AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 15, 2004
REGISTRATION NO. 333-111475
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--------------------------------------------------------------------------------
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
AMENDMENT NO. 1
TO
FORM S-2
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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CARRIZO OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
TEXAS 14701 ST. MARY'S LANE, SUITE 800 76-0415919
(State or other jurisdiction HOUSTON, TEXAS 77079 (I.R.S. Employer Identification No.)
of incorporation or organization) (281) 496-1352
(Address, including zip code, and telephone number, including
area code, of registrant's principal executive offices)
S.P. JOHNSON IV
PRESIDENT AND CHIEF EXECUTIVE OFFICER
CARRIZO OIL & GAS, INC.
14701 ST. MARY'S LANE, SUITE 800
HOUSTON, TEXAS 77079
(281) 496-1352
(Name, address, including zip code, and telephone number, including
area code, of agent for service)
---------------------
COPIES TO:
GENE J. OSHMAN JAMES M. PRINCE
BAKER BOTTS L.L.P. VINSON & ELKINS L.L.P.
3000 ONE SHELL PLAZA 1001 FANNIN
910 LOUISIANA SUITE 2300
HOUSTON, TEXAS 77002-4995 HOUSTON, TEXAS 77002
(713) 229-1234 (713) 758-2222
---------------------
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: Upon the
effective date of this registration statement.
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box. [ ]
If the registrant elects to deliver its latest annual report to security
holders, or a complete and legal facsimile thereof, pursuant to Item 11(a)(1) of
this Form, check the following box. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES
AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE
A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT
SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE
SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
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SUBJECT TO COMPLETION, DATED JANUARY 15, 2004
THE INFORMATION CONTAINED IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED.
THESE SECURITIES MAY NOT BE SOLD UNTIL THE REGISTRATION STATEMENT FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER
TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY THESE
SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.
5,700,000 SHARES
(CARRIZO OIL & GAS, INC. LOGO)
COMMON STOCK
$ PER SHARE
--------------------------------------------------------------------------------
Carrizo Oil & Gas, Inc. is offering 3,420,000 shares of common stock and the
selling shareholders identified in this prospectus are offering 2,280,000 shares
of common stock.
The common stock is listed on the Nasdaq National Market under the symbol
"CRZO." On January , 2004, the last reported sales price of the common stock
listed on the Nasdaq National Market was $ per share.
INVESTING IN THE COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING ON
PAGE 10.
PER SHARE TOTAL
--------- -----------
Price to the public......................................... $ $
Underwriting discount.......................................
Proceeds to Carrizo Oil & Gas, Inc..........................
Proceeds to the selling shareholders........................
We and our selling shareholders have granted an over-allotment option to the
underwriters. Under this option, the underwriters may elect to purchase a
maximum of 855,000 additional shares (256,500 shares from us and 598,500 shares
from the selling shareholders) within 30 days following the date of this
prospectus to cover over-allotments.
--------------------------------------------------------------------------------
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
CIBC WORLD MARKETS
FIRST ALBANY CAPITAL
HIBERNIA SOUTHCOAST CAPITAL
JOHNSON RICE & COMPANY L.L.C.
The date of this prospectus is , 2004.
[INSIDE FRONT COVER]
TABLE OF CONTENTS
PAGE
----
Prospectus Summary.......................................... 1
Risk Factors................................................ 10
Forward-Looking Statements.................................. 19
Use of Proceeds............................................. 20
Selling Shareholders........................................ 21
Capitalization.............................................. 24
Price Range of Common Stock and Dividend Policy............. 25
Selected Consolidated Financial Data........................ 26
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 28
Business and Properties..................................... 43
Management.................................................. 61
Description of Capital Stock................................ 64
Underwriting................................................ 69
Legal Matters............................................... 71
Experts..................................................... 71
Where You Can Find More Information......................... 73
Glossary of Certain Oil and Gas Terms....................... 74
Index to Financial Statements............................... F-1
Appendix A to Prospectus.................................... A-1
i
(This page intentionally left blank)
ii
PROSPECTUS SUMMARY
This summary highlights certain material information contained or incorporated
by reference in this prospectus. You should read carefully the entire prospectus
and the documents incorporated by reference in this prospectus. Unless the
context otherwise requires, all references to "Carrizo," "we," "us," and "our"
refer to Carrizo Oil & Gas, Inc. and its subsidiaries. The term "you" refers to
a prospective investor. We have included definitions of technical terms and
abbreviations important to an understanding of our business under "Glossary of
Certain Oil and Gas Terms" beginning on page 74. Unless explicitly stated
otherwise, or the context otherwise requires, all references in this prospectus
to planned capital expenditures or planned drilling activities assume the
completion of this offering.
ABOUT US
We are an independent energy company engaged in the exploration, development and
production of natural gas and oil. Our current operations are focused in proven,
producing natural gas and oil geologic trends along the onshore Gulf Coast in
Texas and Louisiana, primarily in the Miocene, Wilcox, Frio and Vicksburg
trends. Our other interests include properties in East Texas, a coalbed methane
investment in the Rocky Mountains and, recently, the Barnett Shale trend in
North Texas. Additionally, in 2003 we obtained licenses to explore in the U.K.
North Sea.
We have grown our production through our 3-D seismic-driven exploratory drilling
program. Our compound production growth rate for the period December 31, 1999
through September 30, 2003 on an annualized basis was 19%. From our inception
through September 30, 2003, we participated in the drilling of 285 wells (88.0
net) with a success rate of approximately 67% in our onshore Gulf Coast core
area. Exploratory wells accounted for 97% of the total wells we drilled. Based
on the reports of our independent reserve engineers, our total proved reserves
as of December 31, 2002 were an estimated 63.2 Bcfe with a PV-10 Value of $83.6
million. During 2002, we added 11.4 Bcfe to proved reserves and produced 7.2
Bcfe.
As a main component of our business strategy, we have acquired licenses for over
8,700 square miles of 3-D seismic data for processing and evaluation. Since
2001, we have been able to increase the size of our 3-D seismic holdings in our
onshore Gulf Coast core area by approximately 75% to over 6,650 square miles, in
large part by taking advantage of very favorable pricing available for
nonproprietary data. One of our primary strengths is the experience of our
management and technical staff in the development, processing and analysis of
this 3-D seismic data to generate and drill natural gas and oil prospects. Our
technical and operating employees have an average of over 20 years of industry
experience, in many cases with major and large independent oil and gas
companies, including Shell Oil, ARCO, Conoco, Vastar Resources, Pennzoil and
Tenneco. Using our 3-D seismic database, our highly qualified technical staff is
continually adding to and refining our substantial inventory of drilling
locations.
We believe that our utilization of large-scale 3-D seismic surveys and related
technology allows us to create and maintain a multiyear inventory of
high-quality exploration prospects. As of September 30, 2003, we had 85,678
gross acres in Texas and Louisiana under lease or lease option, almost all of
which is covered by 3-D seismic data. On this leased acreage, we have identified
over 120 potential exploratory drilling locations, including over 45 additional
extension opportunities, depending on the success of our initial drilling
activities on those locations. The vast majority of our 3-D seismic data covers
productive geological trends in our onshore Gulf Coast core area, where we have
made 192 completions as a result of our utilization and evaluation of this data.
In 2003, we expect capital expenditures to have been $25.3 million, which were
used primarily to drill 38 wells (10.1 net). In 2004, we expect capital
expenditures to be approximately $40 to $45 million (a 58 to 78% increase over
our expected 2003 capital expenditures). We expect to drill 38 wells in 2004
(18.5 net), 30 of which we plan to operate and substantially all of which we
anticipate will be exploratory wells. We anticipate that approximately 97% of
our drilling capital expenditures will be directed toward our core onshore Gulf
Coast area. We expect that the proceeds of this offering will allow us to
accelerate and enable us to retain a larger working interest in our drilling
program. Our drilling program may be revised
1
substantially over time depending on a number of factors, including the results
of our exploration efforts, the availability of sufficient capital resources for
the drilling of prospects and economic and industry conditions at the time of
drilling.
RECENT DEVELOPMENTS
Fourth Quarter 2003 Operating Results
During the fourth quarter of 2003, in our core areas in the onshore Gulf Coast
of Texas and Louisiana, we participated in the drilling of 11 gross exploratory
wells, ten of which were successful. Also during the quarter, in our Barnett
Shale Project we participated in the drilling of two gross (one net) exploratory
wells and two gross (one net) development wells, all of which were successful.
On a combined basis for these two areas, we had a 93.3% success rate for the
quarter.
Production during the fourth quarter of 2003 was estimated at 1.85 Bcfe,
bringing our 2003 annual production to an estimated record level of 7.5 Bcfe, an
increase of 3.5% over our 2002 production level. Approximately 72% of our
production during the fourth quarter of 2003 and 64% of our production in the
full year 2003 was natural gas. We estimate that fourth quarter 2003 sales
prices, including the effect of hedging activities, averaged approximately $4.78
per Mcf and $29.61 per barrel. Based on our preliminary reserve estimates, we
believe that in 2003 we more than replaced our production with proved reserve
additions from our drilling activities.
Potential Barnett Shale Acquisition
We have entered into negotiations with a private company to purchase working
interests and acreage in certain oil and gas wells located in Denton County,
Texas in the Newark East Field in the Barnett Shale trend in proximity to our
existing operations. This potential acquisition, with an expected purchase price
of $7.2 million, includes non-operated working interests ranging from 12.5% to
45% over 3,800 acres. As of January 1, 2004, the 14 producing wells (5.0 net)
that would be included in the acquisition were producing a net 1.4 MMcf/d with
another five wells (1.3 net) waiting for pipeline hook-up. We expect the
undeveloped acreage to contribute additional drilling locations, 13 of which
will target proved undeveloped reserves and 18 of which will be exploratory.
We expect that we would finance the acquisition with our current revolving
credit facility or, alternatively, with a new project financing facility that we
would seek to obtain. We currently have targeted a closing date of February 16,
2004 for the acquisition. There can be no assurance that the transaction
described above will be completed on the terms or timing described above or at
all. Regardless of whether this transaction is completed, we intend to continue
to pursue growth opportunities in this geologic trend.
BUSINESS STRATEGY
Growth Through the Drillbit
Our objective is to create shareholder value through the execution of a business
strategy designed to capitalize on our strengths. Key elements of our business
strategy include:
- grow primarily through drilling;\
- focus on prolific and industry-proven trends;
- aggressively evaluate 3-D seismic data and acquire acreage to maintain a
large drillsite inventory;
- maintain a balanced exploration drilling portfolio;
- manage risk exposure by market testing prospects and optimizing working
interests; and
- retain and incentivize a highly qualified technical staff.
Through the execution of this business strategy, we have achieved the following
results from January 1, 2000 through December 31, 2003:
- we drilled 117 wells in our onshore Gulf Coast area, 107 of which were
classified as exploratory wells, with a 77% success rate; and
2
- our annual production grew from 4.3 Bcfe in 1999 to 7.5 Bcfe in 2003, a
compound annual growth rate of approximately 15%.
In addition, we have achieved the following results over the three years ended
December 31, 2002:
- our average annual reserve replacement percentage was 222% and;
- our proved reserves grew from 40.6 Bcfe at December 31, 1999 to 63.2 Bcfe
at December 31, 2002, a compound annual growth rate of 16%.
AREAS OF OPERATIONS
Our operations are focused primarily in the onshore Gulf Coast extending from
South Louisiana to South Texas. Our other areas of interest are in East Texas,
the Barnett Shale trend, the Rocky Mountains and the U.K. North Sea. The table
below highlights our main areas of activity:
THREE MONTHS ENDED
SEPTEMBER 30, 2003 AT SEPTEMBER 30, 2003
----------------------- ----------------------------------------- DRILLING CAPITAL
EXPENDITURES
AVERAGE PRODUCTIVE 3-D --------------------
DAILY NET WELLS SEISMIC
PRODUCTION ------------- DATA (SQ. NET OPTIONS/ ESTIMATED BUDGETED
(MMCFE/D) % NAT. GAS GROSS NET MILES) LEASED ACRES 2003 2004
---------- ---------- ----- ---- --------- ------------ --------- --------
(in millions)
Wilcox............... 1.6 94% 28 8.2 1,793 18,741 $ 5.8 $ 4.9
Frio/Vicksburg....... 8.4 58% 137 43.3 2,102 8,615 5.5 12.4
Southeast Texas...... 8.8 78% 11 3.8 900 3,729 3.8 9.9
South Louisiana...... 2.4 58% 7 1.3 1,864 2,028 3.6 10.5
Other................ 0.4 - - - 2,078 240,978 1.1 1.6
---- -- --- ---- ----- ------- ----- -----
Total.............. 21.6 68% 183 56.6 8,737 274,091 $19.8 $39.3
==== == === ==== ===== ======= ===== =====
Onshore Gulf Coast
We divide our onshore Gulf Coast core region into four main producing areas:
Wilcox, Frio/Vicksburg, Southeast Texas and South Louisiana. Our onshore Gulf
Coast core area generally contains geologically complex natural gas objectives
well-suited for drilling using 3-D seismic evaluation. From our inception
through December 31, 2003, we have acquired licenses for over 6,650 square miles
of 3-D seismic data and have drilled 285 wells with a success rate of 67% in
this area. We believe that our high level of success is based primarily on our
exploration approach and our staff's extensive experience in this area.
In our onshore Gulf Coast area, we have identified over 120 exploratory drilling
opportunities on acreage we have under lease or have an option to lease,
including over 45 additional extension opportunities, depending on the success
of our initial drilling activities on those locations. Currently, we plan to
drill 36 wells (16.6 net) in the onshore Gulf Coast area in 2004.
- Wilcox Trend of Texas. We have acquired licenses for approximately 1,800
square miles of 3-D seismic data that covers potential Wilcox formation
exploration and development targets. From January 1, 2000 through December
31, 2003, we drilled 40 wells (13.3 net) with a success rate of 80% in this
area. We have identified over 30 potential exploratory drilling locations,
with over 22 additional potential extension locations depending on the
success of our initial drilling activities, on our leased acreage. As of
December 31, 2003, we had an average working interest on producing wells of
32.5% and operated 24 wells in this area.
- Frio/Vicksburg Trends of Texas. We have acquired licenses for approximately
2,100 miles of 3-D seismic data over the Frio, Vicksburg and Yegua sands.
From January 1, 2000 through December 31, 2003, we drilled 45 wells (11.6
net) with a success rate of 84% in this area. We have identified over 23
potential exploratory drilling locations, with over 12 additional potential
extension
3
locations depending on the success of our initial drilling activities, on
our leased acreage. As of December 31, 2003, we had an average working
interest on producing wells of 27.5% and operated 15 wells in this area.
- Southeast Texas. We have acquired licenses for approximately 900 square
miles of 3-D seismic data, including approximately 425 square miles of
newly released data delivered in 2003, over our Southeast Texas project
areas which are focused primarily on 3-D seismic anomalies in the Frio,
Yegua, Cook Mountain and Vicksburg formations. From January 1, 2000 through
December 31, 2003, we drilled 17 wells (4.8 net) with a success rate of 71%
in this area. We have identified over 15 potential exploratory drilling
locations, with 10 additional potential extension locations depending on
the success of our initial drilling activities, on our leased acreage. As
of December 31, 2003, we had an average working interest on producing wells
of 34.7% and we operated 13 wells in this area.
- South Louisiana. We have acquired licenses for approximately 1,850 square
miles of 3-D seismic data, including approximately 630 square miles of
newly released data delivered in 2003, that covers potential Upper Miocene
geologic interval exploration and development targets. From January 1, 2000
through December 31, 2003, we drilled 14 wells (2.4 net) with a success
rate of 50% in this area. We have identified eight potential exploratory
drilling locations, with three additional potential extension locations
depending on the success of our initial drilling activities, on our leased
acreage. As of September 30, 2003, we had an average working interest on
producing wells of 24.2% and operated four wells in this area.
Other Areas of Interest
Our other areas of interest are contained in:
- East Texas, where we have our Camp Hill heavy oil project and our Tortuga
Grande Cotton Valley prospect;
- the Barnett Shale trend in North Texas, a new area of interest in 2003 on
which we have acquired leases on over 2,100 net acres and have participated
in the drilling of four wells (1.6 net) as of October 31, 2003;
- coalbed methane interests in the Rocky Mountains, largely related to our
minority interest in Pinnacle Gas Resources, Inc., a corporate joint
venture formed with an affiliate of Credit Suisse First Boston in 2003; and
- our recently obtained offshore licenses to explore on approximately 210,000
acres in the U.K. North Sea, which we plan to promote to third parties and
for which our estimated project commitments from commencement through
mid-2005 are $0.9 million.
For 2004, we expect to spend less than $2.0 million total in these areas. We
believe that each of these areas has significant potential for us. We may, in
the future, either allocate a larger portion of our capital expenditures for
development of these interests or sell down or otherwise dispose of these
interests.
OUR EXECUTIVE OFFICES
Our executive offices are located at 14701 St. Mary's Lane, Suite 800, Houston,
Texas 77079, and our telephone number is (281) 496-1352. Information contained
on our website, www.carrizo.cc, is not part of this prospectus.
4
THE OFFERING
Common stock offered by us.............. 3,420,000 shares(a)
Common stock offered by the selling
shareholders............................ 2,280,000 shares(b)
Common stock to be outstanding after
this offering........................... 18,010,015 shares(a)(c)
Use of proceeds......................... We intend to use the proceeds from
this offering to accelerate our
drilling program and to retain
larger interests in portions of our
drilling prospects that we
otherwise would have sold down or
for which we would have sought
partners, and for general corporate
purposes. Pending such use, we
intend to use a portion of the net
proceeds to repay the outstanding
principal amount under our
revolving credit facility. See "Use
of Proceeds."
Nasdaq National Market Symbol........... CRZO
---------------------------
(a) Does not include 256,500 shares that may be sold upon exercise of the
underwriters' over-allotment option granted by us.
(b) Does not include 598,500 shares that may be sold upon exercise of the
underwriters' over-allotment option granted by the selling shareholders.
(c) Based on shares outstanding as of November 30, 2003. The number of shares
of common stock to be outstanding after this offering also does not include
6,103,434 shares of our common stock reserved for issuance upon the
exercise of options and warrants and upon the conversion of preferred stock
previously issued.
Unless otherwise stated, all information contained in this prospectus assumes no
exercise of the over-allotment option granted to the underwriters.
RISK FACTORS
You should consider carefully the "Risk Factors" beginning on page 10 of this
prospectus before making an investment in our common stock.
5
SUMMARY HISTORICAL FINANCIAL DATA
This section presents our summary historical financial data. This data should be
read in conjunction with the consolidated financial statements, related notes
and other financial information included and incorporated by reference herein.
The summary historical consolidated financial data is not intended to replace
the consolidated financial statements.
We derived the statement of operations data and statement of cash flows data for
the years ended December 31, 2000, 2001 and 2002, and balance sheet data as of
December 31, 2001 and 2002 from the audited financial statements included in
this prospectus and the balance sheet data as of December 31, 2000 from audited
consolidated financial statements that are not included in this prospectus. We
derived the statement of operations data and statement of cash flows data for
the nine months ended September 30, 2002 and 2003 and the balance sheet data as
of September 30, 2002 and 2003 from the unaudited consolidated financial
statements included in this prospectus. The unaudited consolidated financial
statements include all adjustments, consisting of normal recurring accruals,
which we consider necessary for a fair presentation of our financial position
and results of operations for these periods. The financial statements as of and
for the year ended December 31, 2002 were audited by Ernst & Young LLP,
independent auditors. The financial statements as of and for the years ended
December 31, 2000 and 2001 were audited by Arthur Andersen LLP. In 2002, we
dismissed Arthur Andersen LLP as our independent public accountants and retained
Ernst & Young LLP to act as our independent auditors.
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------ -------------------
2000 2001 2002 2002 2003
-------- -------- -------- -------- --------
(in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenues......... $ 26,834 $ 26,226 $ 26,802 $ 17,559 $ 29,615
Cost and expenses:
Oil and natural gas operating
expenses........................ 4,941 4,138 4,908 3,687 5,071
Depreciation, depletion and
amortization.................... 7,170 6,492 10,574 7,332 8,727
General and administrative......... 3,143 3,333 4,133 3,049 4,303
Stock option compensation.......... 652 (558) (84) (70) 319
-------- -------- -------- -------- --------
Total costs and expenses........ 15,906 13,405 19,531 13,998 18,420
-------- -------- -------- -------- --------
Operating income..................... 10,928 12,821 7,271 3,561 11,195
Equity loss of Pinnacle Gas
Resources.......................... - - - - (177)
Interest income (net of amounts
capitalized and interest
expense)........................... 579 269 54 44 34
Other income, net.................... 1,482 1,777 274 245 14
-------- -------- -------- -------- --------
Income before income taxes........... 12,989 14,867 7,599 3,850 11,066
Income tax expense................... 1,004 5,336 2,809 1,456 4,053
-------- -------- -------- -------- --------
Net income before cumulative effect
of change in accounting
principle.......................... 11,985 9,531 4,790 2,394 7,013
Dividends and accretion on preferred
stock.............................. - - 588 415 552
Cumulative effect of change in
accounting principle............... - - - - 128
-------- -------- -------- -------- --------
Net income available to common
shareholders....................... $ 11,985 $ 9,531 $ 4,202 $ 1,979 $ 6,333
======== ======== ======== ======== ========
6
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------ -------------------
2000 2001 2002 2002 2003
-------- -------- -------- -------- --------
(in thousands, except per share data)
Earnings per common share
Basic.............................. $ 0.85 $ 0.68 $ 0.30 $ 0.14 $ 0.45
Diluted............................ 0.74 0.57 0.26 0.12 0.38
Weighted average shares outstanding
Basic.............................. 14,028 14,059 14,158 14,152 14,225
Diluted............................ 16,256 16,731 16,148 15,928 16,574
STATEMENT OF CASH FLOWS DATA:
Net cash provided (used) by:
Operating activities............... $ 17,133 $ 23,951 $ 19,925 $ 12,339 $ 23,509
Investing activities............... (16,438) (31,224) (24,100) (16,744) (19,028)
Financing activities............... (3,823) 2,292 5,682 3,967 (4,798)
AS OF DECEMBER 31, AS OF SEPTEMBER 30,
----------------------------- -------------------
2000 2001 2002 2002 2003
------- -------- -------- -------- --------
(in thousands)
BALANCE SHEET DATA:
Working capital....................... $ 6,433 $ (582) $ (1,442) $ (4,815) $ (4,599)
Property and equipment, net........... 72,129 104,132 120,526 117,780 124,030
Total assets.......................... 93,000 117,392 135,388 131,630 147,635
Long-term debt, including current
maturities.......................... 34,556 38,188 42,012 37,415 36,421
Convertible participating preferred
stock............................... - - 6,373 6,045 6,925
Shareholders' equity.................. 52,939 63,204 66,816 64,603 74,069
7
SUMMARY RESERVE AND PRODUCTION DATA
The following table sets forth summary information concerning our estimated
proved natural gas and oil reserves at December 31, 2000, 2001 and 2002 based on
reports prepared by Ryder Scott Company and Fairchild and Wells, Inc.,
Independent Petroleum Engineers. The PV-10 Value and the Standardized Measure
attributable to our proved reserves, shown below, use prices and costs in effect
as of December 31 of the year for which such information is presented. For more
information regarding our natural gas and oil reserves, please read "Business
and Properties--Natural Gas and Oil Reserves."
