. Lease operating expenses increased $3,943,082, or
25%, to $19,485,359 for the year ended December 31, 2000 from $15,542,277 for
the year ended December 31, 1999. Lease operating expense was $1.19 per Mcfe for
the year ended December 31, 2000, an increase of 6% from $1.12 per Mcfe for the
year ended December 31, 1999. The increase was primarily the result of a general
increase in oilfield related service costs, with the increase on a per unit of
production basis partially offset by increases in production. Additionally,
several non-recurring expenditures associated with returning over 50 wells to
production at our Hastings, Sour Lake and AWP fields, the installation of an
Amine unit and compressor at our Word field and regulatory compliance and
compressor installations at several offshore locations contributed to the
increase in lease operating expenses for the year ended December 31, 2000.
Workover Expense. Workover expense increased $4,238,664, or 176%, to
$6,649,074 for the year ended December 31, 2000 from $2,410,410 for the year
ended December 31, 1999. Workover expense was $0.41 per Mcfe for the year ended
December 31, 2000, an increase of 141% from $0.17 per Mcfe for the year ended
December 31, 1999. In 2000, a workover program was completed that included
normal recurring workovers, a backlog of workovers from 1998 and 1999 and
workovers associated with certain of the 50 wells that we returned to production
during the year. Expenses also included artificial lift and saltwater disposal
system installations for certain wells in our Hastings, AWP, Ord Bend and
Powderhorn fields.
Production Taxes. Production taxes increased $1,263,487, or 179%, to
$1,968,342 for the year ended December 31, 2000 from $704,855 for the year ended
December 31, 1999. Production taxes were $0.12 per Mcfe for the year ended
December 31, 2000, an increase of 140% from $0.05 per Mcfe for the year ended
December 31, 1999. Production taxes are computed by multiplying produced volumes
or revenues by a tax rate specified by the taxing authority. The taxing
authorities, upon meeting certain conditional requirements, offered drilling and
development incentives in the form of tax rate reductions over a specified
period of time. Certain of these incentives expired during early 2000, resulting
in an increase in tax rates for the remainder of that year. Increases in oil and
natural gas volumes and revenues during the year ended December 31, 2000 also
contributed to the increase in the amount of production taxes paid during the
period.
Depreciation, Depletion and Amortization Expense. DD&A increased $2,466,442,
or 22%; to $13,506,477 for the year ended December 31, 2000 from $11,040,035 for
the year ended December 31, 1999. DD&A was $0.83 per Mcfe for the year ended
December 31, 2000, an increase of 4% from $0.80 per Mcfe for the year ended
December 31, 1999. An increase in oil and natural gas volumes produced during
the year ended December 31, 2000 resulted in an increase in the amount of
depletion computed on those volumes. DD&A per unit of production remained
relatively steady as a result of increased production and reserves from the
successful completion of a relatively low cost development program.
27
General and Administrative Expense. G&A decreased $908,375, or 17%, to
$4,328,358 for the year ended December 31, 2000 from $5,236,733 for the year
ended December 31, 1999. G&A was $0.27 per Mcfe for the year ended December 31,
2000, a decrease of 29% from $0.38 per Mcfe for the year ended December 31,
1999. The decrease was primarily the result of a reversal of a provision for
doubtful accounts, which had been recorded for a receivable owed by a working
interest owner at December 31, 1999. A settlement agreement with the working
interest owner during 2000 lead to the reversal of the provision for the
account. Certain reorganization efforts and cost saving measures were
implemented which also contributed to the decrease in G&A expenses for the
period.
Interest Expense. Interest expense increased $776,403, or 6%, to $12,757,863
for the year ended December 31, 2000 from $11,981,460 for the year ended
December 31, 1999. The increase was primarily the result of an increase in
outstanding borrowings.
Reorganization Costs. Tri-Union Development Corporation filed for bankruptcy
protection on March 14, 2000. We incurred reorganization costs of $21,487,191
for the year ended December 31, 2000. Reorganization costs primarily included
the following:
Rejection of fixed-price physical delivery contract -- The bankruptcy
court approved a motion to reject a fixed-price physical delivery contract.
A claim was filed by the damaged party resulting in a liability of
$17,559,272. The contract was not a financial instrument that would qualify
to be treated as a hedge for financial reporting purposes; accordingly the
full amount of the claim was recorded as an expense for the year ended
December 31, 2000. The full amount of the claim was satisfied in accordance
with our amended plan of reorganization.
Professional fees and other -- We retained certain legal and accounting
professionals to assist with the bankruptcy proceedings and have incurred or
estimated legal and accounting fees associated with these proceedings
totaling $3,611,760 for the year ended December 31, 2000.
Employee retention costs -- In an effort to maintain employees through
the bankruptcy period, we sought approval from creditors and the bankruptcy
court to compensate the employees when certain conditions are met. For the
year ended December 31, 2000, estimated retention expenses of $855,000 were
recorded.
Interest -- Interest income of $538,841 was earned from March 14, 2000
through December 31, 2000. As prescribed by SOP 90-7, interest earned is
offset against reorganization costs, as described above.
Provision for Income Taxes. A $79,000 provision for income tax was made for
the year ended December 31, 2000, primarily as a result of alternative minimum
tax considerations. No provision for federal income tax was required for the
year ended December 31, 1999.
LIQUIDITY AND CAPITAL RESOURCES
In March 1998, we acquired certain onshore Texas oil and natural gas
properties from Apache Corporation. Prior to the acquisition, we had
approximately $35.0 million in debt outstanding. We incurred approximately
another $63.0 million in debt in connection with the Apache acquisition. In
August 1998, before we were able to refinance our debt, commodity prices began
falling, with oil prices ultimately reaching a 12-year low in December of that
year. The resultant negative effect on our cash flow from the deterioration of
commodity prices, coupled with the required amortization payment on our bank
loan, severely restricted the amount of capital we were able to dedicate to
development drilling. Consequently, our oil and natural gas production declined,
further negatively affecting our cash flow. In October 1998, our loan matured
and we arranged a forbearance agreement providing for interest payments to be
partially capitalized and providing us with additional time to refinance our
obligations. In July 1999, the forbearance agreement terminated and we made
negotiated interest payments while attempting to negotiate a restructuring of
our obligations. By March 2000, the aggregate principal balance of our bank debt
had increased as a result of capitalized interest and expenses to approximately
$105.0 million. In February 2000, the bank declared the loan in default,
demanded payment of all principle and interest and posted the shares of Tribo
Petroleum Corporation, at that time our parent corporation and a guarantor of
the loan, for foreclosure. As a consequence of the bank's actions, on March 14,
2000, we filed for bankruptcy protection. After the filing, we operated as a
"debtor-in-possession," continuing in possession of our estate, the operation of
our business and the management of our properties. Under Chapter 11, certain
claims against us in existence prior to the filing of the petition were stayed
from enforcement or collection. These claims are reflected in full in the
consolidated December 31, 2000 sheet as "pre-petition liabilities subject to
compromise."
28
After we entered into bankruptcy in March 2000, commodity prices began to
recover, with natural gas prices eventually reaching historically high levels,
particularly in California. During 2001, average prices we received for natural
gas and oil was $6.15 per Mcf and $25.81 per Bbl. During our bankruptcy we were
also permitted to apply funds previously devoted to amortization payments on our
debt towards limited development activities, which yielded substantial
improvements in our production volumes of both oil and natural gas.
We filed our amended plan of reorganization in the bankruptcy court on May
9, 2001, which provided for our exit from bankruptcy upon the completion of a
$130.0 million unit offering of senior secured notes and class A common stock.
Our plan was confirmed by a court order entered as of May 23, 2001, subject to
the completion of the offering. On June 18, 2001, the offering closed and we
exited bankruptcy. The proceeds of the offering and our available cash balances
at closing were sufficient to allow us to pay or segregate funds for the payment
of all claims in full.
During the last two quarters of 2001 and continuing into 2002, commodity
prices again declined. These price declines, coupled with production declines
beginning in the third quarter of 2001, predominately attributable to
unanticipated production declines in two wells, adversely impacted our cash
flows during the latter part of 2001. Commodity price hedges that we had entered
into in connection with the closing of the offering have only partially offset
the adverse impact on our cash flows from the decline in commodity prices.
At December 31, 2001, we had $130.0 million of 12.5% senior secured notes
outstanding. The notes mature on June 1, 2006 and require amortization payments
of the greater of $20.0 million and 15.3% as of June 1, 2002 and 2003 and an
amortization payment of the greater of $15.0 million and 11.5% as of June 1,
2004. A final amortization payment of $75,000,000 is due June 1, 2006. Interest
is payable semi-annually on June 1 and December 1 of each year. On June 1, 2002,
a payment in the approximate amount of $28.0 million is due on the notes,
representing $20.0 million in principal and approximately $8.0 million in
accrued interest.
At December 31, 2001, our cash balance was $4.8 million, a $28.2 million
decrease from our cash balance at December 31, 2000.
Net cash used by operating activities before reorganization items was $16.4
million for the year ended December 31, 2001 compared to net cash provided by
operating activities before reorganization items of $42.7 for the year ended
December 31, 2000. The increase is the result of a decrease in accounts payable
and accrued liabilities and accounts receivable at December 31, 2001.
Additionally, on June 18, 2001, we deposited $13.5 million into a restricted
cash account as required by our plan of reorganization to satisfy the payment in
full of all remaining disputed pre-petition claims. As of December 31, 2001,
$4.6 million of cash deposited into this restricted account was disbursed to us
or to claimants of pre-petition claims. At December 31, 2001, the balance in the
restricted account was $8.9 million. These uses of cash were partially offset by
an increase in net income of $16.5 million after reorganization costs of $8.8
million and income from hedging contracts of $12.5 million at December 31, 2001,
when compared to a net loss of $5.8 million after reorganization costs of $21.5
million at December 31, 2001.
Net cash used in investing activities was $13.2 million for the year ended
December 31, 2001 when compared to $10.1 million for the year ended December 31,
2000. The increase is primarily the result of an increase in proceeds from the
sales of oil and natural gas properties of $1.8 million to $2.2 million at
December 31, 2001 from $0.39 million for the year ended December 31, 2000.
Additions to oil and natural gas properties and other equipment increased $2.7
million to $13.6 million for the year ended December 31, 2001 from $10.9 million
for the year ended December 31, 2000. This increase is partially offset by a
decrease in proceeds from the sale of marketable securities of $1.3 million to
$0.55 million for the year ended December 31, 2001 from $1.87 million for the
year ended December 31, 2000.
Net cash provided by financing activities was $6.5 million for the year
ended December 31, 2001 when compared to net cash used of $0.4 million for the
year ended December 31, 2000. The increase is the result of the completion of
the notes offering on June 18, 2001, partially offset by the payment of loan
fees in the amount of $3.2 million at December 31, 2001.
Years Ended December 31,
---------------------------------------------
1999 2000 2001
------------- ------------- -------------
Property acquisition - proved....................................... $ 250 $ 408 $ -
Development costs................................................... 13,322 10,080 13,598
Exploration costs................................................... - 389 -
------------- ------------- -------------
Total costs incurred........................................... $ 13,572 $ 10,878 $ 13,598
============= ============= =============
29
CAPITAL REQUIREMENTS
Historically, our principal sources of capital have been cash flow from
operations, short-term reserve-based bank loans, proceeds from asset sales and
the notes offering. Our principal uses for capital have been the acquisition and
development of oil and natural gas properties.
At December 31, 2001, our cash balance was $4.8 million. On June 1, 2002, we
are required to make a payment of approximately $28.0 million on the senior
secured notes, representing $20.0 million in principal and approximately $8.0
million in accrued interest. We intend to divest most or all of our Gulf Coast
onshore and offshore assets as part of our plan to focus our efforts on our
Sacramento Basin properties and to provide us with the resources necessary to
fund our capital budget for 2002 and to make the payment on the notes due June
1, 2002, and have retained the services of an oil and gas marketing agent to
assist us in the sales process for our onshore Gulf Coast properties. In March
2002, we terminated certain of our derivatives contracts and replaced them with
contracts providing for price floors at the prices specified under the terms of
the senior secured notes of $2.75 per MMBtu of natural gas (Henry Hub) and
$18.50 per barrel of crude oil (West Texas Intermediate). We are entitled to
receive approximately $3 million on the settlement of these contracts. The funds
will be placed in a segregated bank account and be applied to our June 1 payment
on the senior secured notes. The purchase price of the floor contracts of
approximately $1 million has been financed by our derivatives contract
counterparty. We have also begun negotiations with various lenders regarding the
implementation of a revolving credit facility that would be available for
working capital and debt service requirements. In light of our limited cash
balance at year end and impending debt payment we have begun to limit our
capital expenditures on workover and development projects. Prolonged reductions
in these expenditures would have an adverse affect on our future production of
oil and natural gas.
If the timing or magnitude of our asset sales appears insufficient to fund
our June 1 payment, or if we will be unable to implement a revolving credit
facility providing us with the capacity necessary to fund our obligations, we
will be required to further restrict our workover and development activities and
concurrently pursue alternative means of obtaining the necessary funds, which
may involve the early termination of additional in-the-money commodity price
hedges, sales of future production or other forms of financing.
Qualitative Disclosures About Market Risk
Revenues from our operations are highly dependent on the price of oil and
natural gas. The markets for oil and natural gas are volatile and prices for oil
and natural gas are subject to wide fluctuations in response to relatively minor
changes in the supply of and demand for oil and natural gas and a variety of
additional factors that are beyond our control, including the level of consumer
demand, weather conditions, domestic and foreign governmental regulations,
market uncertainty, the price and availability of alternative fuels, political
conditions in the Middle East, foreign imports and overall economic conditions.
It is impossible to predict future oil and natural gas prices with any
certainty. To reduce our exposure to oil and natural gas price risks, from time
to time we may enter into commodity price derivative contracts to hedge
commodity price risks.
Approximately 80% of our projected oil and natural gas production from
proved developed producing reserves (and the basis differential attributable to
approximately 80% of our projected proved developed producing natural gas
production from our California properties) are hedged at December 31, 2003 at
swap prices of $3.96 per Mcf and $24.42 per Bbl, or a weighted-average natural
gas-equivalent price of approximately $4.01 per Mcfe. In connection with the
issuance of the notes, we agreed to maintain, on a monthly basis, a rolling
two-year hedge program until the maturity of the notes, subject to certain
conditions. In March 2002, we terminated certain of our derivatives contracts
and replaced them with contracts providing for price floors at the prices
specified under the terms of the senior secured notes of $2.75 per MMBtu of
natural gas (Henry Hub) and $18.50 per barrel of crude oil (West Texas
Intermediate).
Recently Issued Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board finalized FASB
Statements No. 141, Business Combinations ("SFAS 141"), and Statement No. 142,
Goodwill and Other Intangible Assets ("SFAS 142"). SFAS 141 requires the use of
the purchase method of accounting and prohibits the use of the
pooling-of-interests method of accounting for business combinations initiated
after June 30, 2001. SFAS 141 also requires that the Company recognize acquired
intangible assets apart from goodwill if the acquired intangible assets meet
certain criteria. SFAS 141 applies to all business combinations initiated after
June 30, 2001 and for purchase business combinations completed on or after July
1, 2001. It also requires, upon adoption of SFAS 142, that the Company
reclassify the carrying amounts of intangible assets and goodwill based on the
criteria in SFAS 141. SFAS 142 requires, among other things, that companies no
longer amortize goodwill, but instead test goodwill for impairment at least
annually. In addition, SFAS 142 requires that the Company identify reporting
units for the purposes of assessing potential future impairments of goodwill and
reassess the amortization of intangible assets with an indefinite useful life.
An intangible asset with an indefinite useful life should be tested for
impairment in accordance with SFAS 142. SFAS 142 is required to be applied in
fiscal years beginning after December 15, 2001 to all goodwill and other
intangible assets recognized at that date, regardless of when those assets were
initially recognized. SFAS 142 requires the Company to complete a transitional
goodwill impairment test six months from the date of adoption. The Company is
also required to reassess the useful lives of other intangible assets within the
first interim quarter after adoption of SFAS 142. Currently, the Company is
assessing but has not yet determined how the adoption of SFAS 141 and SFAS 142
will impact its financial position and results of operations.
30
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations, SFAS No. 143, which amends SFAS No. 19, Financial Accounting and
Reporting by Oil and Gas Producing Companies, is applicable to all companies.
SFAS No. 143, which is effective for fiscal years beginning after June 15, 2002,
addresses financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. It applies to legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction, development
and/or the normal operation of a long-lived asset, except for certain
obligations of lessees. As used in SFAS No. 143, a legal obligation is an
obligation that a party is required to settle as a result of an existing or
enacted law, statue, ordinance, or written or oral contract or by legal
construction of a contract under the doctrine of promissory estoppel. While we
are not yet required to adopt SFAS No. 143, we do not believe the adoption will
have a material effect on our financial condition or results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
of Disposal of Long-lived Assets. SFAS No. 144, which supercedes SFAS No. 121,
Accounting for the Impairment of Long-lived Assets for Long-lived Assets to be
Disposed Of and amends ARB No. 51, Consolidated Financial Statements, addresses
financial accounting and reporting for the impairment or disposal of long-lived
assets. SFAS No. 144 is effective for fiscal years beginning after December 15,
2001, and interim financials within those fiscal years, with early adoption
encouraged. The provisions of SFAS No. 144 are generally to be applied
prospectively. As of the date of this filing, we are still assessing the
requirements of SFAS No. 144 and have not determined the impact the adoption
will have on our financial condition or results of operations.
CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES
The Securities and Exchange Commission recently issued disclosure guidance
for "critical accounting policies." The SEC defines critical accounting policies
as those that require application of management's most difficult, subjective or
complex judgments, often as a result of the need to make estimates about the
effect of matters that are inherently uncertain and may change in subsequent
periods.
Our significant accounting policies are described in Note 3 in the Notes to
Consolidated Financial Statements. Not all of these significant accounting
policies require management to make difficult, subjective or complex judgments
or estimates. However, the following policies could be deemed to be critical
within the SEC definition.
Oil and Natural Gas Interests
Full Cost Method - The Company uses the full cost method of accounting for
exploration and development activities as defined by the SEC. Under this method
of accounting, the costs for unsuccessful, as well as successful, exploration
and development activities are capitalized as properties and equipment. This
includes any internal costs that are directly related to exploration and
development activities but does not include any costs related to production,
general corporate overhead or similar activities. The sum of net capitalized
costs and estimated future development and abandonment costs of oil and gas
properties and mineral investments is amortized using the unit-of-production
method.
Proved Reserves - Proved oil and gas reserves are the estimated quantities
of natural gas, crude oil and condensate that geological and engineering data
demonstrate with reasonable certainty can be recovered in future years from
known reservoirs under existing economic and operating conditions. Reserves are
considered "proved" if they can be produced economically as demonstrated by
either actual production or conclusive formation tests. Reserves which can be
produced economically through application of improved recovery techniques are
included in the "proved" classification when successful testing by a pilot
project or the operation of an installed program in the reservoir provides
support for the engineering analysis on which the project or program was based.
"Proved developed" oil and gas reserves can be expected to be recovered through
existing wells with existing equipment and operating methods. The Company
emphasizes that the volumes of reserves are estimates which, by their nature,
are subject to revision. The estimates are made using all available geological
and reservoir data as well as production performance data. These estimates, made
by the Company's engineers, are reviewed and revised, either upward or downward,
as warranted by additional data. Revisions are necessary due to changes in
assumptions based on, among other things, reservoir performance, prices,
economic conditions and governmental restrictions. Decreases in prices, for
example, may cause a reduction in some proved reserves due to uneconomic
conditions.
Ceiling Test - Companies that use the full cost method of accounting for oil
and gas exploration and development activities are required to perform a ceiling
test. The full cost ceiling test is an impairment test prescribed by SEC
Regulation S-X Rule 4-10. The test determines a limit, or ceiling, on the book
value of oil and gas properties. That limit is basically the after tax present
value of the future net cash flows from proved crude oil and natural gas
reserves. This
31
ceiling is compared to the net book value of the oil and gas properties reduced
by any related deferred income tax liability. If the net book value reduced by
the related deferred income taxes exceeds the ceiling, an impairment or non-cash
write down is required. A ceiling test impairment can give us a significant loss
for a particular period; however, future DD&A expense would be reduced.
Estimates of future net cash flows from proved reserves of gas, oil and
condensate are made in accordance with SFAS No. 69, "Disclosures about Oil and
Gas Producing Activities."
Derivative Financial Instruments
As a condition of the bond indenture agreement, the company entered into
commodity price swap derivative contracts to manage price risk with regard to
80% of its natural gas and crude oil production.
Statement of Accounting Financial Standards No. 133 (SFAS No. 133),
"Accounting for Derivative Instruments and Hedging Activities", as amended by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities--Deferral of the Effective Date of FASB No. 133", and SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities"
was effective for the Company as of January 1, 2001. SFAS No. 133 requires that
an entity recognize all derivatives as either assets or liabilities measured at
fair value. The accounting for changes in the fair value of a derivative depends
on the use of the derivative. Derivatives that are not hedges must be adjusted
to fair value through income. If the derivative is a hedge, depending on the
nature of the hedge, changes in the fair value of derivatives will either be
offset against the change in fair value of the hedged assets, liabilities, or
firm commitments through earnings or recognized in other comprehensive income
until the hedged item is recognized in earnings. The ineffective portion of a
derivative's change in fair value will be immediately recognized in earnings.
Use of Estimates
The financial statements have been prepared in conformity with generally
accepted accounting principles appropriate in the circumstances. In preparing
financial statements, Management makes informed judgments and estimates that
affect the reported amounts of assets and liabilities as of the date of the
financial statements and affect the reported amounts of revenues and expenses
during the reporting period. Actual results may differ from these estimates.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Attached, beginning on F-1, following signature page.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
CHANGE IN ACCOUNTANTS
On March 14, 2001, we terminated Hidalgo, Banfill, Zlotnik & Kermali, P.C.
("Hidalgo") as our independent auditors and engaged BDO Seidman, LLP ("BDO") as
our new auditors. Prior to such engagement, we had not consulted with BDO on
issues relating to our accounting principles or the type of audit opinion to be
issued with respect to our financial statements. Hidalgo's reports for the years
ended December 31, 1998 and 1999 contained an explanatory paragraph describing
the uncertainty about our ability to continue as a going concern due to our
default under our bank loan resulting from the commodity price decreases
experienced during the latter half of 1998 and our subsequent bankruptcy.
Hidalgo's reports for such periods did not contain any adverse opinion or
disclaimer of opinion, nor were they qualified (other than as described above),
or modified as to uncertainty, audit scope or accounting principles. There was
no disagreement between us and Hidalgo during any period of their engagement
through the date of their dismissal on any matter of accounting principles or
practices, financial statement disclosure or auditing scope or procedures which,
if not resolved to the satisfaction of Hidalgo, would have caused them to make
reference to the matter in their reports.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Our directors and principal executive officers are:
Name Age Position
---- --- --------
Richard Bowman.............................. 37 Founder, President, Chief Executive Officer and
Director
Jeffrey T. Janik............................ 49 Vice President, Operations
Suzanne R. Ambrose.......................... 42 Vice President, Treasurer and Chief Financial Officer
G. Bryan Dutt............................... 43 Director
Michel T. Halbouty.......................... 92 Director
Donald W. Riegle, Jr........................ 64 Director
Oliver G. Richard III....................... 49 Director
32
Richard Bowman has served as President, Chief Executive Officer and Director
since our formation in 1996. Mr. Bowman also served as Chairman of the Board,
President and Chief Executive Officer of Tribo Petroleum Corporation, our former
parent corporation, since its formation in 1992. Prior to founding Tribo, Mr.
Bowman was employed as an independent landman, serving Coastal Corporation,
Torch Energy and other independent oil and natural gas companies.
Jeffery T. Janik has served with us since June 1998 when he joined us as
Operations Manager. In June 2001, Mr. Janik became our Vice President,
Operations. Prior to joining us, Mr. Janik served as Vice President of
Operations at Baker-MO Services, Inc., an oil and gas service contractor from
April 1993 to June 1998.
Suzanne R. Ambrose has served with us since November 1998 when she joined us
as an accounting consultant. In February 2000, Ms. Ambrose became our Vice
President, Accounting. In June 2001, Ms. Ambrose became our Vice President,
Treasurer and Chief Accounting Officer. In November 2001, Ms. Ambrose became our
Vice President, Treasurer and Chief Financial Officer. Prior to joining us, Ms.
Ambrose provided accounting advice and services, on a contract basis, to WRT
Energy, Inc., an oil and natural gas exploration and production company, from
May 1996 to November 1998, and HLS Offshore, L.L.C., an oil field services
company, from January 1998 through May 1998. Ms. Ambrose served as controller of
Offshore Petroleum Divers, Inc., a wholly-owned subsidiary of Offshore Pipeline,
Inc., an oil field services company, from March 1989 through November 1995.
G. Bryan Dutt founded Ironman Energy Capital, L.P., a private investment
limited partnership, in 1999 and serves as its Managing Partner. Mr. Dutt served
as managing partner of Centennial Energy Partners; a private investment limited
partnership, from 1995 to 1999. From 1985 to 1995, he was an energy analyst at
Howard, Weil, Labouisse, Friedrichs Inc., an energy investment banking firm. He
is a past president of the New Orleans Financial Analyst.
Michel T. Halbouty has been Chairman of the Board and Chief Executive
Officer of Michel T. Halbouty Energy Co., an independent oil and natural gas
producer and operator, for over 20 years. Mr. Halbouty has served as President
of the American Association of Petroleum Geologists and is a member of the
National Academy of Engineering. Mr. Halbouty chaired President Reagan's Energy
Policy Advisory Task Force and later was appointed by President Reagan as leader
of the transition team on energy.
Donald W. Riegle, Jr. served in the U.S. Senate from 1976 through 1994 and
in the U.S. House of Representatives from 1967 through 1975. He served on the
Senate Banking Committee for eighteen years and as its chairman from 1989 to
1994. In March 2001, Mr. Riegle became Chairman of Government Relations for APCO
Worldwide, a global public affairs and strategic communications firm
headquartered in Washington, D.C. In January 1995, following his retirement from
the Senate, Mr. Riegle joined Shandwick International, a public relations and
public affairs firm, and component of the Interpublic Group of Companies, where
he served until March 2001 as Chairman of Government Relations. Mr. Riegle
currently serves on the board of Anthem, Inc., which is listed on the New York
Stock Exchange.
Oliver G. Richard III served as Chairman, President and Chief Executive
Officer of Columbia Energy Group from April 1995 until its acquisition in
November 2000. From November 2000 to present, Mr. Richard has been engaged in
private investment activities. Mr. Richard has served as Chairman, Chief
Executive Officer and President of New Jersey Resources and President and Chief
Executive Officer of Northern Natural Gas Pipeline, a subsidiary of Enron. Mr.
Richard was appointed to the Federal Energy Regulatory Commission by President
Ronald Reagan and served from 1982 to 1985. While at the FERC, he was
instrumental in forging initiatives to increase competition and efficiencies
among federally regulated energy providers.
In 1997, Mr. Richard consented to the entry of a cease-and-desist order to
settle issues related to reports filed with the SEC by New Jersey Resources
Corporation (NJR) in 1992, while Mr. Richard was its chairman and chief
executive officer. Mr. Richard neither admitted nor denied the issues identified
in the order in agreeing to the settlement.
The settlement related to long-term natural gas supply and purchase
contracts between subsidiaries of NJR and a third party, which the SEC found had
been arranged for the purpose of avoiding a write down of NJR's properties under
the full-cost ceiling test and were not bona fide transactions. As a result, the
SEC found that certain filings by NJR with the SEC during 1992 were materially
inaccurate and that NJR's reported net income and earnings per share for that
period were materially affected. The SEC did not require NJR to restate its
income or earnings for the period and did not impose any civil penalties.
Tri-Union does not believe that this order has had any adverse affect on Mr.
Richard's service as a board member of
33
other publicly held companies or that it will have any adverse affect on his
service as a director of Tri-Union.
MANAGEMENT OF TRI-UNION OPERATING COMPANY
The principal executive officers of Tri-Union Operating Company are the same
as the principal executive officers of Tri-Union Development Corporation. The
sole director of Tri-Union Operating is Richard Bowman.
ITEM 11. DIRECTOR AND EXECUTIVE COMPENSATION
DIRECTOR COMPENSATION
We intend to compensate our directors for their services and provide them
with equity incentives to allow them to participate in our future growth.
Currently our intention is to pay each director $75,000 per year, offer options
to purchase, subject to certain conditions, up to 0.5% of our common equity at a
nominal exercise price and to reimburse reasonable out of pocket expenses
incurred in connection with attending board meetings.
EXECUTIVE COMPENSATION
The following table sets forth certain information for fiscal years 1998,
1999 and 2000 with respect to the compensation paid to Mr. Bowman, our Chief
Executive Officer and our other executive officers that received annual
compensation (including salary and bonuses earned) that exceeded $100,000 for
those years. Mr. Bowman has historically determined the compensation of our
executive officers.
All Other
Name and Principal Positions Year Salary Bonus Compensation (1)(3)
---------------------------- ---------- ------------ ------------ ----------------------
Richard Bowman......................................... 2001 $ 320,833 $ 200,000 $ 11,507
President and Chief Executive Officer 2000 330,000 10,000 9,424
1999 382,500 - 8,305
*R. Kelly Plato(2) 2001 88,333 117,500 6,427
Vice President and Chief Financial Officer 2000 110,000 27,500 7,619
1999 100,000 8,000 -
Jeffrey T. Janik....................................... 2001 152,083 138,750 8,930
Vice President, Operations 2000 145,000 18,750 15,271
1999 145,000 25,000 14,171
Suzanne R. Ambrose(2).................................. 2001 140,000 111,250 4,003
Vice President, Treasurer and Chief 2000 135,000 21,250 2,501
Financial Officer 1999 142,653 10,000 -
- ----------
* Resigned September 2001.
(1) Amount includes automobiles furnished by us and premium payments we made
for health, dental, disability and life insurance policies for the
referenced individuals.
(2) Amount includes employment on a contract basis until February 2000.
(3) We had no stock option plans during 1999, 2000 or 2001.
RETENTION BONUSES
To provide an incentive for our executive officers and key employees through
the pendency of our bankruptcy, we incurred retention bonuses of $855,000 and
$301,740 during the years ended December 31, 2000 and 2001, respectively.
Following the closing of the original offering and our exit from bankruptcy
those funds were distributed to 67 persons as bonuses, including $100,000 to R.
Kelly Plato, $110,000 to Jeffrey T. Janik and $100,000 to Suzanne Ambrose.
EMPLOYMENT AGREEMENTS WITH EXECUTIVE OFFICERS
We are negotiating but have not yet finalized an employment agreement with
Richard Bowman to serve as our
34
Chairman of the Board, President and Chief Executive Officer. We anticipate that
this agreement will provide for a term commencing on June 18, 2001 and
continuing through April 30, 2006, unless renewed for additional periods. We
anticipate that Mr. Bowman will receive a base salary of $350,000 annually
during the initial calendar year, increasing annually by the greater of 5% or an
amount approved by our Board of Directors. Mr. Bowman will also be entitled to
other benefits including, but not limited to, paid vacation, an automobile
allowance, reimbursement of out-of-pocket business expenses and a performance
bonus which is expected to be equal to the greater of (i) an amount approved by
our Board of Directors or (ii) (A) zero, if our adjusted EBITDA is less than $40
million and (B) if our adjusted EBITDA is $40 million or more, then the sum of
(1) .5% of our EBITDA between zero and $59,999,999 and (2) 1% of our adjusted
EBITDA greater than $60,000,000. The employment agreement is also expected to
contain a severance package and a payment upon a change of control, the terms of
which are currently being negotiated.
We do not currently have employment agreements with our other executive
officers. We intend to enter into employment agreements with each of them on
terms that are reflective of current market conditions and are in the process of
negotiating these terms.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
An aggregate of 433,333 shares of our common stock were issued and
outstanding on December 31, 2001, consisting of 368,333 shares of class A common
stock and 65,000 shares of class B common stock. Of these shares, Richard
Bowman, our President and Chief Executive Officer, owns 238,333 shares of class
A common stock (or 55% of our common stock), the purchasers of units in the
original offering own an aggregate of 130,000 shares of class A common stock (or
30% of our common stock) and Jefferies & Company, Inc. owns 65,000 shares of
class B common stock (or 15% of our common stock).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
We historically have had a series of informal relationships with Richard
Bowman and his affiliated companies, including advances to Richard Bowman, our
sole shareholder, for travel and other business expenses.
Under the terms of the indenture, on a prospective basis, all transactions
with affiliates must be on terms as favorable to us as could be obtained from
unaffiliated third parties.
OFFICE LEASE WITH TRIBO PRODUCTION CO. LTD.
Effective April 1, 2001, we relocated our executive offices to 530 Lovett
Boulevard, Houston, Texas, in a building owned by our affiliate, Tribo
Production Co. Ltd., which is beneficially owned by Richard Bowman, our
President, Chief Executive Officer and director. We occupy the entire building,
which has approximately 9,355 square feet of office space. We currently occupy
this space at a base rental of $26,000 per month, which was determined based
upon independent market data. The base rental is subject to adjustment for
changes in the consumer price index during the term of the lease. Pursuant to
the lease, we are responsible for certain expenses associated with the building,
including property taxes, insurance, maintenance and utilities. The lease
expires on March 31, 2006. The lease contains five one-year renewal options at
the then prevailing market rental rate, which may be exercised upon six months
notice to our landlord. We believe the terms of this lease are as favorable to
us as could be obtained from unaffiliated third parties.
CERTAIN TRANSACTIONS WITH ATASCA RESOURCES, INC.