AT DECEMBER 31,
-----------------------------
2000 2001 2002
------- ------- -------
ESTIMATED NET PROVED RESERVES:
Natural gas (MMcf)....................................... 10,992 17,858 12,922
Oil (MBbls).............................................. 6,397 6,857 8,381
Natural gas equivalent (MMcfe)........................ 49,377 59,000 63,208
PV-10 Value (in thousands)(1)............................ $88,830 $49,582 $83,614
Standardized Measure (in thousands)...................... $70,106 $44,577 $65,297
PRICES USED IN CALCULATING ESTIMATED VALUE OF PROVED
RESERVES:
Natural gas (per Mcf).................................... $ 10.34 $ 2.76 $ 4.70
Oil (per Bbl)............................................ 24.85 17.71 29.16
OTHER RESERVE DATA:
Average all-sources finding cost (per Mcfe)(2)........... $ 1.01 $ 1.97 $ 1.89
Average reserve replacement percentage................... 241% 279% 163%
Proved developed reserves (MMcfe)........................ 16,452 20,702 21,184
Our average all-sources finding cost for the three years ended December 31, 2002
was $1.59 per Mcfe.
The following table sets forth summary information concerning our production
results, sales prices and costs and expenses for the years ended December 31,
2000, 2001 and 2002 and for the nine-month periods ended September 30, 2002 and
2003.
NINE MONTHS ENDED
YEAR ENDED SEPTEMBER 30,
-------------------------- ------------------
2000 2001 2002 2002 2003
------ ------ ------ ------- -------
NET PRODUCTION VOLUME:
Oil (MBbls).............................. 198 160 401 261 363
Natural gas (MMcf)....................... 5,460 4,432 4,801 3,543 3,432
Natural gas equivalent (MMcfe)........ 6,651 5,390 7,207 5,109 5,607
AVERAGE PRE-HEDGE SALES PRICES:
Oil (per Bbl)............................ $28.64 $24.14 $25.63 $23.95 $31.02
Natural gas (per Mcf).................... 4.15 4.58 3.62 3.32 5.87
AVERAGE POST-HEDGE SALES PRICES:
Oil (per Bbl)............................ $27.81 $24.28 $24.94 $23.34 $29.08
Natural gas (per Mcf).................... 3.90 5.04 3.50 3.24 5.56
COSTS AND EXPENSES (PER MCFE):
Oil and natural gas operating expenses... $ 0.74 $ 0.77 $ 0.68 $ 0.72 $ 0.90
Depreciation, depletion and
amortization.......................... 1.08 1.20 1.47 1.44 1.56
General and administrative............... 0.47 0.62 0.57 0.60 0.77
---------------------------
(1) The PV-10 Values are pre-tax and were determined by using the year-end
sales prices, which averaged $24.85, $17.71 and $29.16 per Bbl of oil, and
$10.34, $2.76 and $4.70 per Mcf of natural gas in 2000, 2001 and 2002,
respectively.
(2) Our all-sources finding cost excludes the coalbed methane unproved property
costs we contributed as a minority investment to Pinnacle Gas Resources,
Inc. in June 2003 and, accordingly, is no longer included in our
consolidated operations. We believe our calculation of finding cost
provides investors with an indication of our relative exploration
efficiency. In addition, our management uses finding cost as a component of
our individual well economic analysis. The table below reconciles our
8
calculation of finding cost to our costs incurred in the purchase of proved and
unproved properties and in development and exploration activities, excluding
capitalized interest on unproved properties of $3.6 million, $3.2 million and
$3.1 million for the years ended December 31, 2000, 2001 and 2002, respectively:
YEAR ENDED DECEMBER 31,
-----------------------------------
2000 2001 2002
--------- --------- ---------
(in thousands, except finding cost)
Acquisition costs:
Unproved properties contributed to Pinnacle............... -- $ 5,239 $ 1,323
Other unproved properties................................. $ 6,641 7,368 5,079
Proved properties......................................... 337 800 660
Exploration................................................. 7,843 18,356 14,194
Development................................................. 1,361 3,065 2,351
------- ------- -------
Total costs incurred...................................... $16,182 $34,828 $23,607
======= ======= =======
Less unproved properties contributed to Pinnacle............ -- $ 5,239 $ 1,323
------- ------- -------
Adjusted costs.............................................. $16,182 $29,589 $22,284
======= ======= =======
Total proved reserves added................................. 16,040 15,018 11,761
------- ------- -------
Average all-sources finding cost (per Mcfe)................. $ 1.01 $ 1.97 $ 1.89
======= ======= =======
9
RISK FACTORS
You should consider carefully the following risk factors, in addition to the
other information set forth in this prospectus, before purchasing shares of our
common stock. Each of these risk factors could adversely affect our business,
operating results and financial condition, as well as the value of an investment
in our common stock. An investment in our common stock includes a high degree of
risk.
NATURAL GAS AND OIL DRILLING IS A SPECULATIVE ACTIVITY AND INVOLVES NUMEROUS
RISKS AND SUBSTANTIAL AND UNCERTAIN COSTS THAT COULD ADVERSELY AFFECT US.
Our success will be largely dependent upon the success of our drilling program.
Drilling for natural gas and oil involves numerous risks, including the risk
that no commercially productive natural gas or oil reservoirs will be
discovered. The cost of drilling, completing and operating wells is substantial
and uncertain, and drilling operations may be curtailed, delayed or canceled as
a result of a variety of factors beyond our control, including:
- unexpected or adverse drilling conditions;
- elevated pressure or irregularities in geologic formations;
- equipment failures or accidents;
- adverse weather conditions;
- compliance with governmental requirements; and
- shortages or delays in the availability of drilling rigs, crews and
equipment.
Because we identify the areas desirable for drilling from 3-D seismic data
covering large areas, we may not seek to acquire an option or lease rights until
after the seismic data is analyzed or until the drilling locations are also
identified; in those cases, we may not be permitted to lease, drill or produce
natural gas or oil from those locations.
Even if drilled, our completed wells may not produce reserves of natural gas or
oil that are economically viable or that meet our earlier estimates of
economically recoverable reserves. Our overall drilling success rate or our
drilling success rate for activity within a particular project area may decline.
Unsuccessful drilling activities could result in a significant decline in our
production and revenues and materially harm our operations and financial
condition by reducing our available cash and resources. Because of the risks and
uncertainties of our business, our future performance in exploration and
drilling may not be comparable to our historical performance described in this
prospectus.
WE MAY NOT ADHERE TO OUR PROPOSED DRILLING SCHEDULE.
Our final determination of whether to drill any scheduled or budgeted wells will
be dependent on a number of factors, including:
- the results of our exploration efforts and the acquisition, review and
analysis of the seismic data;
- the availability of sufficient capital resources to us and the other
participants for the drilling of the prospects;
- the approval of the prospects by the other participants after additional
data has been compiled;
- economic and industry conditions at the time of drilling, including
prevailing and anticipated prices for natural gas and oil and the
availability and prices of drilling rigs and crews; and
- the availability of leases and permits on reasonable terms for the
prospects.
Although we have identified or budgeted for numerous drilling prospects, we may
not be able to lease or drill those prospects within our expected time frame or
at all. Wells that are currently part of our capital budget may be based on
statistical results of drilling activities in other 3-D project areas that we
believe are geologically similar rather than on analysis of seismic or other
data in the prospect area, in which case actual drilling and results are likely
to vary, possibly materially, from those statistical results. In addition, our
drilling schedule may vary from our expectations because of future
uncertainties.
10
OUR RESERVE DATA AND ESTIMATED DISCOUNTED FUTURE NET CASH FLOWS ARE ESTIMATES
BASED ON ASSUMPTIONS THAT MAY BE INACCURATE AND ARE BASED ON EXISTING ECONOMIC
AND OPERATING CONDITIONS THAT MAY CHANGE IN THE FUTURE.
There are numerous uncertainties inherent in estimating natural gas and oil
reserves and their estimated value, including many factors beyond the control of
the producer. The reserve data set forth in this prospectus represents only
estimates. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner. The reserve data included or incorporated by
reference in this prospectus represents estimates that depend on a number of
factors and assumptions that may vary considerably from actual results,
including:
- historical production from the area compared with production from other
areas;
- the assumed effects of regulations by governmental agencies;
- assumptions concerning future natural gas and oil prices;
- future operating costs;
- severance and excise taxes;
- development costs; and
- workover and remedial costs.
For these reasons, estimates of the economically recoverable quantities of
natural gas and oil attributable to any particular group of properties,
classifications of those reserves based on risk of recovery and estimates of the
future net cash flows expected from them prepared by different engineers or by
the same engineers but at different times may vary substantially. Accordingly,
reserve estimates may be subject to upward or downward adjustment, and actual
production, revenue and expenditures with respect to our reserves likely will
vary, possibly materially, from estimates.
As of December 31, 2002, approximately 66% of our proved reserves were either
proved undeveloped or proved nonproducing. Moreover, some of the producing wells
included in our reserve reports as of December 31, 2002 had produced for a
relatively short period of time as of that date. Because most of our reserve
estimates are calculated using volumetric analysis, those estimates are less
reliable than estimates based on a lengthy production history. Volumetric
analysis involves estimating the volume of a reservoir based on the net feet of
pay of the structure and an estimation of the area covered by the structure
based on seismic analysis. In addition, realization or recognition of our proved
undeveloped reserves will depend on our development schedule and plans. Lack of
certainty with respect to development plans for proved undeveloped reserves
could cause the discontinuation of the classification of these reserves as
proved. We have from time to time chosen to delay development of our proved
undeveloped reserves in the Camp Hill Field in East Texas in favor of pursuing
shorter-term exploration projects with higher potential rates of return, adding
to our lease position in this field and further evaluating additional economic
enhancements for this field's development.
The discounted future net cash flows included or incorporated by reference in
this prospectus are not necessarily the same as the current market value of our
estimated natural gas and oil reserves. As required by the Securities and
Exchange Commission (the SEC), the estimated discounted future net cash flows
from proved reserves are based on prices and costs as of the date of the
estimate. Actual future net cash flows also will be affected by factors such as:
- the actual prices we receive for natural gas and oil;
- our actual operating costs in producing natural gas and oil;
- the amount and timing of actual production;
- supply and demand for natural gas and oil;
- increases or decreases in consumption of natural gas and oil; and
- changes in governmental regulations or taxation.
11
In addition, the 10% discount factor we use when calculating discounted future
net cash flows for reporting requirements in compliance with the Financial
Accounting Standards Board in Statement of Financial Accounting Standards No. 69
may not be the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with us or the natural gas and oil
industry in general.
WE DEPEND ON SUCCESSFUL EXPLORATION, DEVELOPMENT AND ACQUISITIONS TO MAINTAIN
RESERVES AND REVENUE IN THE FUTURE.
In general, the volume of production from natural gas and oil properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent we conduct successful
exploration and development activities or acquire properties containing proved
reserves, or both, our proved reserves will decline as reserves are produced.
Our future natural gas and oil production is, therefore, highly dependent on our
level of success in finding or acquiring additional reserves. The business of
exploring for, developing or acquiring reserves is capital intensive. Recovery
of our reserves, particularly undeveloped reserves, will require significant
additional capital expenditures and successful drilling operations. To the
extent cash flow from operations is reduced and external sources of capital
become limited or unavailable, our ability to make the necessary capital
investment to maintain or expand our asset base of natural gas and oil reserves
would be impaired. In addition, we are dependent on finding partners for our
exploratory activity. To the extent that others in the industry do not have the
financial resources or choose not to participate in our exploration activities,
we will be adversely affected.
NATURAL GAS AND OIL PRICES ARE HIGHLY VOLATILE, AND LOWER PRICES WILL NEGATIVELY
AFFECT OUR FINANCIAL RESULTS.
Our revenue, profitability, cash flow, future growth and ability to borrow funds
or obtain additional capital, as well as the carrying value of our properties,
are substantially dependent on prevailing prices of natural gas and oil.
Historically, the markets for natural gas and oil prices have been volatile, and
those markets are likely to continue to be volatile in the future. It is
impossible to predict future natural gas and oil price movements with certainty.
Prices for natural gas and oil are subject to wide fluctuation in response to
relatively minor changes in the supply of and demand for natural gas and oil,
market uncertainty and a variety of additional factors beyond our control. These
factors include:
- the level of consumer product demand;
- overall economic conditions;
- weather conditions;
- domestic and foreign governmental relations;
- the price and availability of alternative fuels;
- political conditions;
- the level and price of foreign imports of oil and liquefied natural gas;
and
- the ability of the members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil price controls.
Declines in natural gas and oil prices may materially adversely affect our
financial condition, liquidity and ability to finance planned capital
expenditures and results of operations.
WE FACE STRONG COMPETITION FROM OTHER NATURAL GAS AND OIL COMPANIES.
We encounter competition from other natural gas and oil companies in all areas
of our operations, including the acquisition of exploratory prospects and proven
properties. Our competitors include major integrated natural gas and oil
companies and numerous independent natural gas and oil companies, individuals
and drilling and income programs. Many of our competitors are large,
well-established companies that have been engaged in the natural gas and oil
business much longer than we have and possess substantially larger operating
staffs and greater capital resources than we do. These companies may be able to
pay more for exploratory projects and productive natural gas and oil properties
and may be able to define, evaluate, bid for and purchase a greater number of
properties and prospects than our financial or
12
human resources permit. In addition, these companies may be able to expend
greater resources on the existing and changing technologies that we believe are
and will be increasingly important to attaining success in the industry. We may
not be able to conduct our operations, evaluate and select suitable properties
and consummate transactions successfully in this highly competitive environment.
WE MAY NOT BE ABLE TO KEEP PACE WITH TECHNOLOGICAL DEVELOPMENTS IN OUR INDUSTRY.
The natural gas and oil industry is characterized by rapid and significant
technological advancements and introductions of new products and services using
new technologies. As others use or develop new technologies, we may be placed at
a competitive disadvantage, and competitive pressures may force us to implement
those new technologies at substantial cost. In addition, other natural gas and
oil companies may have greater financial, technical and personnel resources that
allow them to enjoy technological advantages and may in the future allow them to
implement new technologies before we can. We may not be able to respond to these
competitive pressures and implement new technologies on a timely basis or at an
acceptable cost. If one or more of the technologies we use now or in the future
were to become obsolete or if we are unable to use the most advanced
commercially available technology, our business, financial condition and results
of operations could be materially adversely affected.
WE ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS AND ENVIRONMENTAL RISKS.
Natural gas and oil operations are subject to various federal, state and local
government regulations that may change from time to time. Matters subject to
regulation include discharge permits for drilling operations, plug and
abandonment bonds, reports concerning operations, the spacing of wells,
unitization and pooling of properties and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on production by
restricting the rate of flow of natural gas and oil wells below actual
production capacity in order to conserve supplies of natural gas and oil. Other
federal, state and local laws and regulations relating primarily to the
protection of human health and the environment apply to the development,
production, handling, storage, transportation and disposal of natural gas and
oil, by-products thereof and other substances and materials produced or used in
connection with natural gas and oil operations. In addition, we may be liable
for environmental damages caused by previous owners of property we purchase or
lease. As a result, we may incur substantial liabilities to third parties or
governmental entities and may be required to incur substantial remediation
costs. Further, we or our affiliates hold certain mineral leases in the State of
Montana that require the issuance of new coalbed methane drilling permits, which
have been halted temporarily pending a final Record of Decision for Montana's
Environmental Impact Statement. We may not be able to obtain new permits in an
optimal time period or at all. We also are subject to changing and extensive tax
laws, the effects of which cannot be predicted. Compliance with existing, new or
modified laws and regulations could have a material adverse effect on our
business, financial condition and results of operations.
WE ARE SUBJECT TO VARIOUS OPERATING AND OTHER CASUALTY RISKS THAT COULD RESULT
IN LIABILITY EXPOSURE OR THE LOSS OF PRODUCTION AND REVENUES.
The natural gas and oil business involves operating hazards such as:
- well blowouts;
- mechanical failures;
- explosions;
- uncontrollable flows of oil, natural gas or well fluids;
- fires;
- geologic formations with abnormal pressures;
- pipeline ruptures or spills;
- releases of toxic gases; and
- other environmental hazards and risks.
13
Any of these hazards and risks can result in the loss of hydrocarbons,
environmental pollution, personal injury claims and other damage to our
properties and the property of others.
WE MAY NOT HAVE ENOUGH INSURANCE TO COVER ALL OF THE RISKS WE FACE.
In accordance with customary industry practices, we maintain insurance coverage
against some, but not all, potential losses in order to protect against the
risks we face. We do not carry business interruption insurance. We may elect not
to carry insurance if our management believes that the cost of available
insurance is excessive relative to the risks presented. In addition, we cannot
insure fully against pollution and environmental risks. The occurrence of an
event not fully covered by insurance could have a material adverse effect on our
financial condition and results of operations.
WE CANNOT CONTROL THE ACTIVITIES ON PROPERTIES WE DO NOT OPERATE AND ARE UNABLE
TO ENSURE THEIR PROPER OPERATION AND PROFITABILITY.
We do not operate all of the properties in which we have an interest. As a
result, we have limited ability to exercise influence over, and control the
risks associated with, operations of these properties. The failure of an
operator of our wells to adequately perform operations, an operator's breach of
the applicable agreements or an operator's failure to act in ways that are in
our best interests could reduce our production and revenues. The success and
timing of our drilling and development activities on properties operated by
others therefore depend upon a number of factors outside of our control,
including the operator's
- timing and amount of capital expenditures;
- expertise and financial resources;
- inclusion of other participants in drilling wells; and
- use of technology.
THE MARKETABILITY OF OUR NATURAL GAS PRODUCTION DEPENDS ON FACILITIES THAT WE
TYPICALLY DO NOT OWN OR CONTROL, WHICH COULD RESULT IN A CURTAILMENT OF
PRODUCTION AND REVENUES.
The marketability of our production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. We generally deliver natural gas through gas gathering
systems and gas pipelines that we do not own under interruptible or short-term
transportation agreements. Under the interruptible transportation agreements,
the transportation of our gas may be interrupted due to capacity constraints on
the applicable system, for maintenance or repair of the system, or for other
reasons as dictated by the particular agreements. Our ability to produce and
market natural gas on a commercial basis could be harmed by any significant
change in the cost or availability of such markets, systems or pipelines.
OUR FUTURE ACQUISITIONS MAY YIELD REVENUES OR PRODUCTION THAT VARIES
SIGNIFICANTLY FROM OUR PROJECTIONS.
In acquiring producing properties, we assess the recoverable reserves, future
natural gas and oil prices, operating costs, potential liabilities and other
factors relating to the properties. Our assessments are necessarily inexact and
their accuracy is inherently uncertain. Our review of a subject property in
connection with our acquisition assessment will not reveal all existing or
potential problems or permit us to become sufficiently familiar with the
property to assess fully its deficiencies and capabilities. We may not inspect
every well, and we may not be able to observe structural and environmental
problems even when we do inspect a well. If problems are identified, the seller
may be unwilling or unable to provide effective contractual protection against
all or part of those problems. Any acquisition of property interests may not be
economically successful, and unsuccessful acquisitions may have a material
adverse effect on our financial condition and future results of operations.
14
OUR BUSINESS MAY SUFFER IF WE LOSE KEY PERSONNEL.
We depend to a large extent on the services of certain key management personnel,
including our executive officers and other key employees, the loss of any of
whom could have a material adverse effect on our operations. We have entered
into employment agreements with each of S.P. Johnson IV, our President and Chief
Executive Officer, Paul F. Boling, our Chief Financial Officer, Jeremy T.
Greene, our Vice President of Exploration Development, Kendell A. Trahan, our
Vice President of Land, and J. Bradley Fisher, our Vice President of Operations.
We do not maintain key-man life insurance with respect to any of our employees.
Our success will be dependent on our ability to continue to employ and retain
skilled technical personnel.
WE MAY EXPERIENCE DIFFICULTY IN ACHIEVING AND MANAGING FUTURE GROWTH.
We have experienced growth in the past primarily through the expansion of our
drilling program. Future growth may place strains on our resources and cause us
to rely more on project partners and independent contractors, possibly
negatively affecting our financial condition and results of operations. Our
ability to grow will depend on a number of factors, including:
- our ability to obtain leases or options on properties for which we have 3-D
seismic data;
- our ability to acquire additional 3-D seismic data;
- our ability to identify and acquire new exploratory prospects;
- our ability to develop existing prospects;
- our ability to continue to retain and attract skilled personnel;
- our ability to maintain or enter into new relationships with project
partners and independent contractors;
- the results of our drilling program;
- hydrocarbon prices; and
- our access to capital.
We may not be successful in upgrading our technical, operations and
administrative resources or in increasing our ability to internally provide
certain of the services currently provided by outside sources, and we may not be
able to maintain or enter into new relationships with project partners and
independent contractors. Our inability to achieve or manage growth may adversely
affect our financial condition and results of operations.
WE MAY CONTINUE TO HEDGE THE PRICE RISKS ASSOCIATED WITH OUR PRODUCTION. OUR
HEDGE TRANSACTIONS MAY RESULT IN OUR MAKING CASH PAYMENTS OR PREVENT US FROM
BENEFITTING TO THE FULLEST EXTENT POSSIBLE FROM INCREASES IN PRICES FOR NATURAL
GAS AND OIL.
Because natural gas and oil prices are unstable, we periodically enter into
price-risk-management transactions such as swaps, collars, futures and options
to reduce our exposure to price declines associated with a portion of our
natural gas and oil production and thereby to achieve a more predictable cash
flow. The use of these arrangements limits our ability to benefit from increases
in the prices of natural gas and oil. Our hedging arrangements may apply to only
a portion of our production, thereby providing only partial protection against
declines in natural gas and oil prices. These arrangements may expose us to the
risk of financial loss in certain circumstances, including instances in which
production is less than expected, our customers fail to purchase contracted
quantities of natural gas and oil or a sudden, unexpected event materially
impacts natural gas or oil prices.
WE HAVE SUBSTANTIAL CAPITAL REQUIREMENTS THAT, IF NOT MET, MAY HINDER
OPERATIONS.
We have experienced and expect to continue to experience substantial capital
needs as a result of our active exploration, development and acquisition
programs. We expect that additional external financing will be required in the
future to fund our growth. We may not be able to obtain additional financing,
and
15
financing under existing or new credit facilities may not be available in the
future. Without additional capital resources, we may be forced to limit or defer
our planned natural gas and oil exploration and development program and thereby
adversely affect the recoverability and ultimate value of our natural gas and
oil properties, in turn negatively affecting our business, financial condition
and results of operations.
OUR CREDIT FACILITY CONTAINS OPERATING RESTRICTIONS AND FINANCIAL COVENANTS, AND
WE MAY HAVE DIFFICULTY OBTAINING ADDITIONAL CREDIT.
Over the past few years, increases in commodity prices and proved reserve
amounts and the resulting increase in our estimated discounted future net
revenue have allowed us to increase our available borrowing amounts. In the
future, commodity prices may decline, we may increase our borrowings or our
borrowing base may be adjusted downward, thereby reducing our borrowing
capacity. Our credit facility is secured by a pledge of substantially all of our
producing natural gas and oil properties assets, is guaranteed by our subsidiary
and contains covenants that limit additional borrowings, dividends to
nonpreferred shareholders, the incurrence of liens, investments, sales or
pledges of assets, changes in control, repurchases or redemptions for cash of
our common or preferred stock, speculative commodity transactions and other
matters. The credit facility also requires that specified financial ratios be
maintained. We may not be able to refinance our debt or obtain additional
financing, particularly in view of our current credit agreement's restrictions
on our ability to incur debt under our bank credit facility and the fact that
substantially all of our assets are currently pledged to secure obligations
under that facility. The restrictions of our credit facility and our difficulty
in obtaining additional debt financing may have adverse consequences on our
operations and financial results including:
- our ability to obtain financing for working capital, capital expenditures,
our drilling program, purchases of new technology or other purposes may be
impaired;
- the covenants in our credit facilities that limit our ability to borrow
additional funds and dispose of assets may affect our flexibility in
planning for, and reacting to, changes in business conditions;
- because our indebtedness is subject to variable interest rates, we are
vulnerable to increases in interest rates;
- any additional financing we obtain may be on unfavorable terms;
- we may be required to use a substantial portion of our cash flow to make
debt service payments, which will reduce the funds that would otherwise be
available for operations and future business opportunities;
- a substantial decrease in our operating cash flow or an increase in our
expenses could make it difficult for us to meet debt service requirements
and could require us to modify our operations, including by curtailing
portions of our drilling program, selling assets, reducing our capital
expenditures, refinancing all or a portion of our existing debt or
obtaining additional financing; and
- we may become more vulnerable to downturns in our business or the economy
generally.
We may incur additional debt in order to fund our exploration and development
activities. A higher level of indebtedness increases the risk that we may
default on our debt obligations. Our ability to meet our debt obligations and
reduce our level of indebtedness depends on future performance. General economic
conditions, natural gas and oil prices and financial, business and other
factors, many of which are beyond our control, affect our operations and our
future performance. Our senior subordinated notes contain restrictive covenants
similar to those under our credit facility.
In addition, under the terms of our credit facility, our borrowing base is
subject to redeterminations at least semiannually based in part on prevailing
natural gas and oil prices. In the event the amount outstanding exceeds the
redetermined borrowing base, we could be forced to repay a portion of our
borrowings. We may not have sufficient funds to make any required repayment. If
we do not have sufficient funds and are otherwise unable to negotiate renewals
of our borrowings or arrange new financing, we may have to sell a portion of our
assets.
16
WE MAY RECORD CEILING LIMITATION WRITE-DOWNS THAT WOULD REDUCE OUR SHAREHOLDERS'
EQUITY.
We use the full-cost method of accounting for investments in natural gas and oil
properties. Accordingly, we capitalize all the direct costs of acquiring,
exploring for and developing natural gas and oil properties. Under the full-cost
accounting rules, the net capitalized cost of natural gas and oil properties may
not exceed a "ceiling limit" that is based upon the present value of estimated
future net revenues from proved reserves, discounted at 10%, plus the lower of
the cost or the fair market value of unproved properties. If net capitalized
costs of natural gas and oil properties exceed the ceiling limit, we must charge
the amount of the excess to operations through depreciation, depletion and
amortization expense. This charge is called a "ceiling limitation write-down."
This charge does not impact cash flow from operating activities but does reduce
our shareholders' equity. The risk that we will be required to write down the
carrying value of our natural gas and oil properties increases when natural gas
and oil prices are low or volatile. In addition, write-downs would occur if we
were to experience sufficient downward adjustments to our estimated proved
reserves or the present value of estimated future net revenues, as further
discussed in "Risk Factors--Our reserve data and estimated discount future net
cash flows are estimates based upon assumptions that may be inaccurate and are
based on existing economic and operating conditions that may change in the
future." Once incurred, a write-down of natural gas and oil properties is not
reversible at a later date. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Critical Accounting Policies
and Estimates" for additional information on these matters.
OUR AFFILIATES CONTROL A MAJORITY OF OUR OUTSTANDING COMMON STOCK, WHICH MAY
AFFECT YOUR VOTE AS A SHAREHOLDER.
As of November 30, 2003, our officers and directors and their affiliates
beneficially owned approximately 84% of our outstanding common stock (68% after
this offering). As a result, these shareholders, to the extent they act as a
group, will be able to significantly influence or control the outcome of certain
matters requiring a shareholder vote, including votes concerning the election of
directors, the adoption or amendment of provisions in our certificate of
incorporation or bylaws, and the approval of mergers and other significant
corporate transactions. The existence of these levels of ownership concentrated
in a few persons makes it unlikely that any other holder of common stock will be
able to affect our management or strategic direction. These factors may also
have the effect of delaying, deterring or preventing a change in control and may
adversely affect the voting and other rights of other shareholders.
OUR SHARES THAT ARE ELIGIBLE FOR FUTURE SALE MAY HAVE AN ADVERSE EFFECT ON THE
PRICE OF OUR COMMON STOCK.
Future sales of substantial amounts of our common stock, or a perception that
such sales could occur, could adversely affect the market price of our common
stock and could impair our ability to raise capital through the sale of our
equity securities. The 5.7 million shares of common stock offered hereby will be
eligible for immediate sale in the public market without restriction. This risk
is compounded by the fact that a substantial portion of our common stock is
owned by a relatively few number of individuals or entities. The major holders
of shares of our common stock have piggyback and demand registration rights that
provide for the registration of the resale of those shares at our expense which
will allow those shares to be sold in the public market without restriction. We
and our directors and officers and certain of our affiliates have agreed not to
offer for sale, sell or otherwise dispose of any shares of our common stock or
any securities convertible or exercisable or exchangeable for shares of our
common stock, or to exercise demand or piggyback registration rights with
respect to those shares, for a period of 90 days after the date of this
prospectus, unless the representatives of the underwriters give their prior
written consent, subject to certain exceptions. The underwriters may consent at
any time and without public notice.
17
THE MARKET PRICE OF OUR COMMON STOCK IS VOLATILE.
The trading price of our common stock and the price at which we may sell common
stock in the future are subject to large fluctuations in response to any of the
following:
- limited trading volume in our common stock;
- quarterly variations in operating results;
- our involvement in litigation;
- general financial market conditions;
- the prices of natural gas and oil;
- announcements by us and our competitors;
- our liquidity;
- our ability to raise additional funds;
- changes in government regulations; and
- other events.
WE DO NOT ANTICIPATE PAYING DIVIDENDS ON OUR COMMON STOCK IN THE NEAR FUTURE.
We have not paid any dividends in the past and do not intend to pay cash
dividends on our common stock in the foreseeable future. We currently intend to
retain any earnings for the future operation and development of our business,
including exploration, development and acquisition activities. Any future
dividend payments will be restricted by the terms of our credit agreement and
our senior subordinated notes.
CERTAIN ANTI-TAKEOVER PROVISIONS MAY AFFECT YOUR RIGHTS AS A SHAREHOLDER.
Our articles of incorporation authorize our board of directors to set the terms
of and issue additional preferred stock without shareholder approval. Our board
of directors could use the preferred stock as a means to delay, defer or prevent
a takeover attempt that a shareholder might consider to be in our best interest.
In addition, our outstanding Series B preferred stock, our senior credit
facility and our senior subordinated notes contain terms that may restrict our
ability to enter into change of control transactions, including requirements to
redeem or repay the Series B preferred stock, our credit facility and our senior
subordinated notes upon a change in control. These provisions, along with
specified provisions of the Texas Business Corporation Act and our articles of
incorporation and bylaws, may discourage or impede transactions involving actual
or potential changes in our control, including transactions that otherwise could
involve payment of a premium over prevailing market prices to holders of our
common stock.
18
FORWARD-LOOKING STATEMENTS
This prospectus and the documents included or incorporated by reference in this
prospectus contain statements concerning our expectations, beliefs, plans,
objectives, goals, strategies, future events or performance and underlying
assumptions and other statements that are not historical facts. These statements
are "forward-looking statements" within the meaning of the Private Securities
Litigation Reform Act of 1995. You generally can identify our forward-looking
statements by the words "anticipate," "believe," "budgeted," "continue,"
"could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective,"
"plan," "potential," "predict," "projection," "scheduled," "should," "will" or
other similar words. These forward-looking statements include, among others,
statements regarding:
- our growth strategies;
- our ability to explore for and develop natural gas and oil resources
successfully and economically;
- anticipated trends in our business;
- our future results of operations;
- our liquidity and our ability to finance our exploration and development
activities;
- future market conditions in the oil and gas industry;
- our ability to make and integrate acquisitions;
- the impact of governmental regulation; and
- future acquisitions.
These statements may be found under "Prospectus Summary," "Risk Factors," "Use
of Proceeds," "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and "Business and Properties." More specifically, our
forward looking statements include:
- our estimates of the timing and number of wells we expect to drill and
other exploration activities included in "Business and Properties" and
elsewhere in this prospectus; and
- statements regarding our capital expenditure program included in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and elsewhere in this prospectus.
We have based our forward-looking statements on our management's beliefs and
assumptions based on information available to our management at the time the
statements are made. We caution you that assumptions, beliefs, expectations,
intentions and projections about future events may and often do vary materially
from actual results. Therefore, we cannot assure you that actual results will
not differ materially from those expressed or implied by our forward-looking
statements.
Some of the factors that could cause actual results to differ from those
expressed or implied in forward-looking statements are described under "Risk
Factors" and in other sections of this prospectus. You should not place undue
reliance on our forward-looking statements. Each forward-looking statement
speaks only as of the date of the particular statement.
19
USE OF PROCEEDS
We estimate that we will receive net proceeds of approximately $ (based on
an assumed offering price of $ , the last reported sale price of our common
stock on the Nasdaq National Market on , 2004) from the sale of
3,420,000 shares of our common stock in this offering. "Net proceeds" is what we
expect to receive after paying the underwriting discount and other expenses of
the offering. We will not receive any proceeds from the sale of shares by the
selling shareholders pursuant to this prospectus.
We intend to use the proceeds from this offering:
- to accelerate our drilling program on a selected basis as described under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources--Capital Expenditures";
- to retain larger working interests in some of our drilling prospects that
we otherwise would have sold down or for which we would have sought
partners; and
- for general corporate purposes.
Pending such use, we intend to use a portion of the net proceeds to repay the
outstanding principal amount under our revolving credit facility. As of January
8, 2003, $7.0 million principal amount, bearing interest at a weighted average
rate of 3.2%, was outstanding under our revolving credit facility with a
borrowing base determined as of October 31, 2003 of $19.0 million. We originally
borrowed this amount to fund our ongoing exploration program. See
"Forward-Looking Statements" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital
Resources--Financing Arrangements--Hibernia Credit Facility."
20
SELLING SHAREHOLDERS
The following table provides information regarding the beneficial ownership of
our common stock held by the selling shareholders as of November 30, 2003.
SHARES OF COMMON STOCK
---------------------------------------------------------------------------------------
SUBJECT TO
BENEFICIALLY BENEFICIALLY UNDERWRITERS'
OWNED PRIOR TO OWNED AFTER THE AS A PERCENT OF OVER-ALLOTMENT
NAME THE OFFERING(1) OFFERED HEREBY OFFERING TOTAL OUTSTANDING OPTION
---- --------------- -------------- --------------- ----------------- --------------
J.P. Morgan Partners (23A
SBIC), L.P.(2)............ 5,143,909 1,145,883 259,235
Mellon Ventures, L.P........ 1,609,937 360,506 81,135
Paul B. Loyd, Jr. .......... 1,355,299 274,702 61,824
Frank A. Wojtek............. 952,521 98,527 48,004
Douglas A.P. Hamilton(3).... 851,472 250,379 69,854
S.P. Johnson IV............. 841,083 75,000 75,000
DAPHAM Partnership L.P...... 395,960 -- --
The Douglas Hayes Pollock
Hamilton Trust............ 43,000 20,000 --
The Carrie Hamilton Trust... 47,824 20,000 --
The Olivia Jean Hamilton
Trust..................... 47,824 20,000 --
Berea Investors:
Paul J. Harder............ 3,906 875 197
Arthur F. DuC. Mussara.... 1,953 437 98
Victor Rice............... 19,531 4,373 984
William Ross.............. 3,907 875 197
Anthony B. Martino........ 6,024 1,349 304
Richard E. Turner, Jr. ... 3,906 560 197
NBLN Limited Partnership.. 11,718 2,624 591
Dr. Brad Cohen............ 3,906 875 197
Thomas H. O'Neill, Jr. ... 4,236 949 214
Albert Stickney........... 1,694 379 85
James Wadsworth........... 4,236 949 214
Richard J. Riley.......... 1,694 379 85
Kenneth W. Colwell........ 1,694 379 85
---------- --------- ---------
Total................ 11,218,586 2,280,000 598,500
========== ========= =========
---------------------------
(1) The table includes shares of common stock that can be acquired through the
exercise of options, warrants and convertible securities within 60 days of
November 30, 2003. Included are 155,000, 70,000, 165,000, 20,000, 20,000
and 26,666 shares that can be acquired through the exercise of options for
Mr. Johnson, Mr. Wojtek, Mr. Webster, Mr. Hamilton, Mr. Loyd and J.P.
Morgan Partners (23A SBIC), L.P. ("JPMorgan"), respectively. Also included
are 92,006, 92,006, 92,006, 2,208,151 and 276,019 shares that can be
acquired through the exercise of the warrants issued in 1999 for Mr.
Webster, Mr. Hamilton, Mr. Loyd, JPMorgan and Mellon Ventures, L.P.
("Mellon"), respectively. 84,210 and 168,422 shares that can be acquired
through the exercise of the warrants issued in 2002 are included for Mr.
Webster and Mellon, respectively, 400,930 and 801,860 shares that can be
acquired upon the conversion of the Series B preferred stock are included
for Mr. Webster and Mellon, respectively.
21
(2) JPMorgan is a Delaware limited partnership. Its general partner is J.P.
Morgan Partners (23A SBIC Manager), Inc. ("JPMP (23A SBIC Manager)"), a
wholly owned subsidiary of JP Morgan Chase Bank ("JPM Chase Bank"), a
wholly owned subsidiary of JP Morgan Chase & Co., a publicly traded company
("JPM Chase"). Each of JPMP (23A SBIC Manager), JPM Chase Bank and JPM
Chase may also be considered the beneficial owner of these shares; however,
each disclaims beneficial ownership except to the extent of its pecuniary
interest in the shares. Shares shown include 15,833, 4,166 and 7,500 shares
of common stock that can be acquired through the exercise of options within
60 days of November 30, 2003 by Mr. Behrens, Mr. Martin and Arnold Chavkin,
our former director. Mr. Behrens, Mr. Martin and Mr. Chavkin are obligated
to transfer any shares issued in connection with the exercise of the
options to JPMorgan.
(3) Shares shown do not include (i) 395,960 shares of common stock beneficially
owned by DAPHAM Partnership, L.P., the limited partner of which is a
charitable remainder trust of which Mr. Hamilton, his wife and children are
among the beneficiaries and (ii) 138,648 shares of common stock
beneficially owned by the trusts identified in the table established for
the benefit of Mr. Hamilton's children, and for each of which Mr.
Hamilton's wife serves as trustee. Mr. Hamilton disclaims beneficial
ownership of all of such shares.
Some of the selling shareholders either have or have had a material relationship
with us within the past three years. Messrs. Hamilton, Loyd, Webster, Wojtek and
Johnson have each been a member of our Board of Directors since 1993. Mr.
Webster has been the Chairman of our Board of Directors since June 1997. Mr.
Wojtek served as our Chief Financial Officer, Vice President, Secretary and
Treasurer from 1993 until August 2003. Mr. Johnson has served as our President
and Chief Executive Officer since December 1993. See "Management" for more
information about these relationships.
In February 2002, we sold 60,000 shares of our Series B preferred stock and
warrants to purchase 252,632 shares of our common stock for an aggregate
purchase price of $6.0 million. We sold $4.0 million of Series B preferred stock
and 168,422 warrants to Mellon and $2.0 million of Series B preferred stock and
84,210 warrants to Mr. Webster, the Chairman of our Board of Directors. For
information on this transaction, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and Capital
Resources--Financing Arrangements--Series B Preferred Stock."
In connection with our 2002 sales of the Series B preferred stock and related
warrants, we and the investors entered into a shareholders' agreement providing
that if the holders of at least 51% of our common stock then outstanding approve
a merger, sale of our company or sale of all or substantially of our assets,
each such investor will vote in favor of the proposed transaction, subject to
certain conditions. Under the 2002 shareholders' agreement, we granted Mellon
and Mr. Webster specified preemptive rights to purchase certain securities
issuable by us.
In December 1999, we sold $22.0 million principal amount of 9% Senior
Subordinated Notes due 2007, 3,636,364 shares of our common stock at a price of
$2.20 per share and warrants expiring in 2007 to purchase up to 2,760,189 shares
of our common stock at an exercise price of $2.20 per share to CB Capital
Investors, L.P. (now JPMorgan), Mellon and Messrs. Loyd, Hamilton and Webster.
For information on this transaction, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and Capital
Resources--Financing Arrangements--Senior Subordinated Notes and Related
Securities."
In connection with this 1999 transaction, we entered into a shareholders'
agreement with the investors and Mr. Johnson, Mr. Wojtek and DAPHAM Partnership,
L.P. (collectively, the "1999 Shareholders") which provides that so long as to
JPMorgan owns (a) at least 15% of our common stock (with percentage ownerships
being determined as specified in the agreement), the 1999 Shareholders agree to
vote their shares to cause the number of directors constituting our Board of
Directors to be seven and to cause the election of two directors to be nominated
by JPMorgan and (b) at least 7.5% of our common stock, the 1999 Shareholders
agree to vote their shares to cause the number of directors constituting our
Board of Directors to be seven and to cause the election of one director to be
nominated by JPMorgan. The 1999 Shareholders also have agreed that, if at any
time after December 15, 2004, JPMorgan then owns at least 15% of our common
stock, unless there shall have occurred certain completed or proposed sale
transactions involving us or we have a minimum public float of common stock of
not less than $40 million and a minimum average weekly trading volume of 250,000
shares, JPMorgan has the right to designate two additional members to our Board
of Directors, and the size of our Board of Directors shall be
22
increased accordingly. The 1999 Shareholders have agreed to vote their shares in
accordance with this arrangement. We were entitled to increase the size of the
Board by one additional member in fiscal 2000. If we at any other time increase
the size of the Board of Directors, the 1999 Shareholders have agreed to take
action, including the voting of their securities, to cause to be elected the
number of directors nominated by JPMorgan necessary to maintain the applicable
proportion of directors nominated by JPMorgan to the Board of Directors.
The 1999 shareholders' agreement gave JPMorgan and affiliates certain preemptive
rights similar to those in the 2002 shareholders' agreement.
In November 1999 we entered into a month-to-month agreement with San Felipe
Resources Company, an entity owned by Mr. Webster, under which he provides
consulting services to us in exchange for a fee of $9,000 per month, which was
increased to $12,000 per month effective April 2003. In December 2001 and April
2003, we granted options to purchase 75,000 and 80,000 shares of our common
stock under our incentive plan to Mr. Webster at the price of $4.01 and $4.43
per share, respectively, the fair market value of the date of each grant, for
consulting services.
In December 2001 we sold to Mr. Webster a 2% working interest in certain leases
in Matagorda County and the right to participate in the Staubach #1 well located
within those leases in exchange for $20,000 and the payment by Mr. Webster of a
33% promoted interest for the drilling costs through casing point of that well.
The terms of this sale were consistent with the terms of sales of other
participants in this project.
During the years ended December 31, 2001 and 2002 and during 2003, we
participated in the drilling of two wells, one well and no wells, respectively,
that were operated by a subsidiary of Brigham Exploration Company ("Brigham").
During the year ended December 31, 2002 and during 2003, Brigham participated in
the drilling of two wells and two wells, respectively, operated by us. Mr.
Webster is a member of the board of directors of Brigham. Mr. Webster is also a
managing director of a merchant banking affiliate of the beneficial owner of
approximately 35% of the common stock of the parent company of Brigham Oil and
Gas, L.P.
Berea Associates, LLC, Berea Oil & Gas Corp., PAC Finance (USA) Inc., William R.
Ziegler, Thomas O'Neill, Jr. and Berea Associates II LLC were participants with
us in a 2001 exploration program. We granted these individuals and entities an
exchange option whereby each participant was entitled to elect to exchange its
interest in the program for our common stock. In October 2003, we issued to
these participants who exercised their election approximately 168,000 shares of
our common stock in exchange for their interests in that program. The
individuals listed below Berea Investors in the table above are transferees of
the interests of Berea Associates, LLC and Berea Associates II LLC in the
exchange program.
In June 2003, we formed Pinnacle Gas Resources, Inc., a corporate joint venture
with an unrelated entity and CSFB Private Equity, which is an affiliate of Mr.
Webster. That transaction is described in "Business and Properties--Pinnacle
Transaction."
In the third quarter of 2003, we paid Mr. Wojtek $251,486 in severance payments
in accordance with his employment agreement.
23
CAPITALIZATION
The table below shows our capitalization:
- on September 30, 2003; and
- on September 30, 2003 on an as-adjusted basis to give effect to this
offering at a public offering price of $ per share, the last reported
sales price on , 2004, and the temporary application of the
proceeds as set forth in "Use of Proceeds."
You should read this table in conjunction with our consolidated financial
statements and related notes that are included in this prospectus.
SEPTEMBER 30, 2003
-----------------------
ACTUAL AS ADJUSTED
-------- -----------
(in thousands)
CASH........................................................ $ 4,426
========
LONG-TERM DEBT:
Revolving credit facility................................. $ 7,000
Senior subordinated notes, related parties................ 26,605
Capital lease obligations................................. 161
Nonrecourse note.......................................... 388
--------
Total long-term debt................................... 34,154
PREFERRED STOCK (10,000,000 SHARES AUTHORIZED):
Series B convertible participating preferred stock
(150,000 shares are designated as convertible
participating shares, with 68,559 convertible
participating shares issued and outstanding)........... 6,925
SHAREHOLDERS' EQUITY:
Warrants (3,262,821 outstanding).......................... 780
Common stock, par value $0.01 (40,000,000 shares
authorized with 14,385,551 issued and outstanding)..... 144
Additional paid in capital................................ 63,821
Retained earnings......................................... 9,391
Accumulated other comprehensive loss...................... (67)
--------
Total shareholders' equity............................. 74,069
--------
Total capitalization........................................ $115,148
========
24
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our common stock, par value $0.01 per share, commenced trading on the Nasdaq
National Market on August 6, 1997 under the symbol CRZO. The following table
sets forth the high and low bid prices per share of our common stock on the
Nasdaq National Market for the periods indicated. The sales information below
reflects interdealer prices, without retail mark-ups, mark-downs or commissions
and may not necessarily represent actual transactions.