We have historically provided and intend to continue to provide limited
general and administrative services, such as accounting, landman and engineering
services to Atasca Resources, Inc., an entity owned and controlled by Richard
Bowman ("Atasca"). During 2000, we commissioned an independent peer group
analysis of companies similar to Atasca in order to determine market levels for
such services. Based upon this analysis and the actual services performed, we
allocated certain general and administrative expenses to Atasca. For the year
ended December 31, 2000 and 2001, we received reimbursements totaling $60,000,
respectively from Atasca for these services. We believe the terms of these
arrangements are as favorable to us as could be obtained from unaffiliated third
parties.
In addition, during 2000 and continuing until Tribo's properties were
assigned to Atasca and we merged with Tribo, a small number of Tribo's oil and
natural gas properties were operated by Atasca. Tribo paid Atasca for ordinary
and customary lease operating expense incurred in connection with the operation
of these properties. During the year ended December 31, 2000, we received oil
and natural gas revenues of $585,692 and incurred production and overhead
expenses of $237,807. During the year ended December 31, 2001, we received oil
and natural gas revenues of $155,490 and incurred production and overhead
expenses of $104,739.
35
CASH ADVANCES WITH AFFILIATED ENTITIES
Historically, we have made cash advances to, and have received cash advances
from, Atasca, Tribo Production Co., Ltd., BL Production Co., Ltd., and Atasca
Properties, Ltd., entities that are beneficially owned or controlled by Richard
Bowman. The advances were made primarily for insurance, oilfield services and
related activities and reimbursement of corporate expenses. Cash advanced from
these affiliates was $488,308 for the year ended December 31, 2000, and $292,221
for the year ended December 31, 2001, reducing the net balance owed to us from
these entities to $364,667 at December 31, 2000 and $72,496 at December 31,
2001. On June 18, 2001, all net amounts due from Mr. Bowman and entities owned
by him were forgiven as partial consideration for the assignment by Mr. Bowman
of his interest in a $3.3 million litigation settlement with Credit Lyonnais as
more fully described in the "Satisfaction of Certain Related Party Obligations"
section.
OTHER TRANSACTIONS WITH RICHARD BOWMAN
The total amount owed to us by Mr. Bowman for travel and other business
expenses was $625,199 and $133,670 at December 31, 2000 and 2001, respectively.
These advances were non-interest bearing and due on demand. On June 18, 2001,
accumulated amounts due through December 31, 2000 from Mr. Bowman and entities
owned by him were forgiven as partial consideration for the assignment by Mr.
Bowman of his interest in a $3.3 million litigation settlement with Credit
Lyonnais as more fully described in the "Satisfaction of Certain Related Party
Obligations" section.
SATISFACTION OF CERTAIN RELATED PARTY OBLIGATIONS
As noted in "Business and Properties -- Legal Proceedings," Richard Bowman
agreed to assign his interest in a $3.3 million litigation settlement with
Credit Lyonnais to us. Mr. Bowman agreed to assign this interest to us in return
for our transfer to Atasca of certain oil and natural gas properties (totaling
approximately 1.2 Bcfe, or 0.7% of our proved reserves, as of December 31, 2000)
at their book value of approximately $1.1 million and certain marketable
securities owned by Tribo Petroleum Corporation and the forgiveness of net
obligations owed to us by Mr. Bowman. Additionally, we released Tribo Production
Company, Ltd., BL Production Co., Ltd., and Atasca Properties, Ltd., (all wholly
owned by Mr. Bowman) from the net obligations they each owed to us. In July
2001, we merged with Tribo Petroleum Corporation. After giving effect to these
transactions, all balances owing to and from these related parties and us were
satisfied. As a consequence of these transactions, we recorded a one-time
reorganization expense of $1,985,442. The following table summarizes the oil and
gas properties and marketable securities transferred to Atasca, the net balances
owing to us by Mr. Bowman, Atasca Resources, Inc., and all other companies
controlled by Mr. Bowman that we forgave in this transaction.
Assets transferred and receivables forgiven by TDC
Oil and gas properties transferred to Atasca........................... $ 1,097,611
Marketable securities transferred to Atasca............................ 102,454
Richard Bowman......................................................... 581,975
Due from Tribo Production Co., Ltd..................................... 491,878
Due from Atasca Resources, Inc......................................... 109,796
Due from BL Production, LLC............................................ 55,844
-------------
Total..................................................... $ 2,439,558
=============
Liabilities of TDC cancelled
Due to Tribo Production Co., Ltd....................................... $ 2,388
Due to Atasca Resources, Inc........................................... 396,742
Due to Atasca Properties, Ltd.......................................... 16,885
Due to BL Production, LLC.............................................. 23,458
Due to Atasca Properties, Ltd.......................................... 14,643
-------------
Total Liabilities Cancelled............................... 454,116
-------------
Net Assets Transferred and Receivables Forgiven........... $ 1,985,442
=============
36
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in
the oil and natural gas industry that are used in this prospectus. All volumes
of natural gas referred to herein are stated at the legal pressure base to the
state or area where the reserves exit and at 60 degrees Fahrenheit and in most
instances are rounded to the nearest major multiple.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume of oil,
condensate or natural gas liquids.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalent, determined using the
ratio of six Mcf of natural gas to one Bbl of oil condensate or natural gas
liquids.
Behind pipe. Oil and natural gas in a potentially producing horizon
penetrated by a well bore the production of which has been postponed pending the
production of oil and natural gas from another formation penetrated by the well
bore.
Boe. Barrel of oil equivalent, determined using the ratio of one Bbl of
crude oil, condensate or natural gas liquids to six Mcf of natural gas.
Completion. The installation of permanent equipment for the production of
oil and natural gas, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
Development. The drilling and bringing into production of wells in addition
to the exploratory or discovery well on a lease.
Development well. A well drilled within the proved area of an oil or natural
gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing oil or natural
gas in sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.
Exploration. The search for oil and natural gas. Exploration operations
include: aerial surveys, geophysical surveys, geological studies, core testing,
and the drilling of test wells (wildcat wells).
Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which working interests are owned.
Horizontal drilling. A drilling technique that permits the operator to
contact and intersect a larger portion of the producing horizon than
conventional vertical drilling techniques and can result in both increased
production rates and greater ultimate recoveries of oil and natural gas.
MBbls. One thousand barrels of oil.
MBoe. One thousand barrels of oil equivalent, determined using the ratio of
one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural
gas.
Mcf. One thousand cubic feet of natural gas.
Mcfd. One thousand cubic feet of natural gas per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
37
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of natural gas equivalent, determined using
the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or
natural gas liquids.
MMS. The Minerals Management Service.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells, as the case may be.
NYMEX. The New York Mercantile Exchange.
Oil. Crude oil, condensate and natural gas liquids.
Plugback. A workover procedure that converts a well from a deeper
non-producing zone to a shallower producing zone.
Present value and PV-10 Value. When used with respect to oil and natural gas
reserves, represents the estimated future net revenue to be generated from the
production of proved reserves, determined in all material respects in accordance
with the rules and regulations of the SEC (generally using prices and costs in
effect as of the date indicated) without giving effect to non-property related
expenses such as general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion and amortization, discounted
using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing oil or
natural gas in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production.
Proved developed reserves. Proved reserves that are expected to be recovered
from existing wellbores, whether or not currently producing, without drilling
additional wells. Production of such reserves may require a recompletion.
Proved reserves. The estimated quantities of crude oil, natural gas, and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage.
Recompletion. The completion for production of an existing wellbore in
another formation from that in which the well has been previously completed.
Reserve life. A ratio determined by dividing proved reserves by production
from such reserves for the prior 12-month period.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reserves.
Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.
Standardized Measure. The estimated future net revenue, including the
effects of estimated future income tax expense, to be generated from the
production of proved reserves, determined in all material respects in accordance
with
38
the rules and regulations of the SEC (generally using prices and costs in effect
as of the date indicated) without giving effect to non-property related expenses
such as general and administrative expenses and debt service or to depreciation,
depletion and amortization, discounted using an annual discount rate of 10%.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
Wellbore. The hole made by the drill bit.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
Workover. Operations on a producing well to restore or increase production.
39
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.1 Debtor's First Amended Plan of Reorganization approved on
May 23, 2001 by the United States Bankruptcy Court for the
Southern District of Texas, Houston Division (1)
2.2 Agreement and Plan of Merger between Tribo Petroleum
Corporation and Tri-Union Development Corporation, dated
July 27, 2001 (1)
3.1 Restated Articles of Incorporation for Tri-Union Development
Corporation, as amended through July 2001. (1)
3.2 By-laws of Tri-Union Development Corporation as amended and
restated through June 18, 2001. (1)
3.3 Certificate of Incorporation for Tri-Union Operating Company
dated as of November 1, 1974, as amended through May 30,
1996 (1)
3.4 By-laws of Tri-Union Operating Company as amended and
restated through June 18, 2001. (1)
4.1 Indenture Agreement by and between Tri-Union Development
Corporation, as Issuer, Tribo Petroleum Corporation, as
Parent Guarantor, and Firstar Bank, National Association, as
Trustee, dated June 18, 2001. (1)
4.2 Purchase Agreement between Tribo Petroleum Corporation,
Tri-Union Development Corporation, Tri-Union Operating
Company and Jefferies & Company, Inc., dated June 18, 2001.
(1)
4.3 Registration Rights Agreement by and among Tri-Union
Development Corporation, Tri-Union Operating Company, Tribo
Petroleum Corporation and Jefferies & Company, Inc., dated
June 18, 2001. (1)
4.4 Equity Registration Rights Agreement by and between Tribo
Petroleum Corporation and Jefferies & Company, Inc., dated
June 18, 2001. (1)
4.5 Intercreditor and Collateral Agency Agreement among
Tri-Union Development Corporation, Tribo Petroleum
Corporation, Tri-Union Operating Company and Wells Fargo
Bank Minnesota, National Association, as Collateral Agent,
and Firstar Bank, National Association, as Trustee, dated
June 18, 2001. (1)
4.6 Pledge and Collateral Account Agreement among Wells Fargo
Bank Minnesota, National Association, as Collateral Agent,
Tribo Petroleum Corporation, Tri-Union Development
Corporation and Tri-Union Operating Company, as Obligors,
dated June 18, 2001. (1)
4.7 Mortgage, Deed of Trust, assignment of Production, Security
Agreement and Financing Statement of Tri-Union Development
Corporation, dated June 18, 2001. (1)
10.1 Amended and Restated Lease Agreement between Tribo
Production Company, Ltd. and Tri-Union Development
Corporation, dated June 18, 2001. (1)
10.2 ISDA Master Agreement by and between Bank of America, N.A.
and Tri-Union Development Corporation, dated June 18, 2001.
(1)
16.1 Letter of Hidalgo, Banfill, Zlotnik & Kermali, P.C. (1)
21.1 Subsidiaries of Registrant. (1)
23.1* Consent of BDO Seidman, LLP.
23.2* Consent of Hidlago, Banfill, Zlotmik & Kermali, P.C.
23.3* Consent of DeGolyer and MacNaughton., Inc.
23.4* Consent of Huddleston & Co., Inc.
* Filed herewith
(1) Incorporation by reference to the comparably numbered Exhibit to the
Registration Statement on Form S-4 filed by the Issuer November 2, 2001.
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 the undersigned, thereunto duly authorized.
TRI-UNION DEVELOPMENT CORPORATION
By: /s/ RICHARD BOWMAN 4/1/02
- ---------------------------------------------------- -----------------
Richard Bowman Date
President and 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 dated indicated.
By: /s/ SUZANNE R. AMBROSE 4/1/02
- ----------------------------------------------------- -------------------
Suzanne R. Ambrose Date
Vice President, Treasurer and Chief
Financial Officer
By: /s/ G. BRYAN DUTT 4/1/02
- ----------------------------------------------------- -------------------
G. Bryan Dutt Date
Director
By: /s/ MICHEL T. HALBOUTY 4/1/02
- ----------------------------------------------------- -------------------
Michel T. Halbouty Date
Director
By: /s/ DONALD W. RIEGLE, JR. 4/1/02
- ----------------------------------------------------- -------------------
Donald W. Riegle, Jr. Date
Director
By: /s/ OLIVER G. RICHARD III 4/1/02
- ----------------------------------------------------- -------------------
Oliver G. Richard III Date
Director
41
INDEX TO AUDITED FINANCIAL STATEMENTS
TRI-UNION DEVELOPMENT CORPORATION (FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED FINANCIAL STATEMENTS;
Report of Independent Certified Public Accountants..................................................... F-2
Report of Independent Certified Public Accountants..................................................... F-3
Consolidated Balance Sheets as of December 31, 2000 and 2001........................................... F-4
Consolidated Statements of Operations and Comprehensive Income (Loss) for
The Years Ended December 31, 1999, 2000 and 2001.................................................... F-5
Consolidated Statements of Stockholders' Equity (Capital Deficit) for the Years
Ended December 31, 1999, 2000 and 2001.............................................................. F-6
Consolidated Statements of Cash Flows for the Years Ended December 31,
1999, 2000 and 2001................................................................................. F-7
Notes to Consolidated Financial Statements............................................................. F-8
F-1
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors
Tri-Union Development Corporation (formerly Tribo Petroleum Corporation)
Houston, Texas
We have audited the accompanying consolidated balance sheets of Tri-Union
Development Corporation (formerly Tribo Petroleum Corporation) and subsidiary as
of December 31, 2000 and 2001, and the related consolidated statements of
operations and comprehensive income (loss), stockholders' equity (capital
deficit) and cash flows for the years then ended. These financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audits 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 Tri-Union
Development Corporation and subsidiary at December 31, 2000 and 2001, and the
results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of
America.
BDO SEIDMAN, LLP
Houston, Texas
March 18, 2002, except for Note 15,
which is as of April 1, 2002
F-2
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors
Tri-Union Development Corporation (formerly Tribo Petroleum Corporation)
Houston, Texas
We have audited the accompanying consolidated statements of operations and
comprehensive income (loss), stockholders' equity (capital deficit) and cash
flows of Tri-Union Development Corporation (formerly Tribo Petroleum
Corporation) and subsidiaries for the year ended December 31, 1999. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the results of operations and cash
flows of Tri-Union Development Corporation and subsidiaries for the year ended
December 31, 1999, in conformity with generally accepted accounting principles.
HIDALGO, BANFILL, ZLOTNIK & KERMALI, P.C.
Houston, Texas
April 22, 2000, except as to Note 12,
which is as of March 23, 2001, and
notes 14 and 16 which is as of
July 30, 2001
F-3
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED BALANCE SHEETS
At December 31,
--------------------------------------
2000 2001
------------------ -----------------
ASSETS
Current assets:
Cash and cash equivalents.............................................................. $ 32,989,939 $ 4,764,545
Restricted cash........................................................................ - 8,929,566
Accounts receivable, net of allowance for doubtful accounts of
$351,505 and $1,376,970.............................................................. 24,546,998 13,860,164
Marketable securities.................................................................. 472,248 -
Prepaid and other...................................................................... 1,512,174 1,960,104
Derivative contracts................................................................... - 9,525,317
------------------ -----------------
Total current assets................................................................. 59,521,359 39,039,696
------------------ -----------------
Oil and natural gas properties - full cost method, net.................................... 87,132,723 85,524,756
Other assets
Restricted cash and bonds.............................................................. 4,674,645 5,225,832
Furniture, fixtures and equipment, net................................................. 175,521 1,147,611
Receivables from affiliates, net....................................................... 989,866 206,116
Deferred loan costs, net............................................................... 99,700 17,034,817
Derivative contracts................................................................... - 2,973,627
------------------ -----------------
Total other assets................................................................... 5,939,732 26,588,003
------------------ -----------------
$ 152,593,814 $ 151,152,455
================== ================
LIABILITIES AND STOCKHOLDERS' EQUITY (CAPITAL DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities............................................... $ 26,609,284 $ 22,904,154
Accounts payable subject to renegotiation.............................................. - 5,133,667
Accrued interest....................................................................... 7,224,477 1,399,306
Notes payable.......................................................................... 333,880 965,875
Current maturities of senior secured notes............................................. - 20,000,000
------------------ -----------------
34,167,641 50,403,002
------------------ -----------------
Pre-petition liabilities subject to compromise:
Note payable........................................................................... 104,323,500 -
Accrued interest....................................................................... 6,226,808 -
Accounts payable and accrued liabilities - unsecured................................... 38,015,232 -
------------------ -----------------
Total pre-petition liabilities subject to compromise................................. 148,565,540 -
Senior secured notes...................................................................... - 89,172,434
------------------ -----------------
182,733,181 139,575,436
Commitments and contingencies (Notes 4, 10 and 15)
Stockholders' equity (capital deficit):
Class A common stock, $0.01 par value, 445,000 shares authorized;
238,333 and 368,333 shares issued and outstanding.................................... 2,383 3,683
Class B common stock, $0.01 par value, 65,000 shares authorized;
none and 65,000 shares issued and outstanding........................................ - 650
Additional paid in capital............................................................. - 25,220,285
Deficit................................................................................ (30,141,750) (13,647,599)
------------------ ----------------
Total stockholders' equity (capital deficit)......................................... (30,139,367) 11,577,019
------------------ -----------------
$ 152,593,814 $ 151,152,455
================== =================
See accompanying notes to consolidated financial statements.
F-4
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
Years Ended December 31,
--------------------------------------------------------
1999 2000 2001
----------------- ----------------- -----------------
Revenues and other:
Oil and natural gas revenues........................................ $ 36,270,343 $ 73,452,054 $ 80,516,275
Gain (loss) on marketable securities................................ - 995,180 (556,735)
Gain on derivative contracts........................................ - - 12,498,944
Other............................................................... 1,495,393 28,404 780,967
----------------- ----------------- -----------------
Total revenues and other...................................... 37,765,736 74,475,638 93,239,451
----------------- ----------------- -----------------
Expenses:
Lease operating expense............................................. 15,542,277 19,485,359 19,947,972
Workover expense.................................................... 2,410,410 6,649,074 5,916,356
Production taxes.................................................... 704,855 1,968,342 1,740,162
Depreciation, depletion and amortization............................ 11,040,035 13,506,477 12,188,841
General and administrative.......................................... 5,236,733 4,328,358 6,972,544
Interest expense ................................................... 11,981,460 12,757,863 21,144,957
----------------- ----------------- -----------------
Total expenses................................................ 46,915,770 58,695,473 67,910,832
----------------- ----------------- -----------------
Income (loss) before reorganization costs and income taxes............. (9,150,034) 15,780,165 25,328,619
Reorganization costs................................................... - 21,487,191 8,834,468
----------------- ----------------- -----------------
Income (loss) before income taxes...................................... (9,150,034) (5,707,026) 16,494,151
Provision for income taxes - current................................... - 79,000 -
----------------- ----------------- -----------------
Net income (loss)...................................................... (9,150,034) (5,786,026) 16,494,151
Other comprehensive income (loss):
Unrealized gains (losses) on available-for-sale-securities.......... 1,803 (1,803) -
----------------- ------------------ -----------------
Comprehensive income (loss)............................................ $ (9,148,231) $ (5,787,829) $ 16,494,151
================ ================ =================
Net income (loss) per share - basic and diluted........................ $ (38.39) $ (24.28) $ 48.01
================ ================ =================
Weighted average shares outstanding.................................... 238,333 238,333 343,580
================= ================= =================
See accompanying note to consolidated financial statements.
F-5
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (CAPITAL DEFICIT)
Class A Class B Accumulated
Common Stock Common Stock Additional Retained Other
---------------- ----------------- Paid in Earnings Comprehensive
Shares Amount Shares Amount Capital (Deficit) Income (Loss) Total
------ ------ ------ ------ ---------- ----------- --------------- ------------
Balance, January 1,
1999.................. 238,333 $ 2,383 - $ - $ - $(15,205,690) $ - $(15,203,307)
Net loss.............. - - - - - (9,150,034) - (9,150,034)
Change in unrealized
gains on available-
for-sale-securities - - - - - - 1,803 1,803
------- ------- ------ ------- ---------- ------------ --------------- ------------
Balance, December 31,
1999.................. 238,333 2,383 - - - (24,355,724) 1,803 (24,351,538)
Net loss.............. - - - - - (5,786,026) - (5,786,026)
Change in unrealized
gains on available-
for-sale-securities - - - - - - (1,803) (1,803)
------- ------- ------ ------- ---------- ------------ --------------- ------------
Balance, December 31,
2000.................. 238,333 2,383 - - - (30,141,750) - (30,139,367)
Net income............ - - - - - 16,494,151 - 16,494,151
Stock issuance in
conjunction with
units offering...... 130,000 1,300 65,000 650 25,220,285 - - 25,222,235
------- ------- ------ ------- ----------- ------------ --------------- ------------
Balance, December 31,
2001.................. 368,333 $ 3,683 65,000 $ 650 $25,220,285 $(13,647,599) $ - $ 11,577,019
======= ======= ====== ======= =========== ============ =============== ============
See accompanying notes to consolidated financial statements.
F-6
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
Years Ended December 31,
--------------------------------------------------------
1999 2000 2001
----------------- ----------------- -----------------
Cash flows from operating activities:
Net income (loss)................................................... $ (9,150,034) $ (5,786,026) $ 16,494,151
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities:
Depreciation, depletion and amortization........................ 11,040,035 13,506,477 12,188,841
Amortization of bond discount................................... - - 3,922,434
Amortization of deferred loan costs............................. - - 3,208,151
Loss (gain) on sale of marketable securities.................... - (995,179) 556,735
Accretion of bond interest income............................... (219,478) (138,040) (123,471)
Gain on sale of equipment....................................... - - (4,961)
Reorganization costs............................................ - 21,487,191 8,834,468
Gain on derivative contracts.................................... - - (12,498,944)
Changes in assets and liabilities:
Restricted cash................................................... - - (8,929,566)
Accounts receivable............................................... (3,085,313) (15,389,358) 10,686,834
Prepaid expenses.................................................. (239,304) (585,888) (447,930)
Receivables from affiliates....................................... (752,554) 203,071 (1,627)
Accounts payable and accrued liabilities.......................... 14,533,644 12,346,569 (11,163,089)
Accounts payable subject to renegotiation......................... - - 5,133,667
Pre-petition liabilities subject to compromise.................... - 18,043,910 (44,242,040)
----------------- ----------------- -----------------
Net cash (used in) provided by operating activities before
reorganization items.............................................. 12,126,996 42,692,727 (16,386,347)
----------------- ----------------- -----------------
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid........................... - (2,536,788) (6,161,956)
Interest earned during bankruptcy................................... - 538,841 945,722
----------------- ----------------- -----------------
Net cash used for reorganization items............................ - (1,997,947) (5,216,234)
----------------- ----------------- -----------------
Net cash provided by (used in) operating activities............. 12,126,996 40,694,780 (21,602,581)
----------------- ----------------- -----------------
Cash flows from investing activities:
Purchase of marketable securities................................... (232,268) (1,118,069) (742,910)
Proceeds from sale of marketable securities......................... - 1,874,245 555,964
Additions to oil and natural gas properties......................... (13,572,444) (10,877,657) (13,597,525)
Purchase of furniture, fixtures and equipment....................... (40,185) (31,280) (1,192,422)
Proceeds from disposal of equipment................................. 4,059 - 18,503
Proceeds from sales of oil and natural gas properties............... 2,262,300 389,971 2,225,529
Purchase of restricted cash and bonds............................... (3,664,957) (355,000) (427,717)
Proceeds from restricted marketable securities...................... 3,300,000 - -
----------------- ----------------- -----------------
Net cash used in investing activities............................. (11,943,495) (10,117,790) (13,160,578)
----------------- ----------------- -----------------
Cash flows from financing activities:
Proceeds from unit offering......................................... - - 113,444,294
Payments of long-term debt.......................................... (300,000) (376,500) (104,323,500)
Payment of loan fees................................................ (20,927) - (3,215,024)
Increase (decrease) in notes payable................................ 278,613 (24,547) 631,995
----------------- ----------------- -----------------
Net cash provided by (used in) financing activities............... (42,314) (401,047) 6,537,765
----------------- ----------------- -----------------
Net increase (decrease) in cash and cash equivalents................... 141,187 30,175,943 (28,225,394)
Cash and cash equivalents - beginning of year.......................... 2,672,809 2,813,996 32,989,939
----------------- ----------------- -----------------
Cash and cash equivalents - end of year................................ $ 2,813,996 $ 32,989,939 $ 4,764,545
================= ================= =================
Supplemental disclosures of cash flow information:
Interest paid during the period..................................... $ 7,100,562 $ 4,039,520 $ 24,805,447
Income taxes paid................................................... - - 79,000
Non-cash transactions:
Accrued interest added to debt...................................... 3,600,000 - -
Transfer of long-term debt to pre-petition liabilities subject to
compromise........................................................ - 104,700,000 -
Discount on unit offering........................................... - - (24,750,000)
Issuance of Class B common stock.................................... - - 11,000,000
Transfer of oil and natural gas properties to affiliate............. - - 1,097,611
Reorganization costs accrued in accounts payable and accrued
liabilities....................................................... - 1,914,753 967,505
Reorganization costs accrued in pre-petition liabilities subject to
compromise........................................................ - 17,794,272 -
See accompanying notes to consolidated financial statements.
F-7
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- BASIS OF PRESENTATION
Basis of Presentation
Tri-Union Development Corporation ("New TDC") formerly Tribo Petroleum
Corporation ("Tribo") was incorporated in the state of Texas in September 1992.
New TDC and its subsidiary ("the Company") is an independent oil and natural gas
company engaged in the acquisition, operation and development of oil and natural
gas properties primarily in areas of Texas and Louisiana, offshore in the
shallow waters of the Gulf of Mexico, and in the Sacramento Basin of northern
California.
The consolidated financial statements include the accounts of New TDC and
its wholly owned subsidiary Tri-Union Operating Company ("TOC"), which was
incorporated in the State of Delaware in November 1974. All significant
intercompany accounts and transactions have been eliminated in consolidation.
Prior to July 2001, New TDC had an additional wholly owned subsidiary
Tri-Union Development Corporation ("TDC"). In July 2001, New TDC and TDC merged
and the surviving corporation was New TDC. Accordingly, the assets, liabilities
and operations of TDC are included with those of New TDC for all periods
presented in the financial statements.
NOTE 2 -- LIQUIDITY AND MANAGEMENT'S PLANS
As described in Note 10, a $28,125,000 payment of principle and interest on
the Company's senior secured notes payable is due on June 1, 2002 and an
additional scheduled interest payment of $6,875,000 is due on December 1, 2002.
Management is pursuing several capital-raising options in order to meet these
obligations. The Company is currently (a) actively marketing to sell all or part
of its Texas and Louisiana oil and gas properties, (b) seeking a line of credit
of between $15 and $20 million with an investment banking firm for which a term
sheet has been received, (c) selling a portion of its derivative contracts,
which was accomplished March 28, 2002 (see Note 15), and (d) using existing cash
and cash generated from continuing operations to meet these upcoming
obligations. Several offers to purchase the Company's Texas and Louisiana
properties have been received to date and, if accepted, would provide the
Company with sufficient capital to meet their upcoming obligations. To date, no
definitive agreement to sell these properties has been made.
To the extent the cash generated from oil and gas property sales, the line
of credit, sale of derivative contracts, and continuing operations are
insufficient to meet the company's debt obligations as well as its projected
working capital needs, the Company will have to raise additional capital. No
assurance can be given that additional funding will be available, or if
available, will be on terms acceptable to the Company.
NOTE 3 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The accompanying financial statements are prepared in conformity with
accounting principles generally accepted in the United States of America which
require management to make estimates and assumptions that effect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Significant assumptions are
required in the valuation of proved oil and natural gas reserves, which as
described herein may affect the amount at which oil and natural gas properties
are recorded. Actual results could differ materially from these estimates.
Restricted Cash and Bonds
The Company had restricted cash balances at December 31, 2000 and 2001 of
$372,696 and $683,813, respectively. These restricted cash balances are pledged
for regulatory operating deposits and performance bonds.
In addition, at December 31, 2000 the Company had zero coupon U.S. Treasury
Bonds with a 2019 maturity value of $12,250,000, held in trust and pledged as
collateral for bonds issued to the Minerals Management Service ("MMS") for the
plugging and abandonment of certain wells and the decommissioning of offshore
platforms with a carrying value of $4,301,849. During July 2001, the Company was
required to replace its pledged collateral and issue $9,850,000 of new bonds to
the MMS. The zero U.S. Treasury Bonds were sold for $4,248,048 and cash in the
amount of $4,500,000 was deposited into a restricted interest bearing money
market account as collateral for the new bonds. At December 31, 2001, the
restricted money market account had a balance of $4,542,019.
Marketable Securities
The Company's marketable securities that are bought and held principally for
the purpose of selling them in the near term are classified as trading
securities. Trading securities are recorded at fair value on the balance sheet
as current assets, with the change in fair value during the period included in
earnings.
Marketable securities that the Company has the positive intent and ability
to hold to maturity are classified as held-to-maturity securities and recorded
at amortized cost. Marketable securities not classified as either
held-to-maturity or trading securities are classified as available-for-sale
securities. Available-for-sale securities are recorded at fair value in the
accompanying balance sheet, with the change in fair value during the period
excluded from earnings and recorded
F-8
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
net of tax as a component of other comprehensive income.
Oil and Natural Gas Interests
The Company follows the full cost method of accounting for oil and natural
gas property acquisition, exploration and development activities. Under this
method, all productive and nonproductive costs incurred in connection with the
acquisition of, exploration for and development of oil and natural gas reserves
for each cost center are capitalized. Capitalized costs include lease
acquisitions, geological and geophysical work, delay rentals and the costs of
drilling, completing and equipping oil and natural gas wells. Gains or losses
are recognized only upon sales or dispositions of significant amounts of oil and
natural gas reserves. Proceeds from all other sales or dispositions are treated
as reductions to capitalized costs.
Internal costs, including salaries, benefits and other internal salary
related costs, which can be directly identified with acquisition, exploration or
development activities are capitalized while any costs related to production,
general corporate overhead, or similar activities are charged to expense.
Geological and geophysical costs not directly associated with a specific
unevaluated property are included in the amortization base as incurred.
Capitalized internal costs directly identified with the Company's acquisition,
exploration and development activities amounted to approximately $764,000,
$767,000 and $856,000 in 1999, 2000 and 2001, respectively. Internal costs
included in capitalized oil and gas properties amounted to approximately
$2,212,000 and $3,067,000 at December 31, 2000 and 2001, respectively.
The capitalized costs of oil and natural gas properties, plus estimated
future development costs relating to proved reserves and estimated costs of
plugging and abandonment, net of estimated salvage value, are amortized on the
unit-of-production method based on total proved reserves. The computation of
depreciation, depletion and amortization ("DD&A") takes into consideration
restoration, dismantlement and abandonment costs and the anticipated proceeds
from equipment salvage. The estimated restoration, dismantlement and abandonment
costs for onshore properties are expected to be offset by the estimated salvage
value of lease and well equipment. The Company has recorded an offshore
abandonment liability of $3,383,000 as of December 31, 2001 based on total
expected abandonment costs of approximately $12,238,000. This liability is
included in accumulated DD&A on the consolidated balance sheets. For the years
ended December 31, 1999, 2000, and 2001, the Company recorded accretion of its
offshore abandonment liability of $905,000, $1,083,000, and $709,000,
respectively. This accretion is recorded as a component of DD&A expense in the
consolidated statements of operations. (See Note 13).
The costs of unproved properties are excluded from amortization until the
properties are evaluated, subject to an annual assessment of whether impairment
has occurred. In determining whether impairment of unevaluated properties has
occurred, management evaluates, among other factors, current oil and natural gas
industry conditions, capital availability, primary lease terms of the
properties, holding periods of the properties, and available geological and
geophysical data. Any impairment assessed is added to the costs being amortized.
Costs of drilling exploratory dry holes are included in the amortization base
immediately upon determination that a well is dry. At December 31, 2001, all of
the Company's oil and gas properties were classified as evaluated and are
included in the amortization base. The Company's proved oil and natural gas
reserves were estimated by an independent petroleum engineering firm.
The capitalized oil and natural gas property costs, less accumulated
depreciation, depletion and amortization and related deferred income taxes, if
any, are generally limited to an amount (the ceiling limitation) equal to the
sum of (a) the present value of estimated future net revenues computed by
applying current prices in effect as of the balance sheet date (with
consideration of price changes only to the extent provided by contractual
arrangements) to estimated future production of proved oil and natural gas
reserves, less estimated future expenditures (based on current costs) to be
incurred in developing and producing the reserves using a discount factor of 10%
and assuming continuation of existing economic conditions; and (b) the cost of
investments in unevaluated properties excluded from the costs being amortized.
No ceiling write down was recorded in 1999, 2000 or 2001.
General and administrative expenses are reported net of amounts allocated to
working interest owners of the oil and natural gas properties operated by Tribo,
net of amounts charged for administrative and overhead costs and net of amounts
capitalized pursuant to the full cost method of accounting.
F-9
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Furniture, Fixtures and Equipment
Furniture, fixtures and equipment are carried at cost. Depreciation is
provided on the straight-line basis using estimated useful lives of five to ten
years. At the time of a retirement or sale, the related cost and accumulated
depreciation are removed from the accounts, and any resulting gain or loss is
recorded to income. Maintenance and repairs are charged to expense as incurred.
Renewals, betterments and expenditures which increase the value of the property
or extend its useful life, are capitalized.