HIGH LOW
------ ------
2002:
First Quarter............................................. $6.000 $4.100
Second Quarter............................................ 5.750 4.260
Third Quarter............................................. 4.700 3.600
Fourth Quarter............................................ 5.730 3.900
2003:
First Quarter............................................. 5.900 4.500
Second Quarter............................................ 6.880 4.250
Third Quarter............................................. 7.440 5.000
Fourth Quarter............................................ 7.940 6.300
2004:
First Quarter (through January 12, 2004).................. 7.550 7.380
The closing market price of our common stock on January 12, 2004 was $7.55 per
share. As of January 12, 2004, there were an estimated 66 record owners of our
common stock.
We have not paid any dividends on our common stock in the past and do not intend
to pay such dividends in the foreseeable future. We currently intend to retain
any earnings for the future operation and development of our business, including
exploration, development and acquisition activities. Our credit agreement with
Hibernia National Bank and the terms of our senior subordinated notes restrict
our ability to pay dividends. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital Resources."
25
SELECTED CONSOLIDATED FINANCIAL DATA
This section presents our selected historical financial data. This data should
be read in conjunction with the consolidated financial statements, related notes
and other financial information included and incorporated by reference herein,
as well as "Management's Discussion and Analysis of Financial Condition and
Results of Operations." The selected financial data in this section is not
intended to replace the consolidated financial statements.
We derived the statement of operations data and statement of cash flows data for
the years ended December 31, 2000, 2001 and 2002, and balance sheet data as of
December 31, 2001 and 2002 from the audited consolidated financial statements
included in this prospectus. We derived the statement of operations data and
statement of cash flows data for the years ended December 31, 1998 and 1999 and
the balance sheet data as of December 31, 1998, 1999 and 2000 from audited
consolidated financial statements that are not included in this prospectus. We
derived the statement of operations data and statement of cash flows data for
the nine months ended September 30, 2002 and 2003 and balance sheet data as of
September 30, 2002 and 2003 from the unaudited consolidated financial statements
included in this prospectus. The unaudited consolidated financial statements
include all adjustments, consisting of normal recurring accruals, which we
consider necessary for a fair presentation of our financial position and results
of operations for these periods. The financial statements as of and for the year
ended December 31, 2002 were audited by Ernst & Young LLP, independent auditors.
The financial statements as of and for the years ended December 31, 1998, 1999,
2000 and 2001 were audited by Arthur Andersen LLP. In 2002, we dismissed Arthur
Andersen LLP as our independent public accountants and retained Ernst & Young
LLP to act as our independent auditors.
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------------------------- --------------------
1998 1999 2000 2001 2002 2002 2003
-------- -------- -------- -------- -------- -------- --------
(in thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenues........... $ 7,859 $ 10,204 $ 26,834 $ 26,226 $ 26,802 $ 17,559 $ 29,615
Cost and expenses:
Oil and natural gas operating
expenses........................... 2,770 3,036 4,941 4,138 4,908 3,687 5,071
Depreciation, depletion and
amortization....................... 3,952 4,301 7,170 6,492 10,574 7,332 8,727
General and administrative........... 2,667 2,195 3,143 3,333 4,133 3,049 4,303
Writedown of oil and gas
properties......................... 20,305 -- -- -- -- -- --
Stock option compensation............ - - 652 (558) (84) (70) 319
-------- -------- -------- -------- -------- -------- --------
Total costs and expenses........... 29,694 9,532 15,906 13,405 19,531 13,998 18,420
-------- -------- -------- -------- -------- -------- --------
Operating income (loss)................ (21,835) 672 10,928 12,821 7,271 3,561 11,195
Equity loss of Pinnacle Gas Resources,
Inc.................................. - - - - - - (177)
Interest income (net of amounts
capitalized and interest expense).... 285 13 579 269 54 44 34
Other income, net...................... - - 1,482 1,777 274 245 14
-------- -------- -------- -------- -------- -------- --------
Income (loss) before income taxes...... (21,550) 685 12,989 14,867 7,599 3,850 11,066
Income tax expense (benefit)........... (2,218) (1,057) 1,004 5,336 2,809 1,456 4,053
-------- -------- -------- -------- -------- -------- --------
Net income (loss) before cumulative
effect of change in accounting
principle............................ (19,332) 1,742 11,985 9,531 4,790 2,394 7,013
Dividends and accretion on Preferred
Stock................................ - - - - 588 415 552
Cumulative effect of change in
accounting principle................. - (78) - - - - 128
-------- -------- -------- -------- -------- -------- --------
Net income (loss) available to common
shareholders(1)...................... $(19,332) $ 1,664 $ 11,985 $ 9,531 $ 4,202 $ 1,979 $ 6,333
======== ======== ======== ======== ======== ======== ========
Basic earnings (loss) per common
share(1)............................. $ (2.15) $ 2.00 $ 0.85 $ 0.68 $ 0.30 $ 0.14 $ 0.45
Diluted earnings (loss) per common
share(1)............................. (2.15) 2.00 0.74 0.57 0.26 0.12 0.38
26
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------------------------- --------------------
1998 1999 2000 2001 2002 2002 2003
-------- -------- -------- -------- -------- -------- --------
(in thousands, except per share data)
Weighted average shares outstanding:
Basic................................ 10,375 10,544 14,028 14,059 14,158 14,152 14,225
Diluted.............................. 10,375 10,546 16,256 16,731 16,148 15,928 16,574
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------------------------- --------------------
1998 1999 2000 2001 2002 2002 2003
-------- -------- -------- -------- -------- -------- --------
(in thousands)
STATEMENT OF CASH FLOWS DATA:
Net cash provided by operating
activities........................... $ 2,387 $ 2,200 $ 17,133 $ 23,951 $ 19,925 $ 12,339 $ 23,509
Net cash used in investing
activities........................... (36,790) (13,500) (16,438) (31,224) (24,100) (16,744) (19,028)
Net cash provided by (used in)
financing activities................. 32,916 21,457 (3,823) 2,292 5,682 3,967 (4,798)
AS OF DECEMBER 31, AS OF SEPTEMBER 30,
-------------------------------------------------------- --------------------
1998 1999 2000 2001 2002 2002 2003
-------- -------- -------- -------- -------- -------- --------
(in thousands)
BALANCE SHEET DATA:
Working capital........................ $ 4,483 $ 8,338 $ 6,433 $ (582) $ (1,442) $ (4,815) $ (4,599)
Property and equipment, net............ 57,878 64,337 72,129 104,132 120,526 117,780 124,030
Total assets........................... 64,988 83,666 93,000 117,392 135,388 131,630 147,635
Long-term debt, including current
maturities........................... 12,056 37,170 34,556 38,188 42,012 37,415 36,421
Mandatorily redeemable preferred
stock................................ 30,731 - - - - - -
Convertible participating preferred
stock................................ - - - - 6,373 6,045 6,925
Shareholders' equity................... 11,202 40,853 52,939 63,204 66,816 64,603 74,069
---------------------------
(1) Net income for the year ended December 31, 1999 excludes, and earnings per
share for the year ended December 31, 1999 includes, the discount on the
redemption of our preferred stock in the amount of $21.9 million.
27
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
You should read this discussion together with the consolidated financial
statements and other financial information included in this prospectus. Unless
explicitly stated otherwise, or the context otherwise requires, all references
in this section to planned capital expenditures or planned drilling activities
assume the completion of this offering.
GENERAL OVERVIEW
For the year ended December 31, 2002 and for the first nine months of 2003, we
achieved record drilling success rates, levels of production, natural gas and
oil revenues and net income available to shareholders for any twelve- and
nine-month period, respectively, in our history.
In 2002, we produced a record 7.2 Bcfe compared to 5.4 Bcfe in 2001. In the
first nine months of 2003, we produced 5.6 Bcfe, a record for any nine-month
period and an improvement over production of 5.1 Bcfe in the first nine months
of 2002. These increasing production levels in 2003 are due to our drilling
success.
In 2002, we drilled 20 wells (7.1 net) in the onshore Gulf Coast with a success
rate of 85% compared to a success rate of 80% in 2001, in which we drilled 25
wells (7.6 net). During the first nine months of 2003, we drilled 22 wells (8.2
net) with a success rate of 86%. Between January 1, 2001 and September 30, 2003,
93% of our wells drilled were exploratory and 7% were development. In 2003, we
drilled 38 wells, with 36 wells in the onshore Gulf Coast area.
In 2002, both our revenues and our net income increased: our natural gas and oil
revenues reached a record level at $26.8 million, and our net income available
to common shareholders was $4.2 million, or $0.30 and $0.26 per basic and fully
diluted share, respectively. In 2001, our natural gas and oil revenues were
$26.2 million and our net income available to common shareholders was $9.5
million, or $0.68 and $0.57 per basic and fully diluted share, respectively. In
the first nine months of 2003, our natural gas and oil revenues reached a
nine-month record level of $29.6 million, as compared to $17.6 million during
the first nine months of 2002. Our net income available to common shareholders
was $6.3 million in the 2003 nine-month period, or $0.45 and $0.38 per basic and
fully diluted share, respectively, as compared to $2.0 million, or $0.14 and
$0.12 per basic and fully diluted share, respectively, for the first nine months
of 2002. These increases in natural gas and oil revenues and net income were
attributable partly to the high levels of production discussed above and to high
commodity prices.
Our financial results are largely dependent on a number of factors, including
commodity prices. Commodity prices are outside of our control and historically
have been and are expected to remain volatile. Natural gas prices in particular
have remained volatile during the last few years. Commodity prices are affected
by changes in market demands, overall economic activity, weather, pipeline
capacity constraints, inventory storage levels, basis differentials and other
factors. As a result, we cannot accurately predict future natural gas, natural
gas liquids and crude oil prices, and therefore, cannot accurately predict
revenues. Including the effects of hedging activities, our realized natural gas
price was 31% lower and our realized oil price was 3% higher in 2002 than in
2001, and our realized natural gas price was 72% higher and our realized oil
price was 25% higher during the first nine months of 2003 than in the comparable
period in 2002.
Because natural gas and oil prices are unstable, we periodically enter into
price-risk-management transactions such as swaps, collars, futures and options
to reduce our exposure to price fluctuations associated with a portion of our
natural gas and oil production and to achieve a more predictable cash flow. The
use of these arrangements limits our ability to benefit from increases in the
prices of natural gas and oil. Our hedging arrangements may apply to only a
portion of our production and provide only partial protection against declines
in natural gas and oil prices.
28
We have continued to reinvest a substantial portion of our operating cash flows
into funding our drilling program and increasing the amount of 3-D seismic data
available to us. In 2004, we expect capital expenditures to be approximately $40
to $45 million, as compared to $25.3 million in 2003. In the first nine months
of 2003, we incurred $20.4 million in capital and exploration expenditures, as
compared to $20.9 million in the first nine months of 2002.
At September 30, 2003, our debt-to-total capitalization ratio was 31.0%, an
improvement from 36.5% at the end of 2002. This improvement was primarily the
result of the increased shareholders' equity from net income, a decrease in the
outstanding debt on the Hibernia credit facility and a reduction in our
nonrecourse note to Rocky Mountain Gas, Inc., both as described under
"--Liquidity and Capital Resources--Financing Arrangements."
During the second quarter of 2001, we acquired interests in natural gas and oil
leases in Wyoming and Montana in areas prospective for coalbed methane and
subsequently began to drill wells on those leases. During the second quarter of
2003, we contributed our interests in certain of these leases to a newly formed
company, Pinnacle Gas Resources, Inc. (Pinnacle). In exchange for this
contribution, we received 37.5% of the common stock of Pinnacle and options to
purchase additional Pinnacle common stock. We account for our interest in
Pinnacle using the equity method. As a result, our contributed operations and
reserves are no longer directly reflected in our financial statements. We
retained our interests in approximately 189,000 gross acres in the Castle Rock
project area in Montana and the Oyster Ridge project area in Wyoming. See
"Business and Properties--Pinnacle Transaction" for a description of this
transaction. Our discussion of future drilling and capital expenditures does not
reflect operations conducted through Pinnacle.
Since our initial public offering, we have grown primarily through the
exploration of properties within our project areas although we consider
acquisitions from time to time and may in the future complete acquisitions that
we find attractive.
RECENT DEVELOPMENTS
Fourth Quarter 2003 Operating Results
During the fourth quarter of 2003, in our core areas in the onshore Gulf Coast
of Texas and Louisiana, we participated in the drilling of 11 gross exploratory
wells, ten of which were successful. Also during the quarter, in our Barnett
Shale Project we participated in the drilling of two gross (one net) exploratory
wells and two gross (one net) development wells, all of which were successful.
On a combined basis for these two areas, we had a 93.3% success rate for the
quarter.
Production during the fourth quarter of 2003 was estimated at 1.85 Bcfe,
bringing our 2003 annual production to an estimated record level of 7.5 Bcfe, an
increase of 3.5% over our 2002 production level. Approximately 72% of our
production during the fourth quarter of 2003 and 64% of our production in the
full year 2003 was natural gas. We estimate that fourth quarter 2003 sales
prices, including the effect of hedging activities, averaged approximately $4.78
per Mcf and $29.61 per barrel. Based on our preliminary reserve estimates, we
believe that in 2003 we more than replaced our production with proved reserve
additions from our drilling activities.
Potential Barnett Shale Acquisition
We have entered into negotiations with a private company to purchase working
interests and acreage in certain oil and gas wells located in Denton County,
Texas in the Newark East Field in the Barnett Shale trend. This potential
acquisition, with an expected purchase price of $7.2 million, includes
non-operated working interests ranging from 12.5% to 45% over 3,800 acres. As of
January 1, 2004, the 14 producing wells (5.0 net) that would be included in the
acquisition were producing a net 1.4 MMcf/d with another five wells (1.3 net)
waiting for pipeline hook-up. We expect the undeveloped acreage to contribute
additional drilling locations, 13 of which will target proved undeveloped
reserves and 18 of which will be exploratory.
29
We expect that we would finance the acquisition with our current revolving
credit facility or, alternatively, with a new project financing facility that we
would seek to obtain. We currently have targeted a closing date of February 16,
2004 for the acquisition. There can be no assurance that the transaction
described above will be completed on the terms or timing described above or at
all. Regardless of whether this transaction is completed, we intend to continue
to pursue growth opportunities in this geologic trend.
RESULTS OF OPERATIONS
The following table summarizes production volumes, average sales prices and
operating revenues for our natural gas and oil operations for the years ended
December 31, 2000, 2001 and 2002 and for the nine months ended September 30,
2002 and 2003:
NINE MONTHS
% INCREASE % INCREASE ENDED
YEAR ENDED YEAR ENDED (DECREASE) YEAR ENDED (DECREASE) SEPTEMBER 30,
DECEMBER 31, DECEMBER 31, FROM 2000 DECEMBER 31, FROM 2001 -----------------
2000 2001 TO 2001 2002 TO 2002 2002 2003
------------ ------------ ------------ ------------ ------------ ------- -------
PRODUCTION VOLUMES
Oil and condensate
(MBbls)............... 198 160 (20)% 401 151% 261 363
Natural gas (MMcf)...... 5,460 4,432 (19) 4,801 8 3,543 3,432
Natural gas equivalent
(MMcfe)............. 6,651 5,390 (19) 7,207 34 5,109 5,607
AVERAGE SALES PRICES(1)
Oil and condensate
(MBbls)............... $ 27.81 $ 24.28 (13)% $ 24.94 3% $ 23.34 $ 29.08
Natural gas (MMcf)...... 3.90 5.04 (29) 3.50 (31) 3.24 5.56
OPERATING REVENUES (IN
THOUSANDS).............. $26,834 $26,226 (2)% $26,802 2% $17,559 $29,615
---------------------------
(1) Includes impact of hedging activities.
Nine Months Ended September 30, 2003 Compared to the Nine Months Ended
September 30, 2002
Natural gas and oil revenues for the nine months ended September 30, 2003
increased 69% to $29.6 million from $17.6 million for the same period in 2002.
Production volumes for natural gas during the nine months ended September 30,
2003 decreased 3% to 3.4 Bcf from 3.5 Bcf for the same period in 2002. Average
natural gas prices increased 72% to $5.56 per Mcf in the first nine months of
2003 from $3.24 per Mcf in the same period in 2002. Production volumes for oil
in the nine months ended September 30, 2003 increased 39% to 363 MBbls from 261
MBbls for the same period in 2002. Average oil prices increased 25% to $29.08
per barrel in the first nine months of 2003 from $23.34 per barrel in the same
period in 2002. The increase in oil production was due primarily to the
commencement of production at six wells offset by the natural decline in
production from other wells. The decrease in natural gas production was
primarily due to a workover at one well and natural production declines in other
wells offset by the commencement of production at new wells. Natural gas and oil
revenues include the impact of hedging activities as discussed below under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Critical Accounting Policies and Estimates--Derivative Instruments
and Hedging Activities."
Natural gas and oil operating expenses for the nine months ended September 30,
2003 increased 38% to $5.1 million from $3.7 million for the same period in 2002
primarily due to higher severance taxes and other operating costs associated
with the addition of new production. Operating expenses per equivalent unit
increased 25% to $0.90 per Mcfe in the first nine months of 2003 from $0.72 per
Mcfe in the same period in 2002 primarily as a result of the natural decline in
production on older wells and the addition of a relatively higher cost new well.
30
General and administrative (G&A) expense for the nine months ended September 30,
2003 increased 43% to $4.3 million from $3.0 million for the same period in
2002. The increase in G&A expense was due primarily to employee severance costs
and the addition of contract staff to handle increased drilling and production
activities, higher compensation costs and higher insurance.
Depreciation, depletion and amortization (DD&A) expense for the nine months
ended September 30, 2003 increased 19% to $8.7 million from $7.3 million for the
same period in 2002. This increase was due to increased production and
additional seismic and drilling costs.
Interest income for the nine months ended September 30, 2003 increased to
$50,000 from $44,000 in the first nine months of 2002 primarily as a result of
higher cash balances during the first quarter of 2003. Capitalized interest was
$2.2 million in the first nine months of 2003 and 2002.
Provision for income taxes increased to $4.1 million for the nine months ended
September 30, 2003 from $1.5 million for the same period in 2002 as a result of
higher taxable income based on the factors described above.
We adopted Financial Accounting Standards Board (FASB) Statement of Financial
Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement
Obligations," effective January 1, 2003 and recorded a cumulative effect of
change in accounting principle of $0.1 million in the nine months ended
September 30, 2003.
Income before income taxes for the nine months ended September 30, 2003
increased to $11.1 million from $3.9 million in the same period in 2002. Net
income for the nine months ended September 30, 2003 increased to $6.3 million
from $2.0 million for the same period in 2002 primarily as a result of the
factors described above.
Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001
Our natural gas and oil revenues for 2002 increased 2% to $26.8 million from
$26.2 million in 2001. Production volumes for natural gas in 2002 increased 8%
to 4,801 MMcf from 4,432 MMcf in 2001, due primarily to the commencement of
production at five wells, offset by natural production declines in other wells,
primarily from the initial Matagorda County Project wells. Realized average
natural gas prices decreased 31% to $3.50 per Mcf in 2002 from $5.04 per Mcf in
2001.
Production volumes for oil in 2002 increased 151% to 401 MBbls from 160 MBbls in
2001, due primarily to the commencement of production at four wells, offset by
natural production declines in other older wells. Natural gas and oil revenues
include the impact of hedging activities as discussed below under "--Critical
Accounting Policies and Estimates--Derivative Instruments and Hedging
Activities." Average oil prices increased 3% to $24.94 per Bbl in 2002 from
$24.28 per Bbl in 2001.
Natural gas and oil operating expenses for 2002 increased 19% to $4.9 million
from $4.1 million in 2001, primarily as a result of the addition of new natural
gas and oil wells drilled and completed since December 31, 2001 and higher ad
valorem taxes. Operating expenses per equivalent unit in 2002 decreased to $0.68
per Mcfe from $0.77 per Mcfe in 2001. The per-unit cost decreased primarily as a
result of the addition of higher-production-rate, lower-cost-per-unit wells,
offset by an increase in ad valorem taxes and decreased production of natural
gas as wells naturally declined.
DD&A expense for 2002 increased 63% to $10.6 million from $6.5 million in 2001.
This increase was due primarily to increased production and the additional
seismic and drilling costs added to the proved property cost base.
G&A expense for 2002 increased 24% to $4.1 million from $3.3 million for 2001.
The increase in G&A expense was due primarily to the addition of contract staff
to handle increased drilling and production activities and higher insurance
costs.
31
Interest income for 2002 decreased to $0.1 million from $0.3 million in 2001
primarily as a result of lower interest rates during 2002. Capitalized interest
decreased to $3.1 million in 2002 from $3.2 million in 2001 primarily due to
lower interest costs during 2002.
Provision for income taxes decreased to $2.8 million in 2002 from $5.3 million
in 2001.
Dividends and accretion of discount on preferred stock increased to $0.6 million
in 2002 from none in 2001 as a result of our sale of preferred stock in the
first quarter of 2002.
Net income for 2002 decreased to $4.8 million from $9.5 million in 2001
primarily as a result of the factors described above.
Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000
Natural gas and oil revenues for 2001 decreased 2% to $26.2 million from $26.8
million in 2000. Production volumes for natural gas in 2001 decreased 19% to
4,432 MMcf from 5,461 MMcf in 2000, due primarily to the sale of a project
during 2000 and the natural decline in production at certain wells, offset by
the commencement of production at other wells. Realized average natural gas
prices increased 29% to $5.04 per Mcf in 2001 from $3.90 per Mcf in 2000.
Production volumes for oil in 2001 decreased 20% to 160 MBbls from 199 MBbls in
2000 due to the natural decline in production at certain wells, offset by the
commencement of production of another well. Natural gas and oil revenues include
the cash effect of hedging activities as discussed below under "Critical
Accounting Policies and Estimates--Derivative Instruments and Hedging
Activities." Average oil prices decreased 13% to $24.28 per Bbl in 2001 from
$27.81 per Bbl in 2000.
Natural gas and oil operating expenses for 2001 decreased 16% to $4.1 million
from $4.9 million in 2000, primarily as a result of the lower production taxes
and the implementation of cost reduction measures in fields with decreased
production. Operating expenses per equivalent unit in 2001 increased to $0.77
per Mcfe from $0.74 per Mcfe in 2000. The per-unit cost increased primarily as a
result of an increase in severance taxes and decreased production of natural gas
as wells naturally declined.