Cash Equivalents
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
Financial Instruments and Concentration of Credit Risk
Financial instruments that subject the Company to credit risk consist of
accounts receivable. The receivables are primarily from companies in the oil and
natural gas industry or from individual oil and natural gas investors. During
1999, 2000 and 2001, the Company had revenues from certain customers exceeding
10% of total revenues as follows:
1999 2000 2001
---------- ---------- ----------
Customer A.................. 35% 31% 22%
Customer B.................. 11% - -
Customer C.................. - 11% -
Customer D.................. - - 19%
Customer E.................. - - 11%
In the case of receivables from joint interest owners, the Company may have
the ability to offset amounts due against the participant's share of production
from the related property.
The estimated fair value of financial instruments has been determined by the
Company using available market information and appropriate valuation
methodologies. The fair value of these instruments approximates their carrying
value at December 31, 2000 and 2001.
Income Taxes
The Company accounts for income taxes using the "liability method."
Accordingly, deferred tax liabilities or assets are determined based on
temporary differences between the financial statement and income tax bases of
assets and liabilities using enacted tax rates in effect for the year in which
the differences are expected to reverse. The effect of a change in tax rates is
recognized in income in the period such change occurs.
Environmental Matters
Environmental costs are expensed or capitalized depending on their future
economic benefit. Costs that relate to an existing condition caused by past
operations and have no future economic benefit are expensed. Liabilities for
future expenditures of a noncapital nature are recorded when future
environmental expenditures and/or remediation is deemed probable, and the costs
can be reasonably estimated. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value.
Derivative Transactions
The Company sometimes enters into fixed-price physical delivery contracts
and commodity price swap derivatives to manage price risk with regard to a
portion of its natural gas and crude oil production. The Company recognizes
revenues under fixed-price physical delivery contracts as the gas is sold. Prior
to January 1, 2001, the Company followed the guidance in Statement of Financial
Accounting Standards No. 80 ("SFAS No. 80"), "Accounting for Futures Contracts",
in accounting for its commodity price swap derivative contracts. Under SFAS No.
80, commodity price swap derivative contracts were accounted for using the hedge
method of accounting. Under this method, realized gains and losses on qualifying
hedges were recognized in oil and gas revenues when the associated production
occurred and the resulting cash flows were reported as cash flows from
operations. These swap contracts were designated as hedges and changes in their
fair
F-10
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
value correlated with changes in the price of anticipated future production such
that the Company's exposure to the effects of commodity price changes was
reduced. If a contract did not qualify as a hedge, any changes in its fair value
were recorded currently.
Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"),
"Accounting for Derivative Instruments and Hedging Activities", as amended by
SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities --
Deferral of the Effective Date of FASB No. 133", and SFAS No. 138, "Accounting
for Certain Derivative Instruments and Certain Hedging Activities" was effective
for the Company as of January 1, 2001. SFAS No. 133 requires that an entity
recognize all derivatives as either assets or liabilities measured at fair
value. The accounting for changes in the fair value of a derivative depends on
the use of the derivative. Derivatives that are not hedges are adjusted to fair
value through income. If the derivative is a hedge, depending on the nature of
the hedge, changes in the fair value of derivatives are either offset against
the change in fair value of the hedged assets, liabilities, or firm commitments
through earnings or recognized in other comprehensive income until the hedged
item is recognized in earnings. The ineffective portion of a derivative's change
in fair value is immediately recognized in earnings.
Earnings (Loss) Per Share
Basic earnings per share includes no dilution and is computed by dividing
income available to common stockholders by the weighted average number of common
shares outstanding for the period. Diluted earnings per share reflects the
potential dilution of securities that could share in the earnings of an entity.
The Company had no potentially dilutive securities for the years ended December
31, 1999, 2000 or 2001.
Comprehensive Income (Loss)
The Company has elected to report comprehensive income (loss) in a
consolidated statement of operations and comprehensive income (loss).
Comprehensive income (loss) is comprised of net income (loss) and all changes to
stockholders' equity, except those due to investments by stockholders, changes
in paid-in capital and distributions to stockholders, and is presented net of
income taxes.
Reclassifications
Certain reclassifications have been made to the 1999 and 2000 balances to
conform to the 2001 presentation.
Recently Issued Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board finalized FASB
Statements No. 141, Business Combinations ("SFAS 141"), and Statement No. 142,
Goodwill and Other Intangible Assets ("SFAS 142"). SFAS 141 requires the use of
the purchase method of accounting and prohibits the use of the
pooling-of-interests method of accounting for business combinations initiated
after June 30, 2001. SFAS 141 also requires that the Company recognize acquired
intangible assets apart from goodwill if the acquired intangible assets meet
certain criteria. SFAS 141 applies to all business combinations initiated after
June 30, 2001 and for purchase business combinations completed on or after July
1, 2001. It also requires, upon adoption of SFAS 142, that the Company
reclassify the carrying amounts of intangible assets and goodwill based on the
criteria in SFAS 141. SFAS 142 requires, among other things, that companies no
longer amortize goodwill, but instead test goodwill for impairment at least
annually. In addition, SFAS 142 requires that the Company identify reporting
units for the purposes of assessing potential future impairments of goodwill and
reassess the amortization of intangible assets with an indefinite useful life.
An intangible asset with an indefinite useful life should be tested for
impairment in accordance with SFAS 142. SFAS 142 is required to be applied in
fiscal years beginning after December 15, 2001 to all goodwill and other
intangible assets recognized at that date, regardless of when those assets were
initially recognized. SFAS 142 requires the Company to complete a transitional
goodwill impairment test six months from the date of adoption. The Company is
also required to reassess the useful lives of other intangible assets within the
first interim quarter after adoption of SFAS 142. Currently, the Company is
assessing but has not yet determined how the adoption of SFAS 141 and SFAS 142
will impact its financial position and results of operations.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations, SFAS No. 143, which amends SFAS No. 19, Financial Accounting and
Reporting by Oil and Gas Producing Companies, is applicable to all companies.
SFAS No. 143, which is effective for fiscal years beginning after June 15, 2002,
addresses financial accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. It applies to legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction, development
and/or the normal operation of a long-lived asset, except for certain
obligations of lessees. As used in SFAS No. 143, a legal obligation is an
obligation that a party is required to settle as a result of an existing or
enacted law, statue, ordinance, or written or oral contract or by legal
construction of a contract under the doctrine of promissory estoppel. As of the
date of this filing, the Company is still assessing the requirements
F-11
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
of SFAS No. 143 and has not determined the impact the adoption will have on our
financial condition or results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment
or Disposal of Long-lived Assets. SFAS No. 144, which supercedes SFAS No. 121,
Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to
be Disposed Of and amends ARB No. 51, Consolidated Financial Statements,
addresses financial accounting and reporting for the impairment or disposal of
long-lived assets. SFAS No. 144 is effective for fiscal years beginning after
December 15, 2001, and interim financials within those fiscal years, with early
adoption encouraged. The provisions of SFAS No. 144 are generally to be applied
prospectively. As of the date of this filing, the Company is still assessing the
requirements of SFAS No. 144 and has not determined the impact the adoption will
have on our financial condition or results of operations.
NOTE 4 -- EMERGENCE FROM BANKRUPTCY
In October, 1997, the Company obtained a short-term bank loan of $105
million (the "Acquisition Facility") to finance the purchase of certain oil and
gas properties. During 1997 and through May 1998, the Company drew approximately
$35 million and $69 million, respectively, against the Acquisition Facility. In
August, 1998 before the Company was able to refinance the Acquisition Facility
with term debt, commodity prices began falling, with oil prices ultimately
reaching a twelve-year low in December of that year. The resultant negative
effect on the Company's cash flow from the deterioration of commodity prices,
coupled with the required amortization payments on the Acquisition Facility,
severely restricted the amount of capital the Company was able to dedicate to
development drilling. Consequently, the Company's oil and natural gas production
declined which further exacerbated its liquidity problem.
During February 2000, due to the Company's default under the terms of the
Acquisition Facility, the bank demanded payment of all principle and interest.
On March 14, 2000, TDC (the "Debtor") sought protection under Chapter 11 of the
U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of
Texas, Houston Division ("Bankruptcy Court").
Under Chapter 11, certain claims against the Debtor in existence prior to
the filing of the petition are stayed while the Debtor continues business
operations as debtor-in-possession. These claims are reflected in the December
31, 2000 balance sheet as "liabilities subject to compromise." Additional claims
(liabilities subject to compromise) may arise subsequent to the bankruptcy
filing date resulting from rejection of executory contracts by the Bankruptcy
Court (or agreed to by parties in interest). Claims secured against the Debtor's
assets are also stayed, although the holders of such claims have the right to
move the court for relief from the stay.
All payments made from TDC to TOC, TPC or any related party during the
Bankruptcy were required to be approved by the Bankruptcy Court.
Reorganization Costs -- As a result of TDC filing for protection under
Chapter 11 of the U.S. Bankruptcy Code, the Company incurred certain
reorganization costs during the years ended December 31, 2000 and 2001 totaling
$21,487,191 and $8,834,468, respectively which include the following:
Rejection of fixed-price physical delivery contract -- The bankruptcy
court approved a motion to reject a fixed-price physical delivery contract.
A claim was filed by the damaged party resulting in a liability of
$17,559,272 (see Note 11). During the years ended December 31, 2000 and
2001, the Company incurred reorganization expenses related to this claim of
$17,559,272 and $737,022, respectively.
Professional fees and other -- The Company was required to hire certain
legal and accounting professionals to help the Company and its Creditors in
its bankruptcy proceedings. These fees were $3,611,760 during 2000 and
$3,781,716 during 2001.
Retention costs -- In an effort to maintain certain key employees
through the bankruptcy period, the Company incurred retention bonuses of
$855,000 and $301,740 during the years ended December 31, 2000 and 2001,
respectively. During August 2001, we paid the retention bonus to our
employees.
Interest expense - The Company paid interest expense of $2,974,270 as a
result of our emergence from bankruptcy during 2001.
Atasca transaction - As a condition of TDC's plan of reorganization, the
Company agreed to transfer all of the oil
F-12
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
and natural gas properties and certain marketable securities owned by Tribo
Petroleum Corporation, as of May 1, 2001 to its affiliate, Atasca Resources,
Inc., at their net book values of approximately $1,098,000 and $102,000,
respectively. In connection with this transaction, all balances owing to and
from the Company by its affiliates on May 1, 2001 were forgiven. These
balances aggregated to a net receivable from the affiliates of $785,000. As
a consequence of these transactions, the Company recorded a one-time
reorganization expense of approximately $1,985,442 in 2001.
Interest Income -- The Company earned interest income of $538,841 from
March 14, 2000 through December 31, 2000, and $945,722 from January 1, 2001
through June 18, 2001.
On May 23, 2001, TDC's plan of reorganization was confirmed by the
bankruptcy court. In accordance with this plan, the Company paid all
pre-petition liabilities in full. In addition, as part of the confirmation of
the plan, TDC's largest creditor agreed to a $3,300,000 reduction of their
claim in settlement of a lawsuit originally brought by the Company and its
chief executive officer. The chief executive officer assigned his interest in
the settlement to the Company in exchange for certain assets which are further
described in the "Atasca transaction" above (see Note 7)
NOTE 5 -- ALLOWANCE FOR DOUBTFUL ACCOUNTS
The activity of the allowance for doubtful accounts for the year ended
December 31, was as follows:
1999 2000 2001
----------------- ----------------- -----------------
Balance, beginning of year........................... $ 695,791 $ 867,864 $ 351,505
Additions (Recoveries)............................ 225,739 (498,436) 1,040,302
Write offs........................................ (53,666) (17,923) (14,837)
---------------- ----------------- ------------------
Balance, end of year................................. $ 867,864 $ 351,505 $ 1,376,970
================= ================= =================
NOTE 6 -- MARKETABLE SECURITIES
Securities classified as available-for-sale at December 31, were as follows:
1999 2000 2001
----------------------- ---------------------- -----------------------
Market Market Market
Value Cost Value Cost Value Cost
---------- ---------- ----------- ---------- ---------- -----------
Classified as available-for-sale:
Common stock......................... $ 172,500 $ 140,721 $ - $ - $ - $ -
Common stock warrants................ 62,500 91,547 - - - -
---------- ---------- ----------- ---------- ---------- -----------
Total classified as
available-for-sale......... $ 235,000 $ 232,268 $ - $ - $ - $ -
========== ========== =========== ========== ========== ===========
At December 31, 1999, unrealized gains and losses from available-for-sale
securities were $31,779, and $29,047, respectively. The net unrealized gains at
December 31, 1999, was $2,732, resulting in net of tax charges of $1,803,
recorded to Other Comprehensive Income. The Company held no available-for-sale
securities during 2000 and 2001.
For the year ended December 31, 1999, the Company did not sell any
available-for-sale securities. For the purposes of determining realized gains
and losses, the cost of securities sold was based on specific identification.
During 2000, the Company began to buy and sell marketable equity securities
to take advantage of favorable market conditions. Accordingly, all
available-for-sale securities were re-categorized to trading securities.
1999 2000 2001
----------------------- ---------------------- -----------------------
Market Market Market
Value Cost Value Cost Value Cost
---------- ---------- ----------- ---------- ---------- -----------
Classified as trading securities - all:
Common stock......................... $ - $ - $ 472,248 $ 308,850 $ - $ -
During 2000, gross gains and gross losses included in results of operations
that resulted from transfers of securities
F-13
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
from the available-for-sale category into the trading category were $510,670 and
$42,688, respectively. No such transfers occurred in 1999 or 2001. All of these
securities were sold in 2001.
Proceeds, realized gains, realized losses, unrealized gains and unrealized
losses related to securities classified as trading securities for the year ended
December 31, 2000 were $1,874,245, $879,458, $47,676, $230,429 and $67,031,
respectively. Realized and unrealized gains and losses on such securities are
reflected as gain (loss) on marketable securities in the accompanying statements
of operations. For the purposes of determining realized gains and losses, the
cost of securities sold was based on specific identification. The Company held
no securities classified as trading securities during 1999.
Proceeds, realized gains and realized losses related to securities
classified as trading securities for the year ended December 31, 2001 were
$555,964, $24,409 and $581,144, respectively.
NOTE 7 -- RELATED PARTY TRANSACTIONS
Balances owed by/(to) affiliated companies were comprised of the following
at December 31:
2000 2001
----------------- -----------------
Receivable:
Atasca Resources, Inc................................ $ 408,632 $ 62,016
Majority Shareholder and Chief Executive Officer..... 625,199 133,670
Other Affiliates..................................... 553,304 27,215
Payable:
Atasca Resources, Inc................................ (537,119) (15,831)
Other Affiliates..................................... (60,150) (954)
----------------- -----------------
Receivable from affiliates, net......................... $ 989,866 $ 206,116
================= =================
Atasca Resources, Inc. and the Other Affiliates referred to above are all
owned by the Company's majority shareholder and chief executive officer. Prior
to June 18, 2001, the Company's Chief Executive Officer was its sole
shareholder. With the Company's issuance of class A and B common stock on June
18, 2001 (see note 14), the Chief Executive Officer's shareholdings were
effectively reduced to 55%.
The net amounts receivable from affiliates are recorded in the accompanying
consolidated balance sheets as Receivables from Affiliates. The amounts due to
or from affiliates have no established repayment terms and no interest is
charged.
The receivables and payables with Atasca Resources, Inc. primarily relate
to: cash advances, transfers, reimbursement of corporate expenses, oil and gas
sales, production expenses, and related activities. In addition, Atasca
Resources, Inc. paid the Company a management fee of $55,000, $60,000 and
$60,000 in 1999, 2000 and 2001, respectively.
During March 2001, the Company entered into a month to month ease agreement
with a related party, Tribo Production Company, Ltd., for the lease of its
current office facilities. In June 2001, the lease was amended to a five year
commitment with terms that require the Company to pay rent of $26,000 per month
(see Note 13).
The receivable from the Company's majority shareholder and chief executive
officer principally relates to cash and travel advances and other business
expenses.
The receivables from other affiliates of the Company are primarily for cash
advances.
The Company earned revenues and incurred production expenses through Atasca
Resources, Inc. for the years ended December 31, as follows:
1999 2000 2001
----------------- ----------------- -----------------
Oil sales............................................... $ 321,747 $ 473,072 $ 96,961
Natural gas sales....................................... 131,736 112,620 58,529
Production expenses..................................... 381,995 237,807 104,739
As a condition of TDC's plan of reorganization, the Company agreed to
transfer all of the oil and natural gas properties and certain marketable
securities owned by Tribo Petroleum Corporation, as of May 1, 2001 to its
affiliate,
F-14
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Atasca Resources, Inc., at their net book values of approximately
$1,098,000 and $102,000, respectively. Revenues from the oil and natural gas
properties totaled $895,644 and $1,777,649 for the years ended December 31, 1999
and 2000 and $778,606 for the period from January 1 through May 1, 2001. In
connection with this transaction, all balances owing to and from the Company by
its affiliates on May 1, 2001 were forgiven. These balances aggregated to a net
receivable from the affiliates of $785,000. As a consequence of these
transactions, the Company recorded a one-time reorganization expense of
approximately $1,985,000 in 2001.
NOTE 8 -- OIL AND NATURAL GAS PROPERTIES
The following table sets forth information concerning the Company's oil and
natural gas properties at December 31:
2000 2001
----------------- -----------------
Cost of oil and natural gas properties, all
evaluated................................................................ $ 126,178,261 $ 136,452,676
Accumulation of depreciation, depletion and
amortization............................................................. (39,045,538) (50,927,920)
----------------- -----------------
$ 87,132,723 $ 85,524,756
================= =================
At December 31, 2001, all of the Company's oil and gas properties were
evaluated and, accordingly, were included in the amortization base.
NOTE 9 -- NOTE PAYABLE
The note payable balance at December 31, 2000 of $104,323,500, resulted from
a $105,000,000 acquisition facility with a bank dated October 15, 1997. Interest
accrued at prime plus 4%, payable at 90 day intervals. At December 31, 2000, the
note payable balance was included in pre-petition liabilities subject to
compromise in the accompanying consolidated balance sheet.
The acquisition facility was collateralized by deeds of trust, mortgages,
assignments of oil and natural gas production, security agreements and financing
statements on substantially all of the real and personal property of the
Company. Additional collateral includes the assignment of the common stock of
the Company and the personal guarantee of the Company's stockholder.
In February 2000, due to the Company's violations of the terms of the
acquisition facility, the bank demanded payment of the note and all accrued
interest. On March 14, 2000 TDC filed for protection under Chapter 11 of the
United States Bankruptcy Code (see Note 4).
On June 18, 2001, following the Company's emergence from bankruptcy, the
Company paid the bank a total of $123,613,399 representing payment in full of
all principal, interest and other charges associated with the note.
NOTE 10 - SENIOR SECURED NOTES AND UNIT OFFERING
On June 18, 2001, the Company completed a unit offering of (1) $130 Million
of 12.5% senior secured notes due 2006 ("Notes") and (2) 130,000 shares of class
A common stock of New TDC. Each unit consisted of a Note in the principal amount
of $1,000 and one share of class A common stock. The Notes are guaranteed by TOC
(see Note 17).
Notes
The Notes mature on June 1, 2006 and require amortization payments of the
greater of $20 million and 15.3% as of June 1, 2002 and 2003 and an amortization
payment of the greater of $15 million and 11.5% of the aggregate principal
balance of the notes as of June 1, 2004. A final amortization payment of
$75,000,000 is due June 1, 2006. Interest is payable semi-annually on
June 1 and December 1 of each year.
The Notes were issued at a 5.5% discount from their face amount resulting in
an aggregate discount of $7,150,000 that is being amortized as additional
interest expense over the term of the Notes. The 5.5% discount, together with
the value of the class A common stock issued in the offering which was also
accounted for as bond discount, the allocated value of the class B common stock,
and other offering costs aggregating a total of $44,993,000 (see below), make
the effective interest rate on the Notes 21.9%.
At any time prior to June 1, 2003, New TDC may redeem in the aggregate up to
30% of the then outstanding
F-15
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
aggregate principal amount of the Notes with the Net Cash Proceeds of one or
more equity offerings at a redemption price of 112.5% of the Notes, together
with accrued and unpaid interest to the redemption date.
Commencing with the quarter ended June 30, 2004, and continuing each quarter
thereafter, the Company is required to offer to apply fifty percent of its cash
flow in excess of $1,000,000 for the quarter to the pro rata redemption of the
notes.
The notes are senior secured obligations, secured by a first priority lien
on substantially all of the Company's oil and gas assets, and are
unconditionally guaranteed by the Company's only subsidiary, TOC, whereby the
guarantee is secured by a first priority lien on substantially all of the oil
and gas assets of TOC. Under the terms of an Intercreditor Agreement, the liens
are held by a collateral agent for the benefit of hedge counter parties and the
holders of the notes. Proceeds from the sale of collateral upon default are to
be applied to the satisfaction of amounts owing to hedge counter parties under
approved hedge agreements before being applied to interest and principal owing
upon the notes.
The indenture contains certain covenants, including covenants that limit the
Company's ability to incur additional debt, to sell or transfer its assets and
covenants that require the board of directors to consist of no fewer than three
individuals, at least 60% of which are required to be independent. Additionally,
the Company is required to hedge its oil and natural gas production so as to
maintain a hedged revenue to interest expense ratio of at least three to one.
The Company is not permitted to hedge more than 80% of its projected proved
developed producing volumes of oil and natural gas, except under price floor
contracts or options, and the Company is not required to enter into hedges when
certain benchmark prices are less than $2.75 per MMBtu or $18.50 per Bbl.
Class A Common Stock
The Company issued 130,000 shares of class A common stock with an estimated
fair value of $17.6 million. This amount was allocated to the value of the class
A common stock from the total proceeds received by the Company in the unit
offering, thereby creating an additional bond discount which is being amortized
to interest expense over the life of the bonds using the effective interest
method.
Class B Common Stock
In conjunction with the offering, the Company issued 65,000 shares of class
B common stock to the initial purchaser of the Notes. These shares had a fair
value of $11,000,000 and this value was considered to be offering costs of the
Company's unit offering. Accordingly, $9,427,000 was allocated to the debt
component of the unit offering, and $1,573,000 was allocated to the equity
component of the unit offering. The portion of the offering costs associated
with the issuance of the Notes is being amortized as additional interest expense
over the term of the Notes. The class B common stock has special voting rights
and the ability to control the board of directors of New TDC, subject to certain
limitations (See Note 14).
In addition, the Company incurred other offering costs of $12,621,000. Of
these costs $10,816,000 was allocated to the debt component of the unit
offering, and $1,805,000 was allocated to the equity component of the unit
offering. The portion of the offering costs associated with the issuance of the
Notes is being amortized as additional interest expense over the term of the
Notes.
NOTE 11 -- DERIVATIVE TRANSACTIONS
The Company may use derivative instruments to manage exposures to commodity
prices. The Company's objectives for holding derivatives are to minimize the
risks using the most effective methods to eliminate or reduce the impacts of
this exposure.
In April 1999, the Company entered into a thirty-two month fixed-price
physical delivery contract with Aquila Energy Marketing Corporation ("Aquila")
that obligated the Company to deliver specified volumes of natural gas to Aquila
at a certain price. For the years 1999, 2000 and 2001, the Company agreed to
deliver approximately 1,525,000 Mbtu, 3,098,000 Mbtu and 2,894,000 Mbtu,
respectively, with prices ranging from $2.353/Mcf to $2.697/Mcf.
With the authorization of the bankruptcy court, the Company rejected this
fixed-price physical delivery contract effective December 20, 2000. Aquila filed
a claim against the Company for damages relating to the cancellation of the
contract for $17,559,272. Subsequent to December 31, 2000, additional
information became available to the Company, resulting in an increase of our
original estimate by $737,022 in 2001. The claim was paid in 2001.
F-16
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
In June 2001 the Company entered into three commodity swap derivative
contracts as a condition of the issuance of the Notes described in Note 10.
Under the terms of the Notes, the Company must use these contracts to mitigate
the volatility of the commodity prices to ensure that the Company has sufficient
cash flows to service the Notes. These commodity swap derivative contracts are
designated as cash flow hedges. The contracts do not qualify for hedge
accounting under FAS No. 133; therefore, the Company recorded these contracts at
their estimated fair values, and included the changes in their fair value in the
statement of operations.
As of December 31, 2001 the Company had three outstanding commodity price
swap agreements. The following table sets forth the volumes and hedge prices of
the contracts:
Contract 1 Contract 2 Contract 3
---------------------- --------------------- ---------------------
Crude Oil Natural Gas Natural Gas
---------------------- --------------------- ---------------------
Volume Hedge Volume Hedge Volume Hedge
Date Per Day Price Per Day Price Per Day Price
- ---- --------- ---------- --------- --------- --------- ---------
January 1 - June 30, 2002............. 2.3 Mbbl $25.30/bbl 11.0 MMcf $3.96/mcf 4.3 MMcf $4.62/mcf
July 1 - December 31, 2002............ 2.3 Mbbl 25.30/bbl 11.0 MMcf 3.96/mcf 4.4 MMcf 4.36/mcf
January 1 - June 30, 2003............. 1.9 Mbbl 25.30/bbl 7.7 MMcf 3.96/mcf 3.3 MMcf 4.36/mcf
July 1 - December 31, 2003............ 1.9 Mbbl 21.51/bbl 7.7 MMcf 3.35/mcf 3.3 MMcf 3.61/mcf
The contracts stipulate that the Company will receive or make payments based
upon the differential between the hedge prices and the market prices, as defined
in the contracts, for the notional quantities. The estimated fair value of these
contracts at December 31, 2001 of $12,498,944 is included in the accompanying
balance sheet as a current asset of $9,525,317 and as a non-current asset of
$2,973,627. The unrealized gain of $12,498,944 is included in the accompanying
statement of operations as "Gain on Derivative Contracts".
The Company is exposed to credit risk in the event of nonperformance by the
counterparty in the commodity price swap contracts; however, the Company does
not anticipate nonperformance by the counterparty.
Subsequent to year end, the Company terminated certain of its derivative
contracts (see Note 15).
NOTE 12 -- INCOME TAXES
Deferred income taxes result from differences between the bases of assets
and liabilities as measured for income tax and financial reporting purposes. The
significant components of deferred tax assets and liabilities as of December 31,
were as follows:
2000 2001
----------------- -----------------
Deferred Tax Assets:
Net operating loss carryforwards...................... $ 16,273,000 $ 22,160,000
Contract loss accrual................................. 5,661,000 -
Statutory depletion carryforwards..................... - 814,000
Accrued expenses...................................... 632,000 -
Other................................................. 41,000 595,000
----------------- -----------------
Total.......................................... 22,607,000 23,569,000
----------------- -----------------
Deferred Tax Liabilities:
Oil and natural gas properties and other
equipment........................................... (6,402,000) (8,644,000)
Derivatives contract.................................. - (4,250,000)
----------------- -----------------
Total.......................................... (6,402,000) (12,894,000)
----------------- -----------------
Valuation Allowance...................................... (16,205,000) (10,675,000)
----------------- -----------------
Net deferred tax asset................................... $ - $ -
================= =================
The Company recorded a valuation allowance at December 31, 2000 and 2001
equal to the excess of deferred tax assets over deferred tax liabilities, as
management is unable to determine that these tax benefits are more likely than
not to be realized.
F-17
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following reconciles statutory federal income tax with the provision for
income tax for the years ended December 31:
1999 2000 2001
----------------- ----------------- -----------------
Income tax expense (benefit) at statutory rate.......... $ (3,111,000) $ (1,940,000) $ 5,608,000
Alternative minimum tax................................. - 79,000 -
Non-deductible expenses................................. 71,200 2,000 32,000
Increase (decrease) in valuation allowance.............. 3,039,800 1,938,000 (5,640,000)
----------------- ----------------- -----------------
Provision for income taxes.............................. $ - $ 79,000 $ -
================= ================= =================
At December 31, 2001, the Company had net operating loss carryforwards for
income tax reporting purposes of approximately $65,000,000, which will expire
during the years 2007 through 2020. The Internal Revenue Code significantly
limits the amount of acquired net operating loss carryforwards that are
available to offset future taxable income when a change of ownership occurs. As
of December 31, 2001, the Company has approximately $5,100,000 of its net
operating losses that are subject to such limitations, of which, the Company can
utilize $658,000 per year.
As of December 31, 2001, the Company's net operating losses expire as
follows:
Year Amount
---- ----------------------
2007.................................. $ 1,661,522
2008.................................. 264,780
2009.................................. 1,726,300
2010.................................. 1,455,967
2012.................................. 2,117,494
2018.................................. 18,136,659
2019.................................. 19,710,242
2020.................................. 20,104,143
-----------------------
$ 65,177,107
=======================
NOTE 13 -- COMMITMENTS AND CONTINGENCIES
Lease commitments
The Company has non-cancelable operating leases covering certain compression
equipment and facilities. The following is a schedule of future minimum lease
payments as of December 31, 2001:
Years Ending December 31, Amount
------------------------- ----------------------
2002................................. $ 2,264,257
2003................................. 2,212,840
2004................................. 1,101,900
2005................................. 312,000
2006................................. 78,000
-----------------------
$ 5,968,997
=======================
Rent expense incurred under operating leases amounted to $2,753,700,
$3,390,383 and $3,539,339 for the years ended December 31, 1999, 2000 and 2001,
respectively.
Lawsuits
The Company is the defendant in several lawsuits filed by companies for
breach of contract with claims and joint interest disputes. Accordingly, the
Company has accrued $6,200,663 associated with these lawsuits, which is included
in the accompanying balance sheet as of December 31, 2001.
The Company is a defendant in various lawsuits arising from normal business
activities. Management has reviewed pending litigation with legal counsel and
believes that these actions are without merit or that the ultimate liability, if
any, resulting from them will not materially affect the Company's financial
position.
Regulatory and environmental contingencies
During 2000, the Company reached a settlement with the MMS resolving a civil
enforcement action related to non-environmental infractions of platform
construction brought against the Company in August 2000 by the MMS. The
F-18
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Company agreed to pay civil penalties of $506,600 with $25,325 to be paid out
initially, and the remaining $481,175 to be paid out in quarterly installments
over a two-year period. The settlement between the MMS and the Company was not
an admission of liability by the Company with respect to the violations alleged
by the MMS.
The Company, as an owner and operator of oil and natural gas properties, is
subject to various federal, state and local laws and regulations relating to
discharge of materials into, and protection of, the environment. These laws and
regulations may, among other things, impose liability on the lessee under an oil
and natural gas lease for the cost of pollution clean-up resulting from
operations and subject the lessee to liability for pollution damages. The
Company maintains insurance coverage, which it believes, is customary in the
industry, although it is not fully insured against all environmental risks.
The Company is not aware of any environmental claims existing as of December
31, 2001, which would have a material impact on its financial position or
results of operations. There can be no assurance however, that current
regulatory requirements will not change, or past non-compliance with
environmental laws will not be discovered on the Company's properties.
Other
As of December 31, 2000, the Company expects the future cost of restoration,
dismantlement and abandonment of certain offshore wells and the decommissioning
of offshore platforms to be approximately $12,238,000. In connection therewith,
the Company has provided bonds with a face value of $9,850,000 pledged to the
MMS for a portion of such estimated costs. Additionally, we have provided
various other forms of pledged collateral to other regulatory agencies in
satisfaction of their requirements. At December 31, 2000 and 2001, these pledges
and bonds had a carrying value of $4,674,645 and $5,225,832, respectively.
NOTE 14 -- CAPITAL STOCK
On June 13, 2001, the Company increased its authorized share capital to
445,000 shares of class A common stock and 65,000 shares of class B common
stock. The Company also effected a 238.333:1 stock split of its class A common
stock. The consolidated financial statements give retroactive effect to the
stock split for all periods presented. In connection with the stock split, the
par value of the class A common stock decreased from $1.00 to $0.01 per share.
The par value of the class B common stock is $0.01. The class B common stock is
convertible into class A common stock upon the occurrence of certain events, as
defined.
The holders of the Class A and Class B common stock are entitled to one vote
for each share on all matters voted upon by shareholders, including the election
of directors. Such holders are not entitled to vote cumulatively for the
election of directors. Holders of a majority of the shares of common stock
entitled to vote in any election of directors may elect all of the directors
standing for election, subject to the rights of holders of class B common stock
described below.
The holders of the class A and class B common stock are together entitled to
participate pro rata in such dividends as may be declared at the discretion of
the board of directors out of funds legally available therefore. Holders of the
class A and class B common stock together are entitled to share ratably in the
net assets of the Company upon liquidation after payment or provision for all
liabilities and any preferential rights. Holders of common stock have no
preemptive rights to purchase shares of stock of the Company. Shares of common
stock are not subject to any redemption provisions and are not convertible into
any other securities of the Company, except that each share of class B common
stock is convertible into one share of class A common stock under certain
circumstances.
Special Rights of Class B Common Stock
In addition to the rights of the holders of common stock set forth above,
the holders of a majority of the class B common stock, voting together as a
single class, are entitled to designate one person to serve as a non-voting
advisory observer to the Company's board of directors, and further, at any time,
to cause the Company to increase the size of its board of directors and to
immediately elect to the board of directors a number of directors (having full
voting power) nominated by a majority of the holders of the class B common stock
sufficient to constitute a majority of the board of directors. Until there are
no outstanding shares of class B common stock, the board of directors may not
consist of more than seven directors other than those nominated by the holders
of the class B common stock in accordance with the foregoing. Only the holders
of the class B common stock may remove the directors that such holders are
entitled to designate.
In addition to any vote required by law, all matters submitted to a vote of
the Company's shareholders will require the
F-19
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
approval of the holders of a majority of the issued and outstanding shares of
class B common stock, voting separately as a single class. In addition, any
amendment to the Company's Bylaws will require the approval of the holders of
the majority of the issued and outstanding shares of class B common stock.