Depreciation, depletion and amortization expense for 2001 decreased 9% to $6.5
million from $7.2 million in 2000. This decrease was primarily due to the
seismic and drilling costs added to the proved property cost base.
G&A expense for 2001 increased 6% to $3.3 million from $3.1 million for 2000.
The increase in G&A expense was due primarily to the addition of staff to handle
increased drilling and production activities and also to stock option
compensation expense, a noncash charge resulting from a decrease during 2001 and
an increase during the last six months of 2000 in the stock price underlying the
stock options that we repriced in February 2000.
Interest expense, net of amounts capitalized, for 2001 decreased 47% to $6,873
from $13,003 in 2000.
Provision for income taxes increased to $5.3 million in 2001 from $1.0 million
in 2000 as a result of an adjusted noncash valuation allowance during 2000 on
net operating loss carryforwards expected to be realized that resulted in a
deferred income tax benefit adjustment of $3.6 million, which reduced our
effective tax rate to 8% in 2000.
Other income for the year ended December 31, 2001 included a gain on the sale of
an investment in Michael Petroleum Corporation of $3.9 million, offset by:
- a charge and related legal expenses of $1.4 million in respect of the final
settlement of litigation with BNP Petroleum Corporation; and
- a noncash valuation allowance of $0.8 million relating to certain hedge
arrangements with Enron North America Corp.
Net income for 2001 decreased to $9.5 million from $12.0 million in 2000 as a
result of the factors described above.
32
LIQUIDITY AND CAPITAL RESOURCES
We have made and expect to make capital expenditures in excess of our net cash
flows provided by operating activities. We will require additional sources of
financing to fund drilling expenditures on properties we currently own and to
fund leasehold costs and geological and geophysical costs on our exploration
projects.
While we believe that current cash balances and anticipated cash provided by
operating activities for 2004 will provide sufficient capital to carry out our
exploration plans for that time period, our management continues to seek
financing for our capital program from a variety of sources. We may not be able
to obtain additional financing on terms that would be acceptable to us. If we
cannot obtain acceptable financing, we anticipate that we may be required to
limit or defer our planned natural gas and oil exploration and development
program, thereby adversely affecting the recoverability and ultimate value of
our natural gas and oil properties. See "Risk Factors--We have substantial
capital requirements that, if not met, may hinder operations."
Our primary sources of liquidity have included funds generated by operations,
proceeds from the issuance of various securities, including our common stock,
preferred stock and warrants, and borrowings, primarily under revolving credit
facilities and through the issuance of senior subordinated notes.
Cash flows provided by operating activities were $17.1 million, $24.0 million
and $19.9 million for 2000, 2001 and 2002, respectively, and $12.3 million and
$23.5 million for the nine months ended September 30, 2002 and 2003,
respectively. The increase in cash flows provided by operating activities in
2003 as compared to 2002 was due primarily to additional revenue resulting from
higher natural gas and oil prices and higher oil and condensate production,
offset by an increase in our working capital during the first nine months of
2003.
Estimated maturities of long-term debt are $3.9 million in 2004, $8.5 million in
2005 and the remainder in 2007.
Capital Expenditures
We have budgeted capital expenditures in 2003 of approximately $25.9 million, of
which we expect to use $5.2 million to fund 3-D seismic surveys and acquire land
and $20.7 million for drilling activities in our project areas. We have budgeted
to drill approximately 25 wells (9.9 net) in the onshore Gulf Coast region and
no coalbed methane wells in 2003. In 2004, we expect capital expenditures to be
approximately $40 to $45 million (a 58 to 78% increase over our expected 2003
capital expenditures). We expect to drill 38 wells in 2004 (18.5 net), 30 of
which we expect to operate. The actual number of wells drilled and the amount of
capital expended depends on available financing, cash flow, availability and
cost of drilling rigs, land and partner issues and other factors.
We have continued to reinvest a substantial portion of our cash flows into
increasing our 3-D prospect portfolio, improving our 3-D seismic interpretation
technology and funding our drilling program. Capital expenditures were $20.4
million for the nine months ended September 30, 2003, which included $2.2
million of capitalized interest and general and administrative costs. Our
drilling efforts in the onshore Gulf Coast region resulted in the successful
completion of 17 wells (6.0 net) in 2002 and 19 wells (5.2 net) in the nine
months ended September 30, 2003. Of the 77 coalbed methane wells (19 net) we
drilled or acquired in the Rocky Mountain region through September 30, 2003, 24
wells (8 net) are currently producing and 53 wells (21 net) are in various
stages of evaluation.
Pursuant to an exchange election provided in a letter agreement dated May 1,
2001, with some of the participants in the Carrizo 2001 Seismic and Acreage
Program, we issued to those participants who exercised their election
approximately 168,000 shares of our common stock in exchange for the
participants' interest in that program, including interests in approximately 350
square miles of 3-D seismic data and working interests in specified producing
properties. The exchange transaction was effective on October 10, 2003 and was
valued at approximately $1.2 million using the closing price of our stock on
that date.
33
Financing Arrangements
Hibernia Credit Facility
On May 24, 2002, we entered into a credit agreement with Hibernia National Bank
that matures on January 31, 2005, and repaid our prior facility with Compass
Bank. The Hibernia credit facility provides a revolving line of credit of up to
$30.0 million. It is secured by substantially all of our producing assets.
The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The borrowing base as of October
31, 2003 was $19.0 million, of which $7.0 million was drawn as of that date.
Each party to the credit agreement can request one unscheduled borrowing base
determination subsequent to each scheduled determination. The borrowing base
will at all times equal the borrowing base most recently determined by Hibernia
National Bank, less quarterly borrowing base reductions required subsequent to
such determination. The quarterly borrowing base reduction effective January 31,
2004 will be $3.0 million.
If the outstanding principal balance of the Hibernia credit facility exceeds the
borrowing base at any time, we have the option within 30 days to take any of the
following actions, either individually or in combination: make a lump sum
payment curing the deficiency, pledge additional collateral sufficient in
Hibernia National Bank's opinion to increase the borrowing base and cure the
deficiency or begin making equal monthly principal payments that will cure the
deficiency within the ensuing six-month period. Those payments would be in
addition to any payments that may come due as a result of the quarterly
borrowing base reductions. Otherwise, any unpaid principal or interest will be
due at maturity.
The interest rate applicable to incremental borrowings under this credit
facility will be, at our option, a eurodollar rate or a base rate, in each case
plus an applicable margin based upon borrowing levels.
We are subject to specified covenants under the terms of the Hibernia credit
facility, including but not limited to maintaining a minimum current ratio, a
minimum quarterly debt services coverage ratio and a minimum level of
shareholders' equity. The Hibernia credit facility also places restrictions on
additional indebtedness, dividends to shareholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, change of
control, repurchase or redemption for cash of our common or preferred stock,
speculative commodity transactions and other matters.
Rocky Mountain Gas Note
In June 2001, our subsidiary CCBM issued a nonrecourse promissory note in the
amount of $7.5 million to Rocky Mountain Gas, Inc. (RMG) as consideration for
specified interests in natural gas and oil leases held by RMG in Wyoming and
Montana. At September 30, 2003, the outstanding principal balance of this note
was $1.0 million.
Capital Leases
We have entered into capital lease agreements, each secured by specified
production equipment, with payment obligations of $0.4 million in 2004, $0.3
million in 2005 and $0.1 million in 2006.
Senior Subordinated Notes and Related Securities
In December 1999, we sold $22.0 million principal amount of 9% Senior
Subordinated Notes due 2007. The senior subordinated notes were sold at a
discount of $0.7 million, which is being amortized over the life of the notes.
Interest is payable quarterly beginning March 31, 2000. We may elect, until
December 2004, to increase the amount of the senior subordinated notes for up to
60% of the interest rate which would otherwise be payable in cash. As of
December 31, 2002 and September 30, 2003, the outstanding balance of the senior
subordinated notes had been increased by $3.9 million and $5.0 million,
respectively, for such interest paid in kind.
Concurrently with the sale of the senior subordinated notes, we sold 3,636,364
shares of our common stock at a price of $2.20 per share and warrants expiring
in December 2007 to purchase up to 2,760,189 shares
34
of our common stock at an exercise price of $2.20 per share. For accounting
purposes, the warrants were valued at $0.25 each. We sold the warrants to CB
Capital Investors, L.P. (now JPMorgan), Mellon, Paul B. Loyd, Jr., Steven A.
Webster and Douglas A.P. Hamilton.
We are subject to specified covenants under the terms of the securities purchase
agreement related to the senior subordinated notes, including but not limited to
maintenance of a specified tangible net worth and a debt service coverage ratio
and limits on our ability to incur indebtedness and to engage in certain
transactions and activities.
Series B Preferred Stock
In February 2002, we sold 60,000 shares of our Series B preferred stock and
warrants to purchase 252,632 shares of our common stock for an aggregate
purchase price of $6.0 million. We sold $4.0 million of Series B preferred stock
and 168,422 warrants to Mellon and $2.0 million of Series B preferred stock and
84,210 warrants to Steven A. Webster, our Chairman of the Board. The investors
may convert the Series B preferred stock into common stock at a conversion price
of $5.70 per share, subject to adjustment for transactions including issuance of
common stock or securities convertible into or exercisable for common stock at
less than the conversion price of the Series B preferred stock. The approximate
$5.8 million net proceeds of this financing were used to fund our ongoing
exploration and development program and for general corporate purposes.
Dividends on the Series B preferred stock are payable either in cash at a rate
of 8% per annum or, at our option, by payment in kind of additional shares of
the Series B preferred stock at a rate of 10% per annum. At December 31, 2002
and September 30, 2003, the outstanding balance of the Series B preferred stock
had been increased by $0.5 million (5,294 shares) and $0.9 million (8,559
shares), respectively, for dividends paid in kind. At September 30, 2003, we had
accrued a dividend of $0.2 million that we paid on December 31, 2003. In
addition to the foregoing, if we declare a cash dividend on our common stock,
the holders of shares of Series B preferred stock are entitled to receive for
each share of Series B preferred stock a cash dividend in the amount of the cash
dividend that would be received by a holder of the common stock into which that
share of Series B preferred stock is convertible on the record date for the cash
dividend. Unless all accrued dividends on the Series B preferred stock shall
have been paid and a sum sufficient for the payment thereof set apart, no
distributions may be paid on any Junior Stock (as defined in the Statement of
Resolutions for the Series B preferred stock) (which includes the common stock),
and no redemption of any junior stock shall occur other than subject to
specified exceptions.
We must redeem the Series B preferred stock at any time after the third
anniversary of its initial issuance upon request from any holder at a price per
share equal to Purchase Price/Dividend Preference (as defined below). We may
redeem the Series B preferred stock after the third anniversary of its issuance
at a price per share equal to the Purchase Price/Dividend Preference and, prior
to that time, at varying preferences to the Purchase Price/Dividend Preference.
"Purchase Price/Dividend Preference" is defined to mean, generally, $100 plus
all cumulative and accrued dividends.
In the event of any dissolution, liquidation or winding up or specified mergers
or sales or other disposition by us of all or substantially all of our assets,
the holder of each share of Series B preferred stock then outstanding will be
entitled to be paid per share of Series B preferred stock, prior to the payment
to holders of our common stock and out of our assets available for distribution
to our shareholders, the greater of:
- $100 in cash plus all cumulative and accrued dividends; and
- in specified circumstances, the "as-converted" liquidation distribution, if
any, payable in such liquidation with respect to each share of common
stock.
Upon the occurrence of specified events constituting a "Change of Control" (as
defined in the Statement of Resolutions), we must make an offer to each holder
of Series B preferred stock to repurchase all of that holder's Series B
preferred stock at an offer price per share of Series B preferred stock in cash
equal to
35
105% of the Change of Control Purchase Price, which is generally defined to mean
$100 plus all cumulative and accrued dividends.
The warrants issued in connection with the Series B preferred stock have a
five-year term, entitle the holders to purchase up to 252,632 shares of our
common stock at a price of $5.94 per share, subject to adjustment, and are
exercisable at any time after issuance. For accounting purposes, the warrants
are valued at $0.06 per warrant.
EFFECTS OF INFLATION AND CHANGES IN PRICE
Our results of operations and cash flows are affected by changing natural gas
and oil prices. If the price of natural gas and oil increases (decreases), there
could be a corresponding increase (decrease) in the operating cost we are
required to bear for operations, as well as an increase (decrease) in revenues.
Inflation has had a minimal effect on us.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The following summarizes several of our critical accounting policies. See a
complete list of significant accounting policies in Note 2 to the Consolidated
Financial Statements.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from these estimates. The use of these estimates
significantly affects natural gas and oil properties through depletion and the
full cost ceiling test, as discussed in more detail below.
Natural Gas and Oil Properties
We account for investments in natural gas and oil properties using the full-cost
method of accounting. All costs directly associated with the acquisition,
exploration and development of natural gas and oil properties are capitalized.
These costs include lease acquisitions, seismic surveys, and drilling and
completion equipment. We proportionally consolidate our interests in natural gas
and oil properties. We capitalized compensation costs for employees working
directly on exploration activities of $0.7 million and $1.1 million for the nine
months ended September 30, 2002 and 2003, respectively. We expense maintenance
and repairs as they are incurred.
We amortize natural gas and oil properties based on the unit-of-production
method using estimates of proved reserve quantities. We do not amortize
investments in unproved properties until proved reserves associated with the
projects can be determined or until these investments are impaired. We
periodically evaluate, on a property-by-property basis, unevaluated properties
for impairment. If the results of an assessment indicate that the properties are
impaired, we add the amount of impairment to the proved natural gas and oil
property costs to be amortized. The amortizable base includes estimated future
development costs. The depletion rate per thousand cubic feet equivalent (Mcfe)
for the nine months ended September 30, 2002 and 2003 was $1.40 and $1.51,
respectively.
We account for dispositions of natural gas and oil properties as adjustments to
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves. We have not had any transactions that significantly alter that
relationship.
The net capitalized costs of proved natural gas and oil properties are subject
to a ceiling test, which limits such costs to the estimated present value,
discounted at a 10% interest rate, of future net revenues from proved reserves
(the NPV) based on current economic and operating conditions (with reserve
estimates calculated using SEC guidelines). This test is performed after any
impairment of unproved properties are
36
added to the property costs to amortize as discussed above. We include asset
retirement obligation costs, liabilities and related discounted cash flows in
our ceiling test calculations. If net capitalized costs exceed this limit, we
charge the excess to operations through depreciation, depletion and
amortization. No write-down of our natural gas and oil assets was necessary for
the nine months ended September 30, 2002 or 2003. In concert with this
determination, a price sensitivity study also indicated that a 20% increase in
commodity prices at September 30, 2003 would have increased our NPV by
approximately $15.8 million. Conversely, a 20% decrease in commodity prices at
September 30, 2003 would have reduced our NPV by approximately $18.4 million.
This would have caused our unamortized cost of proved natural gas and oil
properties to exceed the cost pool ceiling by approximately $18.1 million. Our
aforementioned price sensitivity and NPV is as of September 30, 2003 and,
accordingly, does not include any potential changes in reserves due to fourth
quarter performance, such as commodity prices, reserve revisions and drilling
results, including proved reserves associated with our recently discovered
Shadyside #1 well. Based on natural gas and oil prices in effect on December 31,
2001, the unamortized cost of natural gas and oil properties exceeded the cost
center ceiling. As permitted by full cost accounting rules, improvements in
pricing subsequent to December 31, 2001 removed the necessity to record a
write-down. Using prices in effect on December 31, 2001 the pretax write-down
would have been approximately $0.7 million. Because of the volatility of natural
gas and oil prices, we cannot assure you that we will not experience a write-
down in future periods.
Under the full cost method of accounting, the depletion rate is the current
period production as a percentage of the total proved reserves. Total proved
reserves include both proved developed and proved undeveloped reserves. The
depletion rate is applied to the net book value and estimated future development
costs to calculate the depletion expense.
We have a significant amount of proved undeveloped reserves, which are primarily
oil reserves. We had 41.9 Bcfe of proved undeveloped reserves, representing 66%
of our total proved reserves at December 31, 2002. These reserves are primarily
attributable to our Camp Hill properties we acquired in 1994. This ratio of
proved undeveloped reserves to total proved reserves and the producing
properties that have had an average productive life of 2.25 years since our
inception, compared to the average 10 year depletable life for the total proved
reserves, has resulted in a relatively low historical depletion rate and
depreciation expense. This has resulted in a capitalized cost basis associated
with producing properties being depleted over a longer period than the
associated production and revenue stream. It has also resulted in the build-up
of nondepleted capitalized costs associated with properties that have been
completely produced out.
We expect our low historical depletion rate to continue until the high level of
nonproducing reserves to total proved reserves is reduced and the life of our
proved developed reserves is extended through development drilling and/or the
significant addition of new proved producing reserves through acquisition or
exploration. If our level of total proved reserves and current prices were both
to remain constant, this continued build-up of capitalized costs increases the
probability of a ceiling test write-down.
We depreciate other property and equipment using the straight-line method based
on estimated useful lives ranging from five to 10 years.
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Intangible Assets," were issued by the FASB in June 2001 and became effective
for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires
all business combinations initiated after June 30, 2001 to be accounted for
using the purchase method. Additionally, SFAS No. 141 requires companies to
disaggregate and report separately from goodwill certain intangible assets. SFAS
No. 142 establishes new guidelines for accounting for goodwill and other
intangible assets. Under SFAS No. 142, goodwill and certain other intangible
assets are not amortized but rather are reviewed annually for impairment.
Natural gas and oil mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves for both
undeveloped and developed leaseholds may have to be classified separately from
natural gas and oil properties as intangible assets on our consolidated balance
sheets. In addition, the disclosures required by SFAS No. 141 and 142 relative
to intangibles would be included in the notes to the consolidated financial
statements. Historically, we, like many other natural gas and oil
37
companies, have included these rights as part of natural gas and oil properties,
even after SFAS No. 141 and 142 became effective.
As it applies to companies like us that have adopted full cost accounting for
natural gas and oil activities, we understand that this interpretation of SFAS
No. 141 and 142 would only affect our balance sheet classification of proved
natural gas and oil leaseholds acquired after June 30, 2001 and all of our
unproved natural gas and oil leaseholds. We would not be required to reclassify
proved reserve leasehold acquisitions prior to June 30, 2001 because we did not
separately value or account for these costs prior to the adoption date of SFAS
No. 141. Our results of operations and cash flows would not be affected, since
these natural gas and oil mineral rights held under lease and other contractual
arrangements representing the right to extract natural gas and oil reserves
would continue to be amortized in accordance with full cost accounting rules.
As of September 30, 2003, December 31, 2002 and December 31, 2001, we had
leasehold costs incurred of approximately $3.4 million, $1.4 million and $1.4
million, respectively, that would be classified on our consolidated balance
sheet as "intangible leasehold costs" if we applied the interpretation discussed
above.
We will continue to classify our natural gas and oil mineral rights held under
lease and other contractual rights representing the right to extract such
reserves as tangible oil and gas properties until further guidance is provided.
Natural Gas and Oil Reserve Estimates
The reserve data included or incorporated in this prospectus are estimates
prepared by Ryder Scott Company and Fairchild and Wells, Inc., Independent
Petroleum Engineers. Reserve engineering is a subjective process of estimating
underground accumulations of hydrocarbons that cannot be measured in an exact
manner. The process relies on interpretation of available geologic, geophysical,
engineering and production data. The extent, quality and reliability of this
data can vary. The process also requires certain economic assumptions regarding
drilling and operating expense, capital expenditures, taxes and availability of
funds. The SEC mandates some of these assumptions such as natural gas and oil
prices and the present value discount rate.
Proved reserve estimates prepared by others may be substantially higher or lower
than our estimates. Because these estimates depend on many assumptions, all of
which may differ from actual results, reserve quantities actually recovered may
be significantly different than estimated. Material revisions to reserve
estimates may be made depending on the results of drilling, testing and rates of
production.
You should not assume that the present value of future net cash flows is the
current market value of our estimated proved reserves. In accordance with SEC
requirements, we have based our estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate.
Our rate of recording depreciation, depletion and amortization expense for
proved properties is dependent on our estimate of proved reserves. If these
reserve estimates decline, the rate at which we record these expenses will
increase.
Derivative Instruments and Hedging Activities
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This statement, as amended by SFAS No. 137
and SFAS No. 138, establishes standards of accounting for and disclosures of
derivative instruments and hedging activities. This statement requires all
derivative instruments to be carried on the balance sheet at fair value with
changes in a derivative instrument's fair value recognized currently in earnings
unless specific hedge accounting criteria are met. SFAS No. 133 was effective
for us beginning January 1, 2001 and we adopted it on that date. In accordance
with the current transition provisions of SFAS No. 133, we recorded a cumulative
effect transition adjustment of $2.0 million (net of related tax expense of $1.1
million) in accumulated other comprehensive income to recognize the fair value
of our derivatives designated as cash flow hedging instruments at the date of
adoption.
38
Upon entering into a derivative contract, we designate the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as natural gas
and oil revenues when the forecasted transaction occurs. All of our derivative
instruments at December 31, 2002 and September 30, 2003 were designated and
effective as cash flow hedges except for certain options described below under
"--Qualitative and Quantitative Disclosures About Market Risk--Derivative
Instruments and Hedging Activities."
When we discontinue hedge accounting because it is probable that a forecasted
transaction will not occur, we continue to carry the derivative on the balance
sheet at its fair value and immediately recognize in earnings any gains and
losses that were accumulated in other comprehensive income. In all other
situations in which we discontinue hedge accounting, we will carry the
derivative at fair value on our balance sheet and will recognize in future
earnings any future changes in its fair value.
We typically use fixed rate swaps and costless collars to hedge our exposure to
material changes in the price of natural gas and oil. We formally document all
relationships between hedging instruments and hedged items as well as our risk
management objectives and strategy for undertaking various hedge transactions.
This process includes linking all derivatives that are designated cash flow
hedges to forecasted transactions. We also formally assess, both at the hedge's
inception and on an ongoing basis, whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows of
hedged transactions.
Our Board of Directors sets our hedging policy, including volumes, types of
instruments and counterparties, on a quarterly basis. Management implements
these policies through the execution of trades by either the President or Chief
Financial Officer after consultation with and concurrence by the other as well
as the Chairman of the Board. The master contracts with the authorized
counterparties identify the President and Chief Financial Officer as the only
company representatives authorized to execute trades. The Board of Directors
also reviews the status and results of hedging activities quarterly.
Income Taxes
Under SFAS No. 109, "Accounting for Income Taxes," we recognize deferred income
taxes at each year end for the future tax consequences of differences between
the tax bases of assets and liabilities and their financial reporting amounts
based on tax laws and statutory tax rates applicable to the periods in which the
differences are expected to affect taxable income. We establish valuation
allowances when necessary to reduce the deferred tax asset to the amount
expected to be realized.
Contingencies
We recognize liabilities and other contingencies upon our determination that it
is both probable that an asset has been impaired or that a liability has been
incurred and that the amount of such loss is reasonably estimable.
NEW ACCOUNTING PRONOUNCEMENTS
The FASB issued Interpretation 46, "Consolidation of Variable Interest Entities"
(FIN 46), in January 2003. FIN 46 requires the consolidation of specified types
of entities in which a company absorbs a majority of another entity's expected
losses, receives a majority of the other entity's expected residual returns, or
both, as a result of ownership, contractual or other financial interests in the
other entity. These entities are called "variable interest entities." The
provisions of FIN 46 were effective for us in the second quarter for new
transactions or entities formed in 2003 and in the third quarter for
transactions or entities formed prior to 2003.
39
If an entity is determined to be a "variable interest entity" (VIE), the entity
must be consolidated by the "primary beneficiary." The primary beneficiary is
the holder of the variable interests that absorbs a majority of the variable
interest entity's expected losses or receives a majority of the entity's
residual returns in the event no holder has a majority of the expected losses.
The primary beneficiary is determined based on projected cash flows at the
inception of the variable interests.
We have assessed whether to consolidate Pinnacle under FIN 46. Because Steven A.
Webster, our Chairman, is also a managing director of Credit Suisse First Boston
(whose interest in Pinnacle is described under "Business and
Properties--Pinnacle Transaction") we could be defined as the primary
beneficiary if the projected cash flows analysis indicated losses in excess of
the equity invested. The initial determination of whether an entity is a VIE is
to be reconsidered only when one or more of the following occur:
- the entity's governing documents or the contractual arrangements among the
parties involved change;
- the equity investment of some part thereof is returned to the investors,
and other parties become exposed to expected losses; or
- the entity undertakes additional activities or acquires additional assets
that increase the entity's expected losses.
We have determined that we should not consolidate Pinnacle under FIN 46 because
our current projected cash flow analysis of Pinnacle's operations at inception
indicates that Pinnacle is not a VIE. Accordingly, our investment in Pinnacle
has been recorded using the equity method of accounting.
The reclassification of investments in contributed properties resulting from the
transaction with Pinnacle is reflected on our balance sheet as of September 30,
2003 in accordance with the full cost method of accounting.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
Our major market risk exposure is the commodity pricing applicable to our
natural gas and oil production. Realized commodity prices received for such
production are primarily driven by the prevailing worldwide price for oil and
spot prices applicable to natural gas. Those prices are and are expected to
continue to be volatile. See "Risk Factors--Natural gas and oil prices are
highly volatile, and lower prices will negatively affect our financial results."
A 10% fluctuation in the price received for natural gas and oil production would
have an approximate $2.7 million and $3.0 million impact on our annual revenues
and operating income for the year ended December 31, 2002 and the nine months
ended September 30, 2003, respectively.
Derivative Instruments and Hedging Activities
To mitigate some of our commodity price risk, we engage periodically in certain
limited hedging activities but only to the extent of buying protection price
floors. We record the costs and any benefits derived from these price floors as
a reduction or increase, as applicable, in natural gas and oil sales revenue;
these reductions and increases were not significant for any year presented in
the financial information included or incorporated in this prospectus. The costs
to purchase put options are amortized over the option period. We do not hold or
issue derivative instruments for trading purposes. We realized losses related to
these instruments of $0.4 million and $1.8 million for the nine months ended
September 30, 2002 and 2003, respectively.
As of December 31, 2002 and September 30, 2003, $0.4 million and $67,000, net of
tax of $0.2 million and $36,000, respectively, remained in accumulated other
comprehensive income related to the valuation of our hedging positions.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit our ability to benefit from increases in the prices
of natural gas and oil. We enter into the majority of our hedging transactions
with two counterparties and have a netting agreement in place with those
40
counterparties. We do not obtain collateral to support the agreements but
monitor the financial viability of counterparties and believe our credit risk is
minimal on these transactions. Under these arrangements, payments are received
or made based on the differential between a fixed and a variable product price.
These agreements are settled in cash at expiration or exchanged for physical
delivery contracts. In the event of nonperformance, we would be exposed again to
price risk. We have some risk of financial loss because the price received for
the product at the actual physical delivery point may differ from the prevailing
price at the delivery point required for settlement of the hedging transaction.
Moreover, our hedging arrangements generally do not apply to all of our
production and thus provide only partial price protection against declines in
commodity prices. We expect that the amount of our hedges will vary from time to
time.
Our gas derivative transactions are generally settled based upon the average of
the reporting settlement prices on the NYMEX for the last three trading days of
a particular contract month. Our oil derivative transactions are generally
settled based on the average reporting settlement prices on the NYMEX for each
trading day of a particular calendar month. For the month of December 2002 a
$0.10 change in the price per Mcf of gas sold would have changed revenue by
$44,000. A $0.70 change in the price per barrel of oil would have changed
revenue by $41,000.
The table below summarizes our total natural gas production volumes subject to
derivative transactions during 2002 and the weighted average NYMEX reference
price for those volumes.
NATURAL GAS SWAPS
-----------------
Volumes (MMBtu).................... 2,131,000
Average price ($/MMBtu)............ $3.20
NATURAL GAS CAPS
----------------
Volumes (MMBtu).................... 183,000
Average price ($/MMBtu)
Floor.......................... $3.50
Ceiling........................ $4.52
The table below summarizes our total crude oil production volumes subject to
derivative transactions during 2002 and the weighted average NYMEX reference
price for those volumes.
CRUDE OIL SWAPS
---------------
Volumes (Bbls)................. 131,600
Average price ($/Bbls)......... $ 25.52
Total oil purchased and sold under swaps and collars during the three months
ended September 30, 2002 and 2003 were 33,600 Bbls and 24,400 Bbls,
respectively. Total natural gas purchased and sold under swaps and collars
during the three months ended September 30, 2002 and 2003 was 731,000 MMBtu and
828,000 MMBtu, respectively. Total oil purchased and sold under swaps and
collars during the nine months ended September 30, 2002 and 2003 was 79,100 Bbls
and 150,700 Bbls, respectively. Total natural gas purchased and sold under swaps
and collars during the nine months ended September 30, 2002 and 2003 was
3,094,000 MMBtu and 2,187,000 MMBtu, respectively. We realized net losses under
these hedging arrangements of $0.1 million and $0.1 million for the three months
ended September 30, 2002 and 2003, respectively, and $0.4 million and $1.7
million for the nine months ended September 30, 2002 and 2003, respectively.
41
At December 31, 2002 and September 30, 2003, we had the following outstanding
hedge positions:
DECEMBER 31, 2002
-----------------------------------------------------------------------------------------------------
CONTRACT VOLUMES
------------------ AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------------------------------------- -------- ------- ----------- ----------- -------------
First Quarter 2003................... 27,000 $24.85
First Quarter 2003................... 36,000 $23.50 $26.50
First Quarter 2003................... 540,000 3.40 5.25
Second Quarter 2003.................. 27,300 24.85
Second Quarter 2003.................. 36,000 23.50 26.50
Second Quarter 2003.................. 546,000 3.40 5.25
Third Quarter 2003................... 552,000 3.40 5.25
Fourth Quarter 2003.................. 552,000 3.40 5.25
SEPTEMBER 30, 2003
-----------------------------------------------------------------------------------------------------
CONTRACT VOLUMES
------------------ AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------------------------------------- -------- ------- ----------- ----------- -------------
Fourth Quarter 2003.................. 30,700 $30.22
Fourth Quarter 2003.................. 552,000 $3.40 $5.25
First Quarter 2004................... 546,000 4.10 7.00
Second Quarter 2004.................. 273,000 4.00 5.20
Third Quarter 2004................... 276,000 4.00 5.20
Fourth Quarter 2004.................. 93,000 4.00 5.20
From October 1, 2003 through January 12, 2004, we entered into swap arrangements
covering 51,500 Bbls of oil for November 2003 through May 2004 production with
an average fixed price of $30.33. We also entered into swap arrangements
covering 180,000 MMBtu of natural gas for January 2004 through February 2004
production with an average fixed price of $6.67 and costless collar arrangements
covering 825,000 MMBtu of natural gas production for April 2004 through December
2004 with a floor of $4.00 and a ceiling of $6.00.
In addition to the hedge positions above, during the second quarter of 2003, we
acquired call options to sell 6,000 MMBtu of natural gas per day for the period
July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for
approximately $119,000. We acquired these options to protect our cash position
against potential margin calls on certain natural gas derivatives due to large
increases in the price of natural gas. We expensed $119,000 related to the
expiration of these options during the nine months ended September 30, 2003.
Interest Rate Risk
Our floating rate debt exposes us to changes in interest rates. With regard to
our revolving credit facility, a 10% fluctuation in short-term interest rates
would have impacted our 2002 cash flow by approximately $32,000.
Financial Instruments and Debt Maturities
Our financial instruments consist of cash and cash equivalents, accounts
receivable, accounts payable, bank borrowing, senior subordinated notes payable
and Series B redeemable preferred stock. The carrying amounts of cash and cash
equivalents, accounts receivable and accounts payable approximate fair value due
to the highly liquid nature of these short-term instruments. The fair values of
the bank and vendor borrowings approximate the carrying amounts as of September
30, 2002 and 2003, and were determined based upon interest rates currently
available to us for borrowings with similar terms. Maturities of the debt are
$1.6 million in 2003, $3.9 million in 2004, $8.5 million in 2005 and the balance
in 2007.
42
BUSINESS AND PROPERTIES
Certain terms used in this section relating to the natural gas and oil industry
are defined in the "Glossary of Certain Oil and Gas Terms" in this prospectus.
Unless explicitly stated otherwise, or the context otherwise requires, all
references in this section to planned capital expenditures or planned drilling
activities assume the completion of this offering.
GENERAL
We are an independent energy company engaged in the exploration, development and
production of natural gas and oil. Our current operations are focused in proven,
producing natural gas and oil geologic trends along the onshore Gulf Coast in
Texas and Louisiana, primarily in the Miocene, Wilcox, Frio and Vicksburg
trends. Our other interests include properties in East Texas, a coalbed methane
investment in the Rocky Mountains and, recently, the Barnett Shale trend in
North Texas. Additionally, in 2003 we obtained licenses to explore in the U.K.
North Sea.
We have grown our production through our 3-D seismic-driven exploratory drilling
program. Our compound production growth rate for the period December 31, 1999
through September 30, 2003 on an annualized basis was 19%. From our inception
through September 30, 2003, we participated in the drilling of 285 wells (88.0
net) with a success rate of approximately 67% in our onshore Gulf Coast core
area. Exploratory wells accounted for 97% of the total wells we drilled. Our
total proved reserves as of December 31, 2002 were an estimated 63.2 Bcfe with a
PV-10 Value of $83.6 million. During 2002, we added 11.4 Bcfe to proved reserves
and produced 7.2 Bcfe.
As a main component of our business strategy, we have acquired licenses for over
8,700 square miles of 3-D seismic data for processing and evaluation. Since
2001, we have been able to increase the size of our 3-D seismic holdings in our
onshore Gulf Coast core area by approximately 75% to over 6,650 square miles, in
large part by taking advantage of very favorable pricing available for
nonproprietary data. One of our primary strengths is the experience of our
management and technical staff in the development, processing and analysis of
this 3-D seismic data to generate and drill natural gas and oil prospects. Our
technical and operating employees have an average of over 20 years of industry
experience, in many cases with major and large independent oil and gas
companies, including Shell Oil, ARCO, Conoco, Vastar Resources, Pennzoil and
Tenneco. Using our 3-D seismic database, our highly qualified technical staff is
continually adding to and refining our substantial inventory of drilling
locations.
We believe that our utilization of large-scale 3-D seismic surveys and related
technology allows us to create and maintain a multiyear inventory of
high-quality exploration prospects. As of September 30, 2003, we had 85,678
gross acres in Texas and Louisiana under lease or lease option, almost all of
which is covered by 3-D seismic data. On this leased acreage, we have identified
over 120 potential exploratory drilling locations, including over 45 additional
extension opportunities, depending on the success of our initial drilling
activities on those locations. The vast majority of our 3-D seismic data covers
productive geological trends in our onshore Gulf Coast core area, where we have
made 192 completions as a result of our utilization and evaluation of this data.
BUSINESS STRATEGY
Growth Through the Drillbit
Our objective is to create shareholder value through the execution of a business
strategy designed to capitalize on our strengths. Key elements of our business
strategy include:
- Grow Primarily Through Drilling. We are pursuing an active
technology-driven exploration drilling program. We generate exploration
prospects through geological and geophysical analysis of 3-D seismic and
other data. Our ability to successfully define and drill exploratory
prospects is demonstrated by our exploratory drilling success rate in the
onshore Gulf Coast core area of 72% over the last three years. We are
drilling or plan to drill approximately 32 wells (15.5 net) in the
43
onshore Gulf Coast area during 2004. We have budgeted approximately $40 to
45 million for capital expenditures in 2004, $37.7 million of which we
expect to use for drilling activities in the onshore Gulf Coast area.
- Focus on Prolific and Industry-Proven Trends. We focus our activities
primarily in the prolific onshore Gulf Coast area where our management, our
technical staff and our field operations teams have significant prior
experience. Although we have broadened our areas of operations to include
the Rocky Mountains and have purchased interests in the Barnett Shale trend
and the U.K. North Sea, we plan to focus a majority of our near-term
capital expenditures in the onshore Gulf Coast region, where we believe our
accumulated data and knowledge base provide a competitive advantage.
- Aggressively Evaluate 3-D Seismic Data and Acquire Acreage to Maintain a
Large Drillsite Inventory. We have accumulated and continue to add to a
multiyear inventory of 3-D seismic and geologic data along the prolific
producing trends of our onshore Gulf Coast region. In 2003, we added
approximately 1,050 square miles of newly released 3-D and seismic data. We
believe our utilization of large-scale 3-D seismic surveys and related
technology provides us with the opportunity to maximize our exploration
success. As of September 30, 2003, we had accumulated licenses for
approximately 8,700 square miles of 3-D seismic data and identified over
210 drilling locations and extension opportunities, including 123 currently
under lease or in the process of being leased.
- Maintain a Balanced Exploration Drilling Portfolio. We seek to balance our
drilling program between projects with relatively lower risk and moderate
potential and drilling prospects that have relatively higher risk and
substantial potential. We will continue to expand our exploratory drilling
portfolio, including possibly through acquisitions with exploration
potential.
- Manage Risk Exposure by Market Testing Prospects and Optimizing Working
Interests. We seek to limit our financial and operating risks by varying
our level of participation in drilling prospects with differing risk
profiles and by seeking additional technical input and economic review from
knowledgeable industry participants regarding our prospects. Additionally,
we rely on advanced technologies, including 3-D seismic analysis, to better
define geologic risks, thereby enhancing the results of our drilling
efforts. We also seek to operate our projects in order to better control
drilling costs and the timing of drilling.
- Retain and Incentivize a Highly Qualified Technical Staff. We employ 18
natural gas and oil professionals, including geophysicists,
petrophysicists, geologists, petroleum engineers and production and reserve
engineers, who have an average of over 20 years of experience. This level
of expertise and experience gives us a unique in-house ability to apply
advanced technologies to our drilling and production activities. Our
technical staff is granted stock options and participates in an incentive
bonus pool based on production resulting from our exploratory successes.
SIGNIFICANT AREAS
For the period from January 1, 2000 through December 31, 2002, we completed 61
wells (18.8 net) in 84 attempts for a success rate of 73%. Total exploration,
development and acquisition activities from January 1, 2000 through December 31,
2002 resulted in the addition of approximately 26.4 Bcfe, net to our interest.
44
We have budgeted approximately $40 to $45 million to drill approximately 38
wells (18.5 net) and to purchase and reprocess 3-D seismic surveys during 2004.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources." The following chart summarizes our
properties by region and focus area as of September 30, 2003 unless otherwise
noted.
THREE MONTHS
ENDED SEPTEMBER
30, 2003 AT SEPTEMBER 30, 2003
----------------- --------------------------------------
AVERAGE PRODUCTIVE 3-D NET BUDGETED DRILLING CAPITAL
DAILY NET % WELLS SEISMIC OPTIONS/ EXPENDITURES
PRODUCTION NAT. ------------- DATA LEASED ------------------------------
(MMCFE/D) GAS GROSS NET (SQ. MILES) ACRES ESTIMATED 2003 BUDGETED 2004
---------- ---- ----- ----- ----------- -------- -------------- -------------
(millions)
Onshore Gulf Coast:
Wilcox................. 1.6 94 28 8.2 1,793 18,741 $ 5.7 $ 4.9
Frio/Vicksburg......... 8.4 58 137 43.3 2,102 8,615 5.4 12.4
Southeast Texas........ 8.8 78 11 3.8 900 3,729 3.8 9.9
South Louisiana........ 2.4 58 7 1.3 1,864 2,028 3.6 10.5
East Texas............... 0.4 - 45 5.9 472 2,816 0.7 -
Rocky Mountain........... - - - - 473 27,140 - -
Barnett Shale............ - - - - - 1,409 0.6 1.2
North Sea................ - - - - 153 209,613 - 0.4
Other Areas.............. - - - - 980 - - -
---- -- --- ----- ----- ------- ----- -----
Total.................. 21.6 68 228 62.5 8,737 274,091 $19.8 $39.3
==== == === ===== ===== ======= ===== =====
Core Project Area--The Onshore Gulf Coast Region
The onshore Gulf Coast region is a prolific proven hydrocarbon trend with
complex structural and stratigraphic targets that are optimally explored through
the use of 3-D seismic data. We believe our approximately 6,650 square miles of
data located in key producing onshore Gulf Coast trends is comparable to the
volume of data some major oil and gas companies hold for this area. Of this
volume, approximately 2,870 square miles of 3-D seismic data was acquired or
reprocessed in the last 18 months. Our exploration staff, with an average of
over 20 years experience, analyzes the data seeking to provide multiple
opportunities which we prioritize and add to our onshore Gulf Coast exploration
prospect portfolio.
Wilcox Trend
We have licenses for approximately 1,800 square miles of 3-D seismic data and
18,741 acres of leasehold in the Wilcox trend in Texas. From January 1, 2000
through December 31, 2003, we drilled and completed 32 wells (9.8 net) on 40
attempts in this area. We invested $4.3 million to drill and complete seven
wells (1.9 net) in the Texas Wilcox area in 2003 and expect to devote
approximately $8.0 million to drill seven wells (3.9 net) in this area in 2004.
Currently, we have identified over 30 exploratory drilling locations, with an
additional 22 potential extension opportunities, in the Wilcox trend over which
we have licenses for 3-D seismic data and leased acreage. Approximately 18 of
the 30 exploratory locations we have identified are relatively lower risk and
generally shallower with the remainder being relatively higher risk and deeper
with greater upside potential.
Greater Cabeza Creek. Since January 1, 2000, our exploration efforts in the
Wilcox area largely have been focused in the greater Cabeza Creek area centered
in Goliad, Lavaca and Dewitt Counties, where we have licenses for over 950
square miles of 3-D seismic data and 5,700 net acres of leasehold. From January
1, 2000 through December 31, 2003, we have drilled 14 wells (7.1 net) with an
86% success rate in this area. Our most notable discovery was the Riverdale
Field in 2001, where we have 68.8% working interest. The Riverdale Field was
delineated with two extension wells. The greater Cabeza Creek area continues to
be a primary focus area in the middle and lower Wilcox intervals which have
relatively higher potential and
45
risk. We have a significant acreage position to either explore ourselves or sell
to third parties while retaining a promoted interest.
Texas Frio/Vicksburg Trend Area
This combined trend area sometimes overlaps but is generally closer to the Texas
Gulf Coast than the Wilcox areas discussed above. In any particular target or
prospect in this area, the Frio is the shallower formation, above the deeper
Vicksburg and still deeper Yegua formations. We have licenses for a total of
2,100 miles of 3-D seismic data and 8,615 net leasehold acres over this trend.
Since 1999, we have focused primarily in Matagorda County, the location of the
Providence Field, and in Brooks County, the location of the Encinitas Field.
Currently, we have identified over 23 exploratory drilling locations with an
additional 12 potential extension opportunities (depending on the success of our
initial drilling activities on those locations) in the Frio/ Vicksburg trend
area over which we have licenses for 3-D seismic data and leased acreage.
Approximately 15 of the 23 exploratory locations we have identified are
relatively lower risk and generally shallower with the remaining eight being
relatively higher risk and deeper with greater upside potential.
From January 1, 2000 through December 31, 2003, we have drilled and completed 38
wells (10.0 net) in 45 attempts in this trend. We invested $6.1 million to drill
and complete 16 wells (3.4 net) in the Frio/ Vicksburg trend area in 2003 and
expect to devote approximately $11.0 million to drill 12 wells (5.0 net) in this
area in 2004.
Providence Field. We have licenses for over 540 square miles of 3-D data
(including 450 square miles of newly reprocessed data delivered in 2003) in and
surrounding the Providence Field we discovered in 2001. Since the discovery well
commenced production in January 2002, five wells have been drilled and
successfully completed. Four of the wells had average production rates ranging
from 14,309 to 17,669 Mcfe per day per well during the first 90 full days of
production. The field has cumulative production as of September 30, 2003 of 10.2
Bcfe. We have working interests ranging from 35% to 45% in the leases in this
field and operate three of the six wells. We anticipate participating in two
additional extension wells (1.0 net) in the field in first quarter 2004.
Encinitas Field. This field, the site of our first 3-D seismic survey in 1995,
has 24 wells currently producing. Since 1996, we have participated in the
drilling of 24 wells (4.0 net) in this area, 22 (3.5 net) of which were
successfully completed. During 2003, we participated in the drilling of nine
wells, all of which were successfully completed. We expect to drill between four
and eight wells in 2004, with an additional six to 10 well locations to be
drilled thereafter. We will have a 27.5% working interest in those wells.
Southeast Texas Area
The Southeast Texas area contains similar objective levels found in the
Frio/Vicksburg trend area. We separate this as a focus area because of the
geographic concentration of our 3-D seismic data and because reservoirs in this
area can display seismic amplitude anomalies. Seismic amplitude anomalies can be
interpreted as an indicator of hydrocarbons, although these anomalies are not
necessarily reliable as to hydrocarbon presence or productivity. We have
acquired licenses for approximately 900 square miles of 3-D data (including 400
square miles of newly released data delivered in 2003) over our Southeast Texas
project area which is focused primarily on the Frio, Yegua, Cook Mountain and
Vicksburg formations. The project area is split into the Cedar Point and Liberty
County areas.
Currently, we have identified over 15 exploratory drilling locations with an
additional 10 potential extension locations in the Southeast Texas area over
which we have licenses for 3-D seismic data. Approximately 12 of the 15
exploratory locations we have identified are relatively lower risk and generally
shallower with the remaining three being relatively higher risk and deeper with
greater upside potential.
From January 1, 2000 to December 31, 2003, we participated in the drilling and
completion of 12 wells (4.3 net)in 17 attempts in this area. We invested $2.0
million to drill and complete four wells (1.2 net) in
46
the Southeast Texas area in 2003 and expect to devote approximately $11.1
million to drill 11 wells (4.8 net) in this area in 2004. The Liberty Project
Area and Cedar Point Project Area have proven to be successful for us, and we
expect that the Liberty Project Area will constitute a significant portion of
our drilling program for the remainder of 2003 and for 2004.