NOTE 15 -- SUBSEQUENT EVENTS
In March 2002, the Company terminated certain of its derivatives contracts
and replaced them with contracts providing for price floors at the prices
specified under the terms of the senior secured notes of $2.75 per MMBtu of
natural gas and $18.50 per barrel of crude oil. Proceeds from the settlement of
these contracts were approximately $3 million. The purchase price of the floor
contracts of approximately $1 million has been financed by the Company's
derivatives contracts counterparty.
NOTE 16 -- SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION
Information with respect to the Company's oil and natural gas producing
activities is presented in the following tables. Estimates of reserve
quantities, as well as future production and discounted cash flows before income
taxes, were determined by an independent petroleum engineering firm, as of
December 31, 1999, 2000 and 2001.
Oil and Natural Gas Related Costs
The following table sets forth information concerning costs related to the
Company's oil and gas property acquisition, exploration and development
activities in the United States during the years ended December 31,1999, 2000
and 2001:
1999 2000 2001
----------------- ----------------- -----------------
Property acquisition - proved........................... $ 249,971 $ 408,231 $ -
Less - proceeds from sales of properties................ (2,262,300) (389,971) (2,225,529)
Less - transfer of properties to affiliate.............. - - (1,097,611)
Development costs....................................... 13,322,473 10,080,396 13,597,525
Exploration costs....................................... - 389,030 -
----------------- ----------------- -----------------
$ 11,310,144 $ 10,487,686 $ 10,274,385
================= ================= =================
Results of Operations from Oil and Natural Gas Producing Activities
The following table sets forth the Company's results of operations from oil
and natural gas producing activities for the years ended December 31:
1999 2000 2001
----------------- ----------------- -----------------
Revenues................................................ $ 36,270,343 $ 73,452,054 $ 80,516,275
Production costs and taxes.............................. (18,657,542) (28,102,775) (27,604,490)
Depreciation, depletion and amortization................ (10,526,878) (12,995,403) (11,882,382)
----------------- ----------------- -----------------
Income (loss) from oil and natural gas
producing properties................................. $ 7,085,923 $ 32,353,876 $ 41,029,403
================= ================= =================
Depletion rate per thousand cubic feet (Mcf) of
natural gas equivalent............................... $ 0.76 $ 0.80 $ 0.77
================= ================= =================
In the presentation above, no deduction has been made for indirect costs
such as corporate overhead or interest expense. No income taxes are reflected
above due to the Company's tax loss carryforwards.
Oil and Natural Gas Reserves (Unaudited)
The following table sets forth the Company's net proved oil and natural gas
reserves at December 31, 1999, 2000 and 2001 and the changes in net proved oil
and natural gas reserves for the years then ended. Proved reserves represent the
estimated quantities of crude oil and natural gas which geological and
engineering data demonstrate with reasonable certainty to be recoverable in the
future years from known reservoirs under existing economic and operating
conditions. The reserve information indicated below requires substantial
judgment on the part of the reserve engineers, resulting in estimates, which are
not subject to precise determination. Accordingly, it is expected that the
estimates of reserves will change as future production and development
information becomes available and that revisions in these estimates could be
significant. Reserves are measured in barrels (Bbls) in the case of oil, and
units of one thousand cubic feet (Mcf) in the case of natural gas.
Oil (Bbls) Gas (Mcf)
----------------- -----------------
(Amounts in thousands)
Proved reserves:
Balance, December 31, 1998.............................................. 11,319 111,149
Discoveries and extensions........................................... 609 21,774
Revisions of previous estimates...................................... 5,132 (9,515)
Sale of reserves in place............................................ (64) (6,309)
Production........................................................... (1,145) (7,007)
----------------- -----------------
F-20
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Oil (Bbls) Gas (Mcf)
----------------- -----------------
(Amounts in thousands)
Balance, December 31, 1999.............................................. 15,851 110,092
Discoveries and extensions........................................... 644 13,176
Revisions of previous estimates...................................... 208 (13,258)
Expiration of leases................................................. (244) (11,542)
Sales of reserves in place........................................... (53) (455)
Production........................................................... (1,333) (8,314)
----------------- -----------------
Balance, December 31, 2000.............................................. 15,073 89,699
Discoveries and extensions........................................... 431 25,977
Revisions of previous estimates...................................... 147 1,175
Expiration of leases................................................. (2) (160)
Sales of reserves in place........................................... (164) (1,616)
Transfers to affiliate............................................... (125) (241)
Production........................................................... (1,245) (7,869)
----------------- -----------------
Balance, December 31, 2001.............................................. 14,115 106,965
================= =================
Proved developed reserves at December 31, 1999.............................. 12,957 58,265
================= =================
Proved developed reserves at December 31, 2000.............................. 12,290 45,575
================= =================
Proved developed reserves at December 31, 2001.............................. 11,306 45,767
================= =================
Of the Company's total proved reserves as of December 31, 1999, 2000 and
2001, approximately 48%, 57% and 51%, respectively, were classified as proved
developed producing, 15%, 18% and 9%, respectively, were classified as proved
developed non-producing and 34%, 34% and 41%, respectively, were classified as
proved undeveloped. All of the Company's reserves are located in the continental
United States.
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
The standardized measure of discounted future net cash flows from the
Company's proved oil and natural gas reserves is presented in the following
table:
December 31,
----------------------------------------------------------
1999 2000 2001
----------------- ----------------- -----------------
(Amounts in thousands)
Future cash inflows..................................... $ 733,163 $ 1,316,621 $ 533,137
Future production costs and taxes....................... (208,427) (275,236) (205,640)
Future development costs................................ (56,621) (57,384) (62,969)
Future income tax expense............................... (102,553) (249,779) (38,378)
----------------- ----------------- -----------------
Net future cash flows................................... 365,562 734,222 226,150
Discount at 10% for timing of cash flows................ (133,998) (261,943) (97,919)
----------------- ----------------- -----------------
Discounted future net cash flows from proved
reserves............................................. $ 231,564 $ 472,279 $ 128,231
================= ================= =================
The following table sets forth the changes in the standardized measure of
discounted future net cash flows from proved reserves during 1999, 2000 and
2001:
December 31,
----------------------------------------------------------
1999 2000 2001
----------------- ----------------- -----------------
(Amounts in thousands)
Balance, beginning of year.............................. $ 105,403 $ 231,564 $ 472,279
Sales, net of production costs and taxes................ (17,613) (45,349) (52,912)
Discoveries and extensions.............................. 41,619 139,327 23,811
Purchases and sales of reserves in place................ (4,647) (738) (10,557)
Changes in prices and production costs.................. 101,748 294,404 (504,032)
Revisions of quantity estimates......................... 49,998 (59,897) 1,813
F-21
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
December 31,
----------------------------------------------------------
1999 2000 2001
----------------- ----------------- -----------------
(Amounts in thousands)
Expiration of leases.................................... - (21,380) (875)
Transfer of properties to affiliate..................... - - (2,213)
Net changes in development costs........................ (7,582) 4,156 (1,561)
Interest factor - accretion of discount................. 11,206 25,959 63,000
Net change in income taxes.............................. (48,183) (96,791) 142,148
Changes in production rates and other................... (385) 1,024 (2,670)
----------------- ----------------- -----------------
Balance, end of year.................................... $ 231,564 $ 472,279 $ 128,231
================= ================= =================
Estimated future net cash flows represent an estimate of future net revenues
from the production of proved reserves using current sales prices, along with
estimates of the operating costs, production taxes and future development and
abandonment costs (less salvage value) necessary to produce such reserves. The
average prices used at December 31, 1999, 2000 and 2001, were $25.57, $25.90 and
$18.53 per Bbl and $2.96, $10.31 and $2.54 per Mcf, respectively. No deduction
has been made for depreciation, depletion or any indirect costs such as general
corporate overhead or interest expense.
Operating costs and production taxes are estimated based on current costs
with respect to producing oil and natural gas properties. Future development
costs are based on the best estimate of such costs assuming current economic and
operating conditions.
Income tax expense is computed based on applying the appropriate statutory
tax rate to the excess of future cash inflows less future production and
development costs over the current tax basis of the properties involved, less
applicable carryforwards, for both regular and alternative minimum tax.
The future net revenue information assumes no escalation of costs or prices,
except for oil and natural gas sales made under terms of contracts, which
include fixed and determinable escalation. Future costs and prices could
significantly vary from current amounts and, accordingly, revisions in the
future could be significant.
F-22
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NOTE 17 - CONSOLIDATING INFORMATION
CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2000
TRI-UNION TRI-UNION
DEVELOPMENT OPERATING ELIMINATIONS CONSOLIDATED
----------- --------- ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents.................................... $ 33,102,629 $ (112,690) $ - $ 32,989,939
Accounts receivable, net..................................... 24,299,191 716,622 (468,815) 24,546,998
Marketable securities........................................ 472,248 - - 472,248
Prepaid and other............................................ 1,411,798 100,376 - 1,512,174
------------- -------------- -------------- --------------
Total current assets................................... 59,285,866 704,308 (468,815) 59,521,359
------------- -------------- -------------- --------------
Oil and natural gas properties, net............................. 86,746,107 386,616 - 87,132,723
Other assets:
Restricted cash and bonds.................................... 4,674,645 - - 4,674,645
Furniture, fixtures and equipment, net....................... 144,789 30,732 - 175,521
Receivables from affiliates, net............................. (975,644) 1,965,510 - 989,866
Investment in subsidiary..................................... 3,030,900 - (3,030,900) -
Deferred loan costs, net..................................... 99,700 - - 99,700
------------- -------------- -------------- --------------
Total other assets..................................... 6,974,390 1,996,242 (3,030,900) 5,939,732
------------- -------------- -------------- --------------
$ 153,006,363 $ 3,087,166 $ (3,499,715) $ 152,593,814
============= ============== ============== ==============
LIABILITIES AND STOCKHOLDER'S EQUITY (CAPITAL DEFICIT)
Liabilities not subject to compromise:
Current liabilities:
Accounts payable and accrued liabilities................... $ 27,021,833 $ 56,266 $ (468,815) $ 26,609,284
Accrued interest........................................... 7,224,477 - - 7,224,477
Notes payable.............................................. 333,880 - - 333,880
------------- -------------- -------------- --------------
34,580,190 56,266 (468,815) 34,167,641
------------- -------------- -------------- --------------
Pre-petition liabilities subject to compromise:
Note payable - in default.................................... 104,323,500 - - 104,323,500
Accrued interest............................................. 6,226,808 - - 6,226,808
Accounts payable and accrued liabilities - unsecured......... 38,015,232 - - 38,015,232
------------- -------------- -------------- --------------
Total pre-petition liabilities subject to compromise... 148,565,540 - - 148,565,540
------------- -------------- -------------- --------------
183,145,730 56,266 (468,815) 182,733,181
------------- -------------- -------------- --------------
Commitments and Contingencies Stockholder's equity (capital deficit):
Class A common stock......................................... 2,383 1,000 (1,000) 2,383
Retained earnings (deficit).................................. (30,141,750) 3,029,900 (3,029,900) (30,141,750)
------------- -------------- -------------- --------------
Total stockholder's equity (capital deficit)........... (30,139,367) 3,030,900 (3,030,900) (30,139,367)
------------- -------------- -------------- --------------
$ 153,006,363 $ 3,087,166 $ (3,499,715) $ 152,593,814
============= ============== ============== ==============
F-23
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
CONSOLIDATING BALANCE SHEET
DECEMBER 31, 2001
TRI-UNION TRI-UNION
DEVELOPMENT OPERATING ELIMINATIONS CONSOLIDATED
----------- ---------- ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents.................................... $ 4,600,110 $ 164,435 $ - $ 4,764,545
Restricted cash.............................................. 8,929,566 - - 8,929,566
Accounts receivable, net..................................... 13,884,727 126,069 (150,632) 13,860,164
Prepaid and other............................................ 1,959,822 282 - 1,960,104
Derivative contracts......................................... 9,525,317 - - 9,525,317
------------- -------------- -------------- --------------
Total current assets................................... 38,899,542 290,786 (150,632) 39,039,696
------------- -------------- -------------- --------------
Oil and natural gas properties, net............................. 85,385,954 138,802 - 85,524,756
Other assets:
Restricted cash and bonds.................................... 5,200,832 25,000 - 5,225,832
Furniture, fixtures and equipment, net....................... 953,767 193,844 - 1,147,611
Receivables from affiliates, net............................. (4,153,020) 4,237,990 121,146 206,116
Investment in subsidiary..................................... 4,839,667 - (4,839,667) -
Deferred loan costs, net..................................... 17,034,817 - - 17,034,817
Derivative contracts......................................... 2,973,627 - - 2,973,627
------------- -------------- -------------- --------------
Total other assets..................................... 26,849,690 4,456,834 (4,718,521) 26,588,003
------------- -------------- -------------- --------------
$ 151,135,186 $ 4,886,422 $ (4,869,153) $ 151,152,455
============= ============== ============== ==============
LIABILITIES AND STOCKHOLDER'S EQUITY (CAPITAL DEFICIT)
Liabilities not subject to compromise:
Current liabilities:
Accounts payable and accrued liabilities................... $ 22,886,885 $ 46,755 $ (29,486) $ 22,904,154
Accounts payable subject to renegotiation.................. 5,133,667 - - 5,133,667
Accrued interest........................................... 1,399,306 - - 1,399,306
Notes payable.............................................. 965,875 - - 965,875
Current maturities of long-term debt....................... 20,000,000 - - 20,000,000
------------- -------------- -------------- --------------
50,385,733 46,755 (29,486) 50,403,002
------------- -------------- -------------- --------------
Senior secured notes....................................... 89,172,434 - - 89,172,434
------------- -------------- -------------- --------------
139,558,167 46,755 (29,486) 139,575,436
------------- -------------- -------------- --------------
Commitments and Contingencies Stockholder's equity (capital deficit):
Class A common stock......................................... 3,683 1,000 (1,000) 3,683
Class B common stock......................................... 650 - - 650
Additional paid in capital................................... 25,220,285 - - 25,220,285
Retained earnings (deficit).................................. (13,647,599) 4,838,667 (4,838,667) (13,647,599)
------------- -------------- -------------- --------------
Total stockholder's equity (capital deficit)........... 11,577,019 4,839,667 (4,839,667) 11,577,019
------------- -------------- -------------- --------------
$ 151,135,186 $ 4,886,422 $ (4,869,153) $ 151,152,455
============= ============== ============== ==============
F-24
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1999
TRI-UNION TRI-UNION
DEVELOPMENT OPERATING ELIMINATIONS CONSOLIDATED
-------------- -------------- -------------- ------------
Revenues and other:
Oil and natural gas revenues................................. $ 36,270,343 $ 619,323 $ (619,323) $ 36,270,343
Other........................................................ 1,495,393 230,145 (230,145) 1,495,393
------------- -------------- -------------- --------------
Total revenues and other............................... 37,765,736 849,468 (849,468) 37,765,736
------------- -------------- -------------- --------------
Expenses:
Lease operating expense...................................... 18,054,255 256,829 (2,768,807) 15,542,277
Workover expense............................................. 2,405,001 5,409 - 2,410,410
Production taxes............................................. 703,784 1,071 - 704,855
Depreciation, depletion and amortization..................... 11,040,035 - - 11,040,035
General and administrative................................... 3,314,299 3,095 1,919,339 5,236,733
Interest expense............................................. 11,981,460 - - 11,981,460
------------- -------------- -------------- --------------
Total expenses......................................... 47,498,834 266,404 (849,468) 46,915,770
------------- -------------- -------------- --------------
Income (loss) before income taxes............................... (9,733,098) 583,064 - (9,150,034)
Provision for income taxes...................................... (200,000) 200,000 - -
------------- -------------- -------------- --------------
Income (loss) from operations before equity in net income
of subsidiaries.............................................. (9,533,098) 383,064 - (9,150,034)
Equity in net income of subsidiaries........................... 383,064 - (383,064) -
------------- -------------- -------------- --------------
Net income (loss)............................................... $ (9,150,034) $ 383,064 $ (383,064) $ (9,150,034)
============ ============= ============= ==============
F-25
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2000
TRI-UNION TRI-UNION
DEVELOPMENT OPERATING ELIMINATIONS CONSOLIDATED
-------------- -------------- ------------ ------------
Revenues and other:
Oil and natural gas revenues................................. $ 71,388,500 $ 2,063,554 $ - $ 73,452,054
Gain on marketable securities................................ 995,180 - 995,180
Other........................................................ 125,591 (33,429) (63,758) 28,404
------------- -------------- -------------- --------------
Total revenues and other............................... 72,509,271 2,030,125 (63,758) 74,475,638
------------- -------------- -------------- --------------
Expenses:
Lease operating expense...................................... 20,919,593 279,267 (1,713,501) 19,485,359
Workover expense............................................. 6,640,123 8,951 - 6,649,074
Production taxes............................................. 1,967,460 882 - 1,968,342
Depreciation, depletion and amortization..................... 13,246,074 260,403 - 13,506,477
General and administrative................................... 2,433,521 245,094 1,649,743 4,328,358
Interest expense............................................. 12,757,863 - - 12,757,863
------------- -------------- -------------- --------------
Total expenses......................................... 57,964,634 794,597 (63,758) 58,695,473
------------- -------------- -------------- --------------
Income before reorganization costs income taxes................. 14,544,637 1,235,528 - 15,780,165
Reorganization costs............................................ 21,487,191 - - 21,487,191
------------- -------------- -------------- --------------
Income (loss) before income taxes............................... (6,942,554) 1,235,528 - (5,707,026)
Provision for income taxes...................................... 79,000 - - 79,000
------------- -------------- -------------- --------------
Income (loss) from operations before equity in net income
of subsidiaries.............................................. (7,021,554) 1,235,528 - (5,786,026)
Equity in net income of subsidiaries............................ 1,235,528 - (1,235,528) -
------------- -------------- -------------- --------------
Net income (loss)............................................... $ (5,786,026) $ 1,235,528 $ (1,235,528) $ (5,786,026)
============ ============= ============= ==============
F-26
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2001
TRI-UNION TRI-UNION
DEVELOPMENT OPERATING ELIMINATIONS CONSOLIDATED
-------------- -------------- ------------- ------------
Revenues and other:
Oil and natural gas revenues................................. $ 77,845,271 $ 2,671,004 $ - $ 80,516,275
Loss on marketable securities................................ (556,735) - - (556,735)
Gain on derivative contract.................................. 12,498,944 - - 12,498,944
Other........................................................ 838,675 86,451 (144,159) 780,967
------------- -------------- -------------- --------------
Total revenues and other............................... 90,626,155 2,757,455 (144,159) 93,238,451
------------- -------------- -------------- --------------
Expenses:
Lease operating expense...................................... 21,427,118 261,348 (1,740,494) 19,947,972
Workover expense............................................. 5,900,236 16,120 - 5,916,356
Production taxes............................................. 1,739,737 425 - 1,740,162
Depreciation, depletion and amortization..................... 11,851,138 337,703 - 12,188,841
General and administrative................................... 5,043,117 333,092 1,596,335 6,972,544
Interest expense............................................. 21,144,957 - - 21,144,957
------------- -------------- -------------- --------------
Total expenses......................................... 67,106,303 948,688 (144,159) 67,910,832
------------- -------------- -------------- --------------
Income before reorganization costs income taxes................. 23,519,852 1,808,767 - 25,328,619
Reorganization costs............................................ 8,834,468 - - 8,834,468
------------- -------------- -------------- --------------
Income (loss) before income taxes............................... 14,685,384 1,808,767 - 16,494,151
Provision for income taxes...................................... - - - -
------------- -------------- -------------- --------------
Income from operations before equity in net income
of subsidiaries.............................................. 14,685,384 1,808,767 - 16,494,151
Equity in net income of subsidiaries............................ 1,808,767 - (1,808,767) -
------------- -------------- -------------- --------------
Net income...................................................... $ 16,494,151 $ 1,808,767 $ (1,808,767) $ 16,494,151
============ ============= ============= ==============
F-27
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1999
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
TRI-UNION TRI-UNION
DEVELOPMENT OPERATING ELIMINATIONS CONSOLIDATED
----------- ----------- ------------ ------------
Cash flows from operating activities:
Net income (loss)............................................ $ (9,150,034) $ 383,064 $ (383,064) $ (9,150,034)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Equity in undistributed income (loss) of subsidiaries.... (383,064) - 383,064 -
Depletion, depreciation and amortization................. 11,040,035 - - 11,040,035
Accretion of bond interest income........................ (219,478) - - (219,478)
Changes in assets and liabilities:
Accounts receivable................................... (3,055,940) (29,373) - (3,085,313)
Prepaid expenses...................................... (239,304) - - (239,304)
Receivable from affiliates............................ (547,636) (204,918) - (752,554)
Accounts payable and accrued liabilities.............. 14,533,594 50 - 14,533,644
------------- -------------- -------------- --------------
Net cash provided by operating activities....................... 11,978,173 148,823 - 12,126,996
Cash flows from investing activities:
Purchase of marketable securities............................ (232,268) - - (232,268)
Additions to oil and natural gas properties.................. (13,574,973) 2,529 - (13,572,444)
Purchase of furniture, fixtures and equipment................ (45,017) 4,832 - (40,185)
Proceeds from disposal of equipment.......................... - 4,059 - 4,059
Proceeds from sales of oil and natural gas properties........ 2,262,300 - - 2,262,300
Purchase of restricted cash and bonds........................ (3,664,957) - - (3,664,957)
Proceeds from restricted marketable securities............... 3,300,000 - - 3,300,000
------------- -------------- -------------- --------------
Net cash provided by (used in) investing activities............. (11,954,915) 11,420 - (11,943,495)
Cash flows from financing activities:
Payments of long-term debt................................... (300,000) - - (300,000)
Payments of loan fees........................................ (20,927) - - (20,927)
Increase in notes payable.................................... 278,613 - - 278,613
------------- -------------- -------------- --------------
Net cash used in financing activities........................... (42,314) - - (42,314)
------------- -------------- -------------- -------------
Net increase (decrease) in cash and cash equivalents............ (19,056) 160,243 - 141,187
Cash and cash equivalents - beginning of year................... 2,430,899 241,910 - 2,672,809
------------- -------------- -------------- --------------
Cash and cash equivalents - end of year......................... $ 2,411,843 $ 402,153 $ - $ 2,813,996
============= ============== ============== ==============
F-28
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2000
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
TRI-UNION TRI-UNION
DEVELOPMENT OPERATING ELIMINATIONS CONSOLIDATED
-------------- -------------- -------------- -------------
Cash flows from operating activities:
Net income (loss)............................................ $ (5,786,026) $ 1,235,528 $ (1,235,528) $ (5,786,026)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Equity in undistributed income (loss) of subsidiaries.... (1,235,528) - 1,235,528 -
Depletion, depreciation and amortization................. 13,246,074 260,403 - 13,506,477
Gain on sale of marketable securities.................... (995,179) - - (995,179)
Accretion of bond interest income........................ (138,040) - - (138,040)
Reorganization items..................................... 21,487,191 - - 21,487,191
Changes in assets and liabilities
Accounts receivable................................... (15,411,221) (236,683) 258,546 (15,389,358)
Prepaid expenses...................................... (219,923) (365,965) - (585,888)
Receivable from affiliates............................ 1,030,793 (827,722) - 203,071
Accounts payable and accrued liabilities.............. 12,548,899 56,216 (258,546) 12,346,569
Pre-petition liabilities subject to compromise........ 18,043,910 - - 18,043,910
------------- -------------- -------------- --------------
Net cash provided by operating activities before
Reorganization items......................................... 42,570,950 121,777 - 42,692,727
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid.................... (2,536,788) - - (2,536,788)
Interest earned during bankruptcy............................ 538,841 - - 538,841
------------- -------------- -------------- --------------
Net cash used in reorganization items........................ (1,997,947) - - (1,997,947)
------------- -------------- -------------- --------------
Net cash provided by operating activities.................... 40,573,003 121,777 - 40,694,780
Cash flows from investing activities:
Purchase of marketable securities............................ (1,118,069) - - (1,118,069)
Proceeds from sales of marketable securities................. 1,874,245 - - 1,874,245
Additions to oil and natural gas properties.................. (10,241,037) (636,620) - (10,877,657)
Purchase of furniture, fixtures and equipment................ (31,280) - - (31,280)
Proceeds from sales of oil and natural gas properties........ 389,971 - - 389,971
Purchase of restricted cash and bonds........................ (355,000) - - (355,000)
-------------- -------------- -------------- --------------
Net cash used in investing activities........................ (9,481,170) (636,620) - (10,117,790)
Cash flows from financing activities:
Payments of long-term debt................................... (376,500) - - (376,500)
Decrease in notes payable.................................... (24,547) - - (24,547)
------------- -------------- -------------- --------------
Net cash used in financing activities............. (401,047) - - (401,047)
------------- -------------- -------------- --------------
Net increase (decrease) in cash and cash equivalents............ 30,690,786 (514,843) - 30,175,943
Cash and cash equivalents - beginning of year................... 2,411,843 402,153 - 2,813,996
------------- -------------- -------------- --------------
Cash and cash equivalents - end of year......................... $ 33,102,629 $ (112,690) $ - $ 32,989,939
============= ============== ============== ==============
F-29
TRI-UNION DEVELOPMENT CORPORATION
(FORMERLY TRIBO PETROLEUM CORPORATION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2001
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
TRI-UNION TRI-UNION
DEVELOPMENT OPERATING ELIMINATIONS CONSOLIDATED
-------------- -------------- ------------- --------------
Cash flows from operating activities:
Net income................................................... $ 16,494,151 $ 1,808,767 $ (1,808,767) $ 16,494,151
Adjustments to reconcile net income to net cash
provided by operating activities:
Equity in undistributed income (loss) of subsidiaries.... (1,808,767) - 1,808,767 -
Depletion, depreciation and amortization................. 11,851,138 337,703 - 12,188,841
Amortization of bond discount............................ 3,922,434 - - 3,922,434
Amortization of deferred loan costs...................... 3,208,151 - - 3,208,151
Loss on sale of marketable securities.................... 556,735 - - 556,735
Accretion of bond interest income........................ (123,471) - - (123,471)
Gain on sale of equipment................................ (4,961) - - (4,961)
Reorganization items..................................... 8,834,468 - - 8,834,468
Gain on derivative contracts............................. (12,498,944) - - (12,498,944)
Changes in assets and liabilities:
Restricted cash....................................... (8,904,566) (25,000) - (8,929,566)
Accounts receivable................................... 10,361,868 324,966 - 10,686,834
Prepaid expenses...................................... (813,613) 365,683 - (447,930)
Receivable from affiliates............................ 2,270,853 (2,272,480) - (1,627)
Accounts payable and accrued liabilities.............. (11,153,577) (9,512) - (11,163,089)
Accounts payable subject to negotiation............... 5,133,667 - - 5,133,667
Pre-petition liabilities subject to compromise........ (44,242,040) - - (44,242,040)
------------- -------------- -------------- -------------
Net cash provided by (used in) operating activities before
Reorganization items......................................... (16,916,474) 530,127 - (16,386,347)
Operating cash flows from reorganization items:
Bankruptcy related professional fees paid.................... (6,161,956) - - (6,161,956)
Interest earned during bankruptcy............................ 945,722 - - 945,722
------------- -------------- -------------- --------------
Net cash used in reorganization items........................ (5,216,234) - - (5,216,234)
------------- -------------- -------------- --------------
Net cash provided by (used in) operating activities...... (22,132,708) 530,127 - (21,602,581)
Cash flows from investing activities:
Purchase of marketable securities............................ (742,910) - - (742,910)
Proceeds from sales of marketable securities................. 555,964 - - 555,964
Additions to oil and natural gas properties.................. (13,538,773) (58,752) - (13,597,525)
Purchase of furniture, fixtures and equipment................ (998,172) (194,250) - (1,192,422)
Proceeds from disposal of equipment.......................... 18,503 - - 18,503
Proceeds from sales of oil and natural gas properties........ 2,225,529 - - 2,225,529
Purchase of restricted cash and bonds........................ (427,717) - - (427,717)
------------- -------------- -------------- -------------
Net cash used in investing activities.................... (12,907,576) (253,002) - (13,160,578)
Cash flows from financing activities:
Proceeds from unit offering.................................. 113,444,294 - - 113,444,294
Payments of long-term debt................................... (104,323,500) - - (104,323,500)
Payment of loan fees......................................... (3,215,024) - - (3,215,024)
Decrease in notes payable.................................... 631,995 - - 631,995
------------- -------------- -------------- --------------
Net cash provided by financing activities......... 6,537,765 - - 6,537,765
------------- -------------- -------------- --------------
Net increase (decrease) in cash and cash equivalents............ (28,502,519) 277,125 - (28,225,394)
Cash and cash equivalents - beginning of year................... 33,102,629 (112,690) - 32,989,939
------------- -------------- -------------- --------------
Cash and cash equivalents - end of year......................... $ 4,600,110 $ 164,435 $ - $ 4,764,545
============= ============== ============== ==============
F-30
NOTE 18 - QUARTERLY CONSOLIDATED FINANCIAL INFORMATION (UNAUDITED)
The following is a summary of the unaudited quarterly results of the Company's
operations for the years ended December 31, 2000 and 2001 (in thousands, except
per share data):
1st 2nd 3rd 4th Full
Year Ended 2000: Quarter Quarter Quarter Quarter Year
- --------------- -------------- -------------- -------------- -------------- --------------
Revenues.................................. $ 13,013 $ 14,496 $ 22,392 $ 24,575 $ 74,476
Expenses.................................. 12,612 11,175 16,748 18,160 58,695
Net income (loss)......................... (2) 2,809 4,734 (13,327) (5,786)
Net income (loss) per common
share - basic and assuming
dilution............................... $ (0.01) $ 11.79 $ 19.86 $ (55.92) $ (24.28)
1st 2nd 3rd 4th Full
Year Ended 2001: Quarter Quarter Quarter (a) Quarter Year
- --------------- -------------- -------------- -------------- -------------- --------------
Revenues.................................. $ 32,139 $ 26,594 $ 21,549 $ 12,957 $ 93,239
Expenses.................................. 16,335 15,515 17,847 18,214 67,911
Net income (loss)......................... 14,781 4,400 2,454 (5,140) 16,494
Net income (loss) per common
share - basic and assuming
dilution............................... $ 62.02 $ 17.44 $ 5.66 $ (11.86) $ 48.01
(a) Net income for the quarter ended September 30, 2001 has been reduced by
$737,022 as a result of a change in our original estimate of the loss associated
with the rejection of a fixed-price physical delivery contract during our
bankruptcy proceeding. Additional information became available to us subsequent
to the filing of our report on Form 10Q at September 30, 2001. Net income per
common share was reduced by $1.70 per share as a result of this change in
estimate.
F-31
EXHIBIT INDEX
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
2.1 Debtor's First Amended Plan of Reorganization approved on May 23, 2001
by the United States Bankruptcy Court for the Southern District of
Texas, Houston Division (1)
2.2 Agreement and Plan of Merger between Tribo Petroleum Corporation and
Tri-Union Development Corporation, dated July 27, 2001 (1)
3.1 Restated Articles of Incorporation for Tri-Union Development
Corporation, as amended through July 2001. (1)
3.2 By-laws of Tri-Union Development Corporation as amended and restated
through June 18, 2001. (1)
3.3 Certificate of Incorporation for Tri-Union Operating Company dated as
of November 1, 1974, as amended through May 30, 1996 (1)
3.4 By-laws of Tri-Union Operating Company as amended and restated through
June 18, 2001. (1)
4.1 Indenture Agreement by and between Tri-Union Development Corporation,
as Issuer, Tribo Petroleum Corporation, as Parent Guarantor, and
Firstar Bank, National Association, as Trustee, dated June 18, 2001.
(1)
4.2 Purchase Agreement between Tribo Petroleum Corporation, Tri-Union
Development Corporation, Tri-Union Operating Company and Jefferies &
Company, Inc., dated June 18, 2001. (1)
4.3 Registration Rights Agreement by and among Tri-Union Development
Corporation, Tri-Union Operating Company, Tribo Petroleum Corporation
and Jefferies & Company, Inc., dated June 18, 2001. (1)
4.4 Equity Registration Rights Agreement by and between Tribo Petroleum
Corporation and Jefferies & Company, Inc., dated June 18, 2001. (1)
4.5 Intercreditor and Collateral Agency Agreement among Tri-Union
Development Corporation, Tribo Petroleum Corporation, Tri-Union
Operating Company and Wells Fargo Bank Minnesota, National Association,
as Collateral Agent, and Firstar Bank, National Association, as
Trustee, dated June 18, 2001. (1)
4.6 Pledge and Collateral Account Agreement among Wells Fargo Bank
Minnesota, National Association, as Collateral Agent, Tribo Petroleum
Corporation, Tri-Union Development Corporation and Tri-Union Operating
Company, as Obligors, dated June 18, 2001. (1)
4.7 Mortgage, Deed of Trust, assignment of Production, Security Agreement
and Financing Statement of Tri-Union Development Corporation, dated
June 18, 2001. (1)
10.1 Amended and Restated Lease Agreement between Tribo Production Company,
Ltd. and Tri-Union Development Corporation, dated June 18, 2001. (1)
10.2 ISDA Master Agreement by and between Bank of America, N.A. and
Tri-Union Development Corporation, dated June 18, 2001. (1)
16.1 Letter of Hidalgo, Banfill, Zlotnik & Kermali, P.C. (1)
21.1 Subsidiaries of Registrant. (1)
23.1* Consent of BDO Seidman, LLP.
23.2* Consent of Hidlago, Banfill, Zlotnik & Kermali, P.C.
23.3* Consent of DeGolyer and MacNaughton., Inc.
23.4* Consent of Huddleston & Co., Inc.
</Table>
* Filed herewith
(1) Incorporation by reference to the comparably numbered Exhibit to the
Registration Statement on Form S-4 filed by the Issuer November 2, 2001.