Cedar Point Area. The Cedar Point Project Area is located in Chambers County,
Texas, adjacent to Trinity Bay. The 30-square-mile 3-D survey targets the lower
Frio and Vicksburg formations. Since 1999, five of six wells drilled have been
successful. In 2003, we drilled one well that produced an average of 15,789 Mcfe
per day during the first 90 full days of production. In December 2003, we
completed an extension well that encountered approximately 41 feet of logged
pay. Our working interest in leases in this project area is approximately 28% in
the first well drilled in 2003 and 25% in the extension well.
Liberty County Area. We have identified and leased prospects ranging from the
Frio to the Cook Mountain formations within the 500 square miles of 3-D seismic
data in the Liberty Project Area which, along with 290 square miles of newly
released 3-D seismic data licensed in early 2003, now covers significant areas
of Liberty and Hardin Counties, Texas. Since January 1, 2000, we have been
successful on six of eight wells drilled, including one Yegua well, one Frio
well and five Cook Mountain wells. In 2002, we completed one well that produced
an average of 9,787 Mcfe per day during the first 90 full days of production. We
operate this well and own a 40% working interest. In 2003, we had another
drilling success in this area with a well producing an average of 13,030 Mcfe
per day during the first 90 full days of production. We operate this well and
own a 46.3% working interest.
South Louisiana Area
The South Louisiana area primarily contains objectives in the Middle and Lower
Miocene intervals. We have acquired licenses for approximately 1,850 square
miles of 3-D data (including 1,416 square miles of newly released data delivered
in 2003), and over 2,000 acres of leasehold. The 3-D seismic data sets are
concentrated in one general area including St. Mary, Terrebonne and LaFourche
Parishes.
Currently, we have identified over eight exploratory drilling locations with an
additional three potential extension locations in the South Louisiana area over
which we have licenses for 3-D seismic data. Two of the eight exploratory
locations we have identified are relatively lower risk and generally shallower
with the other six being relatively higher risk and deeper with greater upside
potential. From January 1, 2000 to December 31, 2003, we drilled and completed
seven wells (1.7 net) on 14 attempts in this area. We invested $3.2 million to
drill three wells (0.1 net) in the South Louisiana area in 2003 and expect to
devote approximately $9.3 million to drill five wells (2.5 net) in this area in
2004.
LaRose Area. During 2002, we successfully drilled and completed an offset well
to the discovery well in this area. We operate the two wells and own a 40%
working interest. The discovery well produced at an average of 15,581 Mcfe per
day during the first 90 full days of production. We plan to participate in three
to four additional wells (1.3 to 1.8 net) in the general area during 2004.
Patterson Area. In December 2003, we announced the discovery of Shadyside #1
well in this area, which logged over 77 feet of pay. We operate the well and
have an approximate 35% working interest. We believe there are two potential
extension wells in the Patterson area.
Other Areas of Interest
East Texas Area
The East Texas area encompasses multiple objectives, including the Wilcox and
Cotton Valley intervals. We are focused on the Camp Hill Field, a Wilcox steam
flood project in Anderson County, and the Tortuga Grande Prospect, a Cotton
Valley sand opportunity. We have licenses for over 470 square miles of 3-D
seismic data in the East Texas area and 2,816 net acres under leasehold.
47
We did not drill any wells in the East Texas area in the first nine months of
2003 and expect to devote approximately $0.7 million to drill one (0.5 net) well
in this region in the last three months of 2003 and in 2004.
Camp Hill Field. We own interests in eight leases totaling approximately 600
gross acres in the Camp Hill field in Anderson County, Texas. We currently
operate seven of these leases. During the year ended December 31, 2002, the
project produced an average of 58 Bbls/d of 19 API gravity oil. The wells
produce from a depth of 500 feet and utilize a tertiary steam drive as an
enhanced oil recovery process. Although efficient at maximizing oil recovery,
the steam drive process is relatively expensive to operate because natural gas
or produced crude is burned to create the steam injectant. Lifting costs during
the year ended December 31, 2002 averaged $14.99 per barrel ($2.50 per Mcfe). In
response to high fuel gas prices, steam injection was reduced in mid-2000.
Because profitability increases when natural gas prices drop relative to oil
prices, the project is a natural hedge against decreases in natural gas prices
relative to oil prices. The oil produced, although viscous, commands a higher
price (an average premium of $1.00 per Bbl during the year ended December 31,
2002) than West Texas intermediate crude due to its suitability as a lube oil
feedstock. As of December 31, 2002, we had 7.7 MMBbls of proved oil reserves in
this project, with 750 MBbls of oil reserves currently developed. We have from
time to time chosen to delay development of our proved undeveloped reserves in
the Camp Hill Field in East Texas in favor of pursuing shorter-term exploration
projects with potential higher rates of return, adding to our lease position in
this field and further evaluating additional economic enhancements for this
field's development. The proved undeveloped reserves at the Camp Hill Field
constitute 66% of our proved reserves and account for 34% of our present value
of net future revenues from proved reserves as of December 31, 2002. We
anticipate drilling additional wells and increasing steam injection to develop
the proved undeveloped reserves in this project, with the timing and amount of
expenditures dependent on the relative prices of oil and natural gas. We have an
average working interest of approximately 90% in this field and an average net
revenue interest of 74%.
Tortuga Grande Prospect. In November 2003 we finalized an agreement to operate
the re-entry of an abandoned Cotton Valley test well that calculates on logs to
have over 230 feet of sands with possible production. At the time of drilling,
the operator perforated the objective interval and tested gas but in uneconomic
volumes. This well was drilled before newer fracturing technology that can
increase flow rates was developed and when gas prices were significantly lower.
Following successful testing of this re-entry, there are over 10 potential
extension locations on our acreage that may be prospective.
Barnett Shale Trend
We began active participation in the Barnett Shale play in the Fort Worth Basin
on acreage located west of the city of Fort Worth, Texas in mid-2003. Since that
time, we have acquired leases on 2,178 net acres and have transactions pending
on additional acreage. We have participated in the drilling of four wells (1.6
net), two of which are completed and producing and two of which are awaiting
pipeline hookup. Our total capital expenditures as of November 21, 2003 on these
wells have been $0.6 million. Current net production from the two wells (1.0
net) drilled to date that are on-line is a combined 360 Mcf per day and 384 Mcfe
per day as of November 21, 2003. We have received permits for the first proposed
well for which we will act as operator, a horizontal well expected to be drilled
in the first quarter of 2004. We are continuing to expand our leasehold
acquisition in this trend. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Recent Developments--Potential
Barnett Shale Acquisition."
Rocky Mountain Region
As discussed below under "--Pinnacle Transaction," in the second quarter of
2003, we contributed to Pinnacle our interests in leases in the Clearmont,
Kirby, Arvada and Bobcat project areas and natural gas and oil reserves in the
Bobcat project in the Powder River Basin in southwestern Wyoming and Montana. We
also own direct interests in approximately 189,000 gross acres of coalbed
methane properties in the Castle Rock project area in Montana and the Oyster
Ridge project area in Wyoming that were not
48
contributed to Pinnacle, but we currently have no proved reserves of, and are no
longer receiving revenue from, coalbed methane gas other than through Pinnacle.
As of the closing of the Pinnacle transaction in June 2003, we had participated
in the acquisition and/or drilling of 75 wells (28.0 net); we had invested $0.6
million to drill and complete two wells in the Rocky Mountain region from
January 1, 2003 to that date. All of the wells encountered coal accumulations
and are in various stages of development and/or stages of production. Coalbed
methane wells typically first produce water in a process called dewatering and
then, as the water production declines, begin producing methane gas at an
increasing rate. As the wells mature, the production peaks and begins declining.
We continue to own a 26.9% interest in Pinnacle on a fully diluted basis. We are
not required to make any further capital contributions to Pinnacle.
Of the approximately 318,740 gross and 90,250 net mineral acres held by us and
Pinnacle, respectively, as of September 30, 2003, approximately 193,250 and
20,970 net mineral acres, respectively, are located in the State of Montana. The
issuance of new coalbed methane drilling permits in Montana was halted
temporarily pending the Federal Bureau of Land Management's approval of a final
record of decision on Montana's Resource Management Plan environmental impact
statement and the Montana Department of Environmental Quality's approval of a
statewide oil and gas environmental impact statement. These two program
approvals were obtained in April and August of 2003, respectively. Accordingly,
the Montana Board of Oil and Gas Conservation has begun accepting new coalbed
methane drilling permit applications. Environmental groups have initiated two
lawsuits, each challenging one of these program approvals. We believe that the
decisions by the Federal Bureau of Land Management and the State of Montana
ultimately will be upheld and new coalbed methane development will continue to
be authorized in Montana. Pinnacle holds approximately 56 grandfathered drilling
permits in Montana that were contributed by our joint venture partner RMG at the
time of Pinnacle's formation, and RMG holds approximately 56 grandfathered
drilling permits in Montana for acreage in which CCBM also has an interest.
There can be no assurance that any new permits will be obtained in a given time
period or at all.
U.K. North Sea Region
We have been awarded seven acreage blocks, consisting of one "Traditional" and
three "Promote" licenses, in the United Kingdom's 21st Round of Licensing. The
awarded blocks, to explore for natural gas and oil totaling approximately
209,000 acres, are located within mature producing areas of the Central and
Southern North Sea in water depths of 30 to 350 feet. The Promote licenses do
not have drilling commitments and have two-year terms. The Traditional license
will be canceled after four years if we or our assignee elects not to commit to
drilling a well. We believe our U.K. North Sea interest is a natural extension
to our technical analyses, portfolio and business plan. The U.K. North Sea
includes proven hydrocarbon trends with established technological expertise,
available large 3-D seismic datasets and significant exploration potential. We
plan to promote our interests to other parties experienced in drilling and
operating in this region. Geological and geophysical costs will be incurred in
an attempt to maximize the value of our retained interest. Our estimated project
commitments from commencement through mid-2005 are $0.9 million, comprised of
$0.2 million for seismic data, $0.2 million for leasehold costs and $0.2 million
for data processing in 2003 and $0.3 million for seismic data processing in
2004.
WORKING INTEREST AND DRILLING IN PROJECT AREAS
The actual working interest we ultimately will own in a well will vary based
upon several factors, including the depth, cost and risk of each well relative
to our strategic goals, activity levels and budget availability. From time to
time, some fraction of these wells may be sold to industry partners either on a
prospect-by-prospect basis or on a program basis. In addition, we may also
contribute acreage to larger drilling units, thereby reducing prospect working
interest. We have, in the past, retained less than 100% working interest in our
drilling prospects. References to our interests are not intended to imply that
we have or will maintain any particular level of working interest.
49
Our success will be materially dependent upon the success of our exploratory
drilling program. In addition, although we currently are pursuing prospects
within the project areas described above, there can be no assurance that these
prospects will be drilled at all or within the expected time frame. See "Risk
Factors--Natural gas and oil drilling is a speculative activity and involves
numerous risks and substantial and uncertain costs that could adversely affect
us" and "Risk Factors--We may not adhere to our proposed drilling schedule."
NATURAL GAS AND OIL RESERVES
The following table sets forth our estimated net proved natural gas and oil
reserves and the PV-10 Value of such reserves as of December 31, 2002. The
reserve data and the present value as of December 31, 2002 were prepared by
Ryder Scott Company and Fairchild and Wells, Inc., Independent Petroleum
Engineers. For further information concerning Ryder Scott's and Fairchild's
estimate of our proved reserves at December 31, 2002, see the reserve reports
included as Appendix A to this prospectus. The PV-10 Value was prepared using
constant prices as of the calculation date, discounted at 10% per annum on a
pretax basis, and is not intended to represent the current market value of the
estimated natural gas and oil reserves we own. For further information
concerning the present value of future net revenue from these proved reserves,
see Note 13 of the notes to our consolidated financial statements for the year
ended December 31, 2002, which are included in this prospectus.
PROVED RESERVES
---------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
Natural gas (MMcf)........................................ 12,826 96 12,922
Oil and condensate (MBbls)................................ 1,393 6,988 8,381
Natural gas equivalent (MMcfe).......................... 21,184 42,024 63,208
PV-10 Value (in thousands)(1)............................. $55,235 $28,379 $83,614
---------------------------
(1) The PV-10 Value as of December 31, 2002 is pretax and was determined by
using the December 31, 2002 sales prices, which averaged $29.16 per Bbl of
oil, $4.70 per Mcf of natural gas.
No estimates of proved reserves comparable to those included herein have been
included in reports to any federal agency other than the SEC.
For a discussion of the uncertainties inherent in estimating natural gas and oil
reserves and their estimated values, see "Risk Factors--Our reserve data and
estimated discounted future net cash flows are estimates based on assumptions
that may be inaccurate and on existing economic and operating conditions that
may differ from future conditions."
50
VOLUMES, PRICES AND NATURAL GAS & OIL OPERATING EXPENSE
The following table sets forth certain information regarding the production
volumes of, average sales prices received for and average production costs
associated with our sales of natural gas and oil for the periods indicated. The
table includes the cash impact of hedging activities and the effect of certain
hedge positions with an affiliate of Enron Corp. reclassified as derivatives
during November 2001.
YEAR ENDED DECEMBER 31,
------------------------
2000 2001 2002
------ ------ ------
PRODUCTION VOLUMES:
Natural gas (MMcf)........................................ 5,460 4,432 4,801
Oil (MBbls)............................................... 198 160 401
Natural gas equivalent (MMcfe)......................... 6,651 5,390 7,207
AVERAGE SALES PRICES:(1)
Natural gas (per Mcf)..................................... 3.90 5.04 3.50
Oil (per Bbl)............................................. $27.81 $24.28 $24.94
NATURAL GAS AND OIL OPERATING EXPENSES (PER MCFE):(2)
Operating expenses in all areas excluding Camp Hill....... $ 0.59 $ 0.43 $ 0.44
Operating expenses in Camp Hill........................... 3.08 2.14 2.50
Total operating expenses............................... $ 0.74 $ 0.77 $ 0.68
---------------------------
(1) Includes impact of hedging activities.
(2) Includes direct operating costs (labor, repairs and maintenance, materials
and supplies), workover costs and the administrative costs of production
offices, insurance and property and severance taxes.
DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES
The following table sets forth certain information regarding the gross costs
incurred in the purchase of proved and unproved properties and in development
and exploration activities.
YEAR ENDED DECEMBER 31,
-----------------------------
2000 2001 2002
------- ------- -------
(in thousands)
Acquisition costs:
Unproved properties(1)................................... $ 6,641 $12,607 $ 6,402
Proved properties........................................ 337 800 660
Exploration................................................ 7,843 18,356 14,194
Development................................................ 1,361 3,065 2,351
------- ------- -------
Total costs incurred(2)............................... $16,182 $34,828 $23,607
======= ======= =======
---------------------------
(1) Includes unproved property costs of $9.0 million in 2001 and $2.2 million
in 2002 in the coalbed methane properties we contributed as a minority
interest to Pinnacle in June 2003.
(2) Excludes capitalized interest on unproved properties of $3.6 million, $3.2
million and $3.1 million for the years ended December 31, 2000, 2001 and
2002, respectively.
51
DRILLING ACTIVITY
The following table sets forth our drilling activity for the years ended
December 31, 2000, 2001 and 2002. In the table, "gross" refers to the total
wells in which we have a working interest and "net" refers to gross wells
multiplied by our working interest therein. Our drilling activity from January
1, 1996 to December 31, 2002 has resulted in a commercial success rate of
approximately 66%.
YEAR ENDED DECEMBER 31,
--------------------------------------------
2000 2001 2002
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Exploratory wells:
Productive................................... 19 4.7 18 5.9 16 4.6
Nonproductive................................ 15 3.4 5 1.4 3 1.1
-- --- -- --- -- ---
Total..................................... 34 8.1 23 7.3 19 6.7
== === == === == ===
Development wells:
Productive................................... 5 1.9 2 0.3 1 0.4
Nonproductive................................ - - - - - -
-- --- -- --- -- ---
Total..................................... 5 1.9 2 0.3 1 0.4
== === == === == ===
The above table excludes 75 gross (28 net) wells drilled or acquired by CCBM
through 2002. At December 31, 2002, we have ownership in 11 gross (2.7 net)
wells with dual completion in single bore holes.
PRODUCTIVE WELLS
The following table sets forth the number of productive natural gas and oil
wells in which we owned an interest as of December 31, 2002.
COMPANY
OPERATED OTHER TOTAL
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Oil........................................... 49 46 18 6 67 52
Natural Gas................................... 36 19 59 15 95 34
-- -- -- -- --- --
Total......................................... 85 65 77 21 162 86
== == == == === ==
ACREAGE DATA
The following table sets forth certain information regarding our developed and
undeveloped lease acreage as of September 30, 2003. Developed acres refers to
acreage within producing units and undeveloped acres refers to acreage that has
not been placed in producing units. Leases covering substantially all of the
undeveloped acreage in the following table will expire within the next three
years. In general, our leases will continue past their primary terms if natural
gas or oil in commercial quantities is being produced from a well on such
leases.
DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL
------------------ -------------------- ------------------
GROSS NET GROSS NET GROSS NET
------- ------- -------- -------- ------- -------
Onshore Gulf Coast........... 40,449 14,767 44,182 18,675 84,631 33,442
East Texas................... 360 220 687 342 1,047 562
Rocky Mountain............... -- -- 145,376 16,710 145,376 16,710
U.K. North Sea............... -- -- 209,613 209,613 209,613 209,613
------ ------ ------- ------- ------- -------
Total...................... 40,809 14,987 399,858 245,340 440,667 260,327
====== ====== ======= ======= ======= =======
The table does not include 7,422 gross acres (3,334 net) that we had a right to
acquire in Texas pursuant to various seismic options or agreements at September
30, 2003. Under the terms of our option
52
agreements, we typically have the right for a period of one year, subject to
extensions, to exercise our option to lease the acreage at predetermined terms.
Our lease agreements generally terminate if producing wells have not been
drilled on the acreage within a period of three years. Further, the table does
not include 28,511 gross and 10,403 net acres in Wyoming that we have the right
to earn pursuant to specified drilling obligations and other predetermined
terms.
MARKETING
Our production is marketed to third parties consistent with industry practices.
Typically, oil is sold at the wellhead at field-posted prices plus a bonus and
natural gas is sold under contract at a negotiated price based upon factors
normally considered in the industry, such as distance from the well to the
pipeline, well pressure, estimated reserves, quality of natural gas and
prevailing supply and demand conditions.
Our marketing objective is to receive the highest possible wellhead price for
our product. We are aided by the presence of multiple outlets near our
production in the Texas and Louisiana onshore Gulf Coast. We take an active role
in determining the available pipeline alternatives for each property based on
historical pricing, capacity, pressure, market relationships, seasonal variances
and long-term viability.
There are a variety of factors that affect the market for natural gas and oil,
including:
- the extent of domestic production and imports of natural gas and oil;
- the proximity and capacity of natural gas pipelines and other
transportation facilities;
- demand for natural gas and oil;
- the marketing of competitive fuels; and
- the effects of state and federal regulations on natural gas and oil
production and sales.
See "Risk Factors--Natural gas and oil prices are highly volatile, and lower
prices will negatively affect our financial results," "Risk Factors--We are
subject to various governmental regulations and environmental risks" and "Risk
Factors--The marketability of our natural gas production depends on facilities
that we typically do not own or control, which could result in a curtailment of
production and revenues."
We from time to time market our own production where feasible with a combination
of market-sensitive pricing and forward-fixed pricing. We utilize forward
pricing to take advantage of anomalies in the futures market and to hedge a
portion of our production deliverability at prices exceeding forecast. All of
these hedging transactions provide for financial rather than physical
settlement. For a discussion of these matters, our hedging policy and recent
hedging positions, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Critical Accounting Policies and
Estimates--Derivative Instruments and Hedging Activities" and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Qualitative and Quantitative Disclosures About Market
Risk--Derivative Instruments and Hedging Activities."
COMPETITION AND TECHNOLOGICAL CHANGES
We encounter competition from other natural gas and oil companies in all areas
of our operations, including the acquisition of exploratory prospects and proven
properties. Many of our competitors are large, well-established companies that
have been engaged in the natural gas and oil business for much longer than we
have and possess substantially larger operating staffs and greater capital
resources than we do. We may not be able to conduct our operations, evaluate and
select suitable properties and consummate transactions successfully in this
highly competitive environment. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations," "Risk Factors--We face strong
competition from larger natural gas and oil companies" and "Risk Factors--We
have substantial capital requirements that, if not met, may hinder operations."
The natural gas and oil industry is characterized by rapid and significant
technological advancements and introductions of new products and services using
new technologies. If one or more of the technologies we
53
use now or in the future were to become obsolete or if we are unable to use the
most advanced commercially available technology, our business, financial
condition and results of operations could be materially adversely affected. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Risk Factors--We may not be able to keep pace with technological
developments in our industry," "Risk Factors--We may experience difficulty in
achieving and managing future growth" and "Risk Factors--We have substantial
capital requirements that, if not met, may hinder operations."
REGULATION
Natural gas and oil operations are subject to various federal, state and local
environmental regulations that may change from time to time, including
regulations governing natural gas and oil production, federal and state
regulations governing environmental quality and pollution control and state
limits on allowable rates of production by well or proration unit. These
regulations may affect the amount of natural gas and oil available for sale, the
availability of adequate pipeline and other regulated transportation and
processing facilities and the marketing of competitive fuels. For example, a
productive natural gas well may be "shut-in" because of an oversupply of natural
gas or lack of an available natural gas pipeline in the areas in which we may
conduct operations. State and federal regulations generally are intended to
prevent waste of natural gas and oil, protect rights to produce natural gas and
oil between owners in a common reservoir, control the amount of natural gas and
oil produced by assigning allowable rates of production and control
contamination of the environment. Pipelines are subject to the jurisdiction of
various federal, state and local agencies. We are also subject to changing and
extensive tax laws, the effects of which cannot be predicted.
The following discussion summarizes the regulation of the United States oil and
gas industry. We believe we are in substantial compliance with the various
statutes, rules, regulations and governmental orders to which our operations may
be subject, although we cannot assure you that this is or will remain the case.
Moreover, those statutes, rules, regulations and government orders may be
changed or reinterpreted from time to time in response to economic or political
conditions, and any such changes or reinterpretations could materially adversely
affect our results of operations and financial condition. The following
discussion is not intended to constitute a complete discussion of the various
statutes, rules, regulations and governmental orders to which our operations may
be subject.
Regulation of Natural Gas and Oil Exploration and Production
Our operations are subject to various types of regulation at the federal, state
and local levels that:
- require permits for the drilling of wells;
- mandate that we maintain bonding requirements in order to drill or operate
wells; and
- regulate the location of wells, the method of drilling and casing wells,
the surface use and restoration of properties upon which wells are drilled,
the plugging and abandoning of wells and the disposal of fluids used in
connection with operations.
Our operations are also subject to various conservation laws and regulations.
These regulations govern the size of drilling and spacing units or proration
units, the density of wells that may be drilled in natural gas and oil
properties and the unitization or pooling of natural gas and oil properties. In
this regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units and therefore more difficult to develop a
project if the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from natural gas and oil
wells, generally prohibit the venting or flaring of natural gas and impose
specified requirements regarding the ratability of production. The effect of
these regulations may limit the amount of natural gas and oil we can produce
from our wells and may limit the number of wells or the locations at which we
can drill. The regulatory burden on the natural gas and oil industry increases
our costs of doing business and, consequently, affects our profitability.
Because these laws and regulations
54
are frequently expanded, amended and reinterpreted, we are unable to predict the
future cost or impact of complying with such regulations.
Regulation of Sales and Transportation of Natural Gas
Federal legislation and regulatory controls have historically affected the price
of natural gas we produce and the manner in which our production is transported
and marketed. Under the Natural Gas Act of 1938 (NGA), the Federal Energy
Regulatory Commission (FERC) regulates the interstate transportation and the
sale in interstate commerce for resale of natural gas. Effective January 1,
1993, the Natural Gas Wellhead Decontrol Act (the Decontrol Act) deregulated
natural gas prices for all "first sales" of natural gas, including all of our
sales of our own production. As a result, all of our domestically produced
natural gas may now be sold at market prices, subject to the terms of any
private contracts that may be in effect. The FERC's jurisdiction over interstate
natural gas transportation, however, was not affected by the Decontrol Act.
Under the NGA, facilities used in the production or gathering of natural gas are
exempt from the FERC's jurisdiction. We own certain natural gas pipelines that
we believe satisfy the FERC's criteria for establishing that these are all
gathering facilities not subject to FERC jurisdiction under the NGA. State
regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, nondiscriminatory take requirements
but does not generally entail rate regulation.
Although we therefore do not own or operate any pipelines or facilities that are
directly regulated by the FERC, its regulations of third-party pipelines and
facilities could indirectly affect our ability to market our production.
Beginning in the 1980s the FERC initiated a series of major restructuring orders
that required pipelines, among other things, to perform open access
transportation, "unbundle" their sales and transportation functions, and allow
shippers to release their pipeline capacity to other shippers. As a result of
these changes, sellers and buyers of natural gas have gained direct access to
the particular pipeline services they need and are better able to conduct
business with a larger number of counterparties. We believe these changes
generally have improved our access to markets while, at the same time,
substantially increasing competition in the natural gas marketplace. It remains
to be seen, however, what effect the FERC's other activities will have on access
to markets, the fostering of competition and the cost of doing business. We
cannot predict what new or different regulations the FERC and other regulatory
agencies may adopt, or what effect subsequent regulations may have on our
activities.
In the past, Congress has been very active in the area of natural gas
regulation. However, the more recent trend has been in favor of deregulation or
"lighter handed" regulation and the promotion of competition in the gas
industry. There regularly are other legislative proposals pending in the federal
and state legislatures which, if enacted, would significantly affect the
petroleum industry. At the present time, it is impossible to predict what
proposals, if any, might actually be enacted by Congress or the various state
legislatures and what effect, if any, such proposals might have on us.
Similarly, and despite the trend toward federal deregulation of the natural gas
industry, whether or to what extent that trend will continue, or what the
ultimate effect will be on our sales of gas, cannot be predicted.
Oil Price Controls and Transportation Rates
Our sales of 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.
Much of that transportation is through interstate common carrier pipelines.
Effective as of January 1, 1995, the FERC implemented regulations generally
grandfathering all previously approved interstate transportation rates and
establishing an indexing system for those rates by which adjustments are made
annually based on the rate of inflation, subject to specified conditions and
limitations. These regulations may tend to increase the cost of transporting
natural gas and oil liquids by interstate pipeline, although the annual
adjustments may result in decreased rates in a given year. These regulations
generally have been approved on judicial review. Every five years, the FERC must
examine the relationship between the annual change in the applicable index and
the actual cost changes experienced in the oil pipeline industry. The first such
review was completed in 2000 and on December 14, 2000, the
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FERC reaffirmed the current index. Following a successful court challenge of
these orders by an association of oil pipelines, on February 24, 2003 the FERC
increased the index slightly for the current five-year period, effective July
2001. We are not able at this time to predict the effects, if any, of these
regulations on the transportation costs associated with oil production from our
oil-producing operations.
Environmental Regulations
Our operations are subject to numerous federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on specified lands within wilderness,
wetlands and other protected areas, require remedial measures to mitigate
pollution from former operations, such as pit closure and plugging abandoned
wells, and impose substantial liabilities for pollution resulting from
production and drilling operations. Public interest in the protection of the
environment has increased dramatically in recent years. The trend of applying
more expansive and stricter environmental legislation and regulations to the
natural gas and oil industry could continue, resulting in increased costs of
doing business and consequently affecting our profitability. To the extent laws
are enacted or other governmental action is taken that restricts drilling or
imposes more stringent and costly waste handling, disposal and cleanup
requirements, our business and prospects could be adversely affected.
We generate wastes that may be subject to the federal Resource Conservation and
Recovery Act (RCRA) and comparable state statutes. The U.S. Environmental
Protection Agency (EPA) and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes. Furthermore,
certain wastes generated by our natural gas and oil operations that are
currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes" and therefore become subject to more rigorous
and costly operating and disposal requirements.
We currently own or lease numerous properties that for many years have been used
for the exploration and production of natural gas and oil. Although we believe
that we have implemented appropriate operating and waste disposal practices,
prior owners and operators of these properties may not have used similar
practices, and hydrocarbons or other wastes may have been disposed of or
released on or under the properties we own or lease or on or under locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under our control. These
properties and the wastes disposed thereon may be subject to the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA), RCRA and
analogous state laws as well as state laws governing the management of natural
gas and oil wastes. Under these laws, we could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination. See "Risk Factors--We are subject to various governmental
regulations and environmental risks."
CERCLA, also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
specified classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These classes of
persons include the owner or operator of the disposal site or sites where the
release occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site. Persons who are or were responsible for
releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment.
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Our operations may be subject to the Clean Air Act (CAA) and comparable state
and local requirements. In 1990 Congress adopted amendments to the CAA
containing provisions that have resulted in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. The EPA and states have developed and continue to develop
regulations to implement these requirements. We may be required to incur certain
capital expenditures in the next several years for air pollution control
equipment in connection with maintaining or obtaining operating permits and
approvals addressing other air emission-related issues. However, we do not
believe our operations will be materially adversely affected by any such
requirements.
Federal regulations require certain owners or operators of facilities that store
or otherwise handle oil, such as us, to prepare and implement spill prevention,
control, countermeasure (SPCC) and response plans relating to the possible
discharge of oil into surface waters. We have acknowledged the need for SPCC
plans at certain of our properties and have developed and implemented these
plans. The Oil Pollution Act of 1990 (OPA) contains numerous requirements
relating to the prevention of and response to oil spills into waters of the
United States. The OPA subjects owners of facilities to strict joint and several
liability for all containment and cleanup costs and certain other damages
arising from a spill, including, but not limited to, the costs of responding to
a release of oil to surface waters. The OPA also requires owners and operators
of offshore facilities that could be the source of an oil spill into federal or
state waters, including wetlands, to post a bond, letter of credit or other form
of financial assurance in amounts ranging from $10 million in specified state
waters to $35 million in federal outer continental shelf waters to cover costs
that could be incurred by governmental authorities in responding to an oil
spill. These financial assurances may be increased by as much as $150 million if
a formal risk assessment indicates that the increase is warranted. Noncompliance
with OPA may result in varying civil and criminal penalties and liabilities. Our
operations are also subject to the federal Clean Water Act (CWA) and analogous
state laws. In accordance with the CWA, the State of Louisiana issued
regulations prohibiting discharges of produced water in state coastal waters
effective July 1, 1997. Pursuant to other requirements of the CWA, the EPA has
adopted regulations concerning discharges of storm water runoff. This program
requires covered facilities to obtain individual permits, participate in a group
permit or seek coverage under an EPA general permit. While certain of our
properties may require permits for discharges of storm water runoff, we believe
that we will be able to obtain, or be included under, such permits, where
necessary, and make minor modifications to existing facilities and operations
that would not have a material effect on us. Like OPA, the CWA and analogous
state laws relating to the control of water pollution provide varying civil and
criminal penalties and liabilities for releases of petroleum or its derivatives
into surface waters or into the ground.
We also are subject to a variety of federal, state and local permitting and
registration requirements relating to protection of the environment. We believe
we are in substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse effect on us.
As further described in "--Significant Areas--Other Areas of Interest--Rocky
Mountain Region," the issuance of new coalbed methane drilling permits and the
continued viability of existing permits in Montana have been challenged in
lawsuits filed in state and federal court.
OPERATING HAZARDS AND INSURANCE
The natural gas and oil business involves a variety of operating hazards and
risks that could result in substantial losses to us from, among other things,
injury or loss of life, severe damage to or destruction of property, natural
resources and equipment, pollution or other environmental damage, cleanup
responsibilities, regulatory investigation and penalties and suspension of
operations. See "Risk Factors--We are subject to various operating and other
casualty risks that could result in liability exposure or the loss of production
and revenues."
In addition, we may be liable for environmental damages caused by previous
owners of property we purchase and lease. As a result, we may incur substantial
liabilities to third parties or governmental
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entities, the payment of which could reduce or eliminate the funds available for
exploration, development or acquisitions or result in the loss of our
properties. See "Risk Factors--We are subject to various governmental
regulations and environmental risks."
In accordance with customary industry practices, we maintain insurance against
some, but not all, potential losses. We do not carry business interruption
insurance or protect against loss of revenues. We cannot assure you that any
insurance we obtain will be adequate to cover any losses or liabilities. We
cannot predict the continued availability of insurance or the availability of
insurance at premium levels that justify its purchase. We may elect to
self-insure if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks
generally are not fully insurable. The occurrence of an event not fully covered
by insurance could have a material adverse effect on our financial condition and
results of operations. See "Risk Factors--We may not have enough insurance to
cover all of the risks we face."
We participate in a substantial percentage of our wells on a nonoperated basis,
and may be accordingly limited in our ability to control the risks associated
with natural gas and oil operations. See "Risk Factors--We cannot control the
activities on properties we do not operate and are unable to ensure their proper
operation and profitability."
TITLE TO PROPERTIES; ACQUISITION RISKS
We believe we have satisfactory title to all of our producing properties in
accordance with standards generally accepted in the natural gas and oil
industry. 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 affect the value
of these properties. As is customary in the industry in the case of undeveloped
properties, we make little investigation of record title at the time of
acquisition (other than a preliminary review of local records). Investigations,
including a title opinion of local counsel, are generally made before
commencement of drilling operations. Our revolving credit facility is secured by
substantially all of our natural gas and oil properties.
In acquiring producing properties, we assess the recoverable reserves, future
natural gas and oil prices, operating costs, potential liabilities and other
factors relating to the properties. Our assessments are necessarily inexact and
their accuracy is inherently uncertain. Our review of a subject property in
connection with our acquisition assessment will not reveal all existing or
potential problems or permit us to become sufficiently familiar with the
property to assess fully its deficiencies and capabilities. We may not inspect
every well, and we may not be able to observe structural and environmental
problems even when we do inspect a well. If problems are identified, the seller
may be unwilling or unable to provide effective contractual protection against
all or part of those problems. Any acquisition of property interests may not be
economically successful, and unsuccessful acquisitions may have a material
adverse effect on our financial condition and future results of operations See
"Risk Factors -- Our future acquisitions may yield revenues or production that
varies significantly from our projections."
EMPLOYEES
At September 30, 2003, we had 37 full-time employees, including six
geoscientists and six engineers. We believe that our relationships with our
employees are good.
In order to optimize prospect generation and development, we utilize the
services of independent consultants and contractors to perform various
professional services, particularly in the areas of 3-D seismic data mapping,
acquisition of leases and lease options, construction, design, well site
surveillance, permitting and environmental assessment. Independent contractors
generally provide field and on-site production operation services, such as
pumping, maintenance, dispatching, inspection and testings. We believe that this
use of third-party service providers has enhanced our ability to contain general
and administrative expenses.
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We depend to a large extent on the services of certain key management personnel,
the loss of, any of which could have a material adverse effect on our
operations. We do not maintain key-man life insurance with respect to any of our
employees. See "Risk Factors--Our business may suffer if we lose key personnel."
PINNACLE TRANSACTION
Formation and Operations
During the second quarter of 2003, we and Rocky Mountain Gas, Inc. (RMG) each
contributed our interests in certain natural gas and oil leases in Wyoming and
Montana in areas prospective for coalbed methane to a newly formed joint
venture, Pinnacle Gas Resources, Inc. In exchange for the contribution of these
assets, we received 37.5% of the common stock of Pinnacle and options to
purchase additional Pinnacle common stock. We retained our interests in
approximately 189,000 gross acres in the Castle Rock project area in Montana and
the Oyster Ridge project area in Wyoming. We no longer have a drilling
obligation in connection with the oil and natural gas leases contributed to
Pinnacle.
Simultaneously with the contribution of these assets, affiliates and related
parties of CSFB Private Equity (CSFB) contributed approximately $17.6 million of
cash to Pinnacle in return for redeemable preferred stock of Pinnacle, 25% of
Pinnacle's common stock as of the closing date and warrants to purchase Pinnacle
common stock. The CSFB parties also agreed to contribute additional cash, under
specified circumstances, of up to approximately $11.8 million to Pinnacle to
fund future drilling, development and acquisitions. The CSFB parties currently
have greater than 50% of the voting power of the Pinnacle capital stock through
their ownership of Pinnacle common and preferred stock.
Currently, on a fully diluted basis, assuming that all parties exercised their
Pinnacle warrants and options, the CSFB parties would have an ownership interest
in Pinnacle of 46.2%, and we and RMG each would own 26.9%. On a fully diluted
basis, assuming the additional $11.8 million of cash were contributed by the
CSFB parties and all warrants and options were exercised by all parties, the
CSFB parties would own 54.6% of Pinnacle and RMG and we each would own 22.7% of
Pinnacle.
Immediately following its formation, Pinnacle acquired an approximate 50%
working interest in existing leases and approximately 36,529 gross acres
prospective for coalbed methane development in the Powder River Basin of Wyoming
from an unaffiliated party for $6.2 million. The leases include 95 producing
coalbed methane wells currently in the early stages of dewatering, a process
that occurs prior to achieving stabilized production. At the time of the
Pinnacle transaction, these wells were producing at a combined gross rate of
approximately 2.5 MMcfd, or an estimated 1 MMcfd net to Pinnacle. Pinnacle also
agreed to fund up to $14.9 million of future drilling and development costs on
these properties on behalf of the third party prior to December 31, 2005. The
drilling and development work will be done under the terms of an earn-in joint
venture agreement between Pinnacle and Gastar. As of September 30, 2003,
Pinnacle owned interests in approximately 131,000 gross acres in the Powder
River Basin.
Certain Relationships and Agreements
Our Chairman, Steven A. Webster, is also Chairman of Global Energy Partners,
Ltd., an affiliate of CSFB Private Equity and could be deemed a related party
with respect to the Pinnacle transaction.
We provide specified accounting, treasury, tax, insurance and financial
reporting functions to Pinnacle through the end of 2003 under a transition
services agreement for a monthly fee equal to our actual cost to provide these
services. After December 31, 2003, the agreement will automatically renew on a
quarterly basis unless one of the parties gives notice of its intent to
terminate the agreement.
We have mutually agreed with RMG, its majority shareholder and the CSFB parties
to provide Pinnacle the right until June 23, 2008 to acquire at cost any
interest in natural gas and oil leases or mineral interests in the Powder River
Basin in Wyoming and Montana, but excluding most of Powder River County,
Montana, that such parties may have acquired in the covered area, subject to
specified exceptions.
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We, the CSFB parties, RMG, RMG's parent company, Peter G. Schoonmaker, Gary W.
Uhland and Pinnacle also entered into a securityholders' agreement providing for
an initial eight person board of directors, which initially includes four
directors nominated by the CSFB parties and two nominated by each of us and RMG,
subject to change as their respective ownership percentages change. Each party
to the securityholders' agreement also granted to the others a right of first
offer and co-sale rights. If the CSFB parties propose to sell all of their
Pinnacle shares to a third party, under specified circumstances the CSFB parties
may require the other securityholders to include all of their Pinnacle shares in
that sale. In event of such a sale, the Pinnacle preferred stock will have a
preferred right to receive an amount equal to its liquidation value (as defined
below) per share plus accrued and unpaid dividends prior to distributions to the
holders of shares of Pinnacle common stock and common stock equivalents.
Pinnacle also granted the securityholders pre-emptive rights to purchase
additional securities in order to maintain their proportionate ownership of
Pinnacle. The securityholders' agreement also provides generally for multiple
demand registration rights with respect to the Pinnacle common stock in favor of
the CSFB parties and certain piggyback registration rights for us and RMG
subject to the satisfaction of specified conditions.
Pinnacle Preferred Stock and Warrants Held by the CSFB Parties
The Pinnacle redeemable preferred stock issued to the CSFB parties generally has
the right to vote together with the Pinnacle common stock and has a class vote
on specified matters, including specified extraordinary transactions. In the
event of any dissolution, liquidation, or winding up by Pinnacle, the holder of
each share of Pinnacle preferred stock will be entitled to be paid a liquidation
value of $100 per share out of the assets of Pinnacle available for distribution
to its shareholders.
Dividends on the Pinnacle preferred stock are payable either in cash at a rate
of 10.5% per annum through June 23, 2011 and 12.5% thereafter or, at Pinnacle's
option, by payment in kind of additional shares of the Pinnacle preferred stock.
For each additional share of Pinnacle preferred stock distributed to a holder as
an in-kind dividend, Pinnacle will also deliver to that holder one Pinnacle
warrant, which will have an exercise price equal to the exercise price of the
outstanding Pinnacle warrants on the date of such distribution. On or after July
1, 2005, Pinnacle may redeem all or any portion of the Pinnacle preferred stock,
provided that if any Pinnacle warrants are still outstanding, Pinnacle may
redeem all but a single share; if the redemption occurs at any time before July
1, 2009, the redemption price will be at a premium to the liquidation value of
the shares.
Pinnacle is required to redeem its preferred stock upon:
- specified changes of control, at a price per share equal to 101% of its
liquidation value; or
- specified events of default, at a price per share equal to 110% of the
liquidation value prior to June 30, 2005 and, thereafter, equal to an
optional redemption price that decreases over time.
The Pinnacle warrants entitle the holders to purchase up to 130,000 shares of
Pinnacle common stock at a price of $100 per share and are exercisable at any
time until June 30, 2013. The Pinnacle warrants can be exercised in cash, by
tender of the Pinnacle preferred stock and on a cashless net exercise basis. The
Pinnacle warrants are subject to adjustments, including, in specified cases, an
adjustment of the exercise price to equal the lowest price at which Pinnacle
common stock is sold if such shares are sold below the then-current exercise
price.
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MANAGEMENT
The following table sets forth certain information with respect to our executive
officers and directors.
NAME AGE POSITION
---- --- --------
S.P. Johnson IV.......................... 47 President, Chief Executive Officer and
Director
Paul F. Boling........................... 49 Chief Financial Officer, Vice President,
Secretary and Treasurer
Jeremy T. Greene......................... 43 Vice President of Exploration
Kendall A. Trahan........................ 53 Vice President of Land
J. Bradley Fisher........................ 42 Vice President of Operations
Steven A. Webster........................ 52 Chairman
Christopher C. Behrens................... 42 Director
Douglas A. P. Hamilton................... 57 Director
Paul B. Loyd, Jr. ....................... 57 Director
Bryan R. Martin.......................... 36 Director
F. Gardner Parker........................ 61 Director
Frank A. Wojtek.......................... 48 Director
Set forth below is a description of the backgrounds of each of our executive
officers and directors.
S.P. Johnson IV has served as our President and Chief Executive Officer and a
director since December 1993. Prior to that, he worked for Shell Oil Company for
15 years. His managerial positions included Operations Superintendent, Manager
of Planning and Finance and Manager of Development Engineering. Mr. Johnson is
also a director of Basic Energy Services, Inc. (a well servicing contractor).
Mr. Johnson is a Registered Petroleum Engineer and has a B.S. in Mechanical
Engineering from the University of Colorado.
Paul F. Boling became our Chief Financial Officer, Vice President, Secretary and
Treasurer in August 2003. From 2001 to 2003, Mr. Boling was the Global
Controller for Resolution Performance Products, LLC, an international epoxy
resins manufacturer. From 1990 to 2001, Mr. Boling served in a number of
financial and managerial positions with Cabot Oil & Gas Corporation, serving
most recently as Vice President, Finance. Mr. Boling is a CPA and holds a B.B.A.
from Baylor University.
Jeremy T. Greene was elected Vice President of Exploration in August 2002. From
September 2000 to August 2002 he was the Deepwater Gulf of Mexico Division
Specialist for EOG Resources, Inc. Mr. Greene was the Eastern Area Deepwater
Exploration Manager for Vastar Resources, Inc. from August 1997 to September
2000. He spent the previous 14 years with Vastar Resources, Inc., ARCO
International and ARCO, where he held various technical and managerial
positions, including Director of Joint Ventures Onshore Gulf Coast and Director
of Geophysical Interpretation Research. Mr. Greene received his B.S. in
Geophysical Engineering from the Colorado School of Mines and his M.S. in
Geophysics from The University of Texas at Austin.
Kendall A. Trahan has been head of our land activities since joining us in March
1997 and was elected Vice President of Land in June 1997. From 1994 to February
1997, he served as a Director of Joint Ventures Onshore Gulf Coast for Vastar
Resources, Inc. From 1982 to 1994, he worked as an Area Landman and then a
Division Landman and Director of Business Development for Arco Oil & Gas
Company. Prior to that, Mr. Trahan served as a Staff Landman for Amerada Hess
Corporation and as an independent Landman. He holds a B.S. degree from the
University of Southwestern Louisiana.
J. Bradley Fisher has served as Vice President of Operations since July 2000 and
General Manager of Operations from April 1998 to June 2000. Prior to joining us,
Mr. Fisher was the Vice President of Engineering and Operations for Tri-Union
Development Corp. from August 1997 to April 1998. He spent the prior 14 years
with Cody Energy and its predecessor Ultramar Oil & Gas Limited where he held
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various managerial and technical positions, last serving as Senior Vice
President of Engineering and Operations. Mr. Fisher hold a B.S. degree in
Petroleum Engineering from Texas A&M University.
Steven A. Webster has been the Chairman of our Board of Directors since June
1997 and has been a director since 1993. Mr. Webster serves as the Chairman of
Global Energy Partners, Ltd., an affiliate of CSFB Private Equity, which makes
private equity investments in the energy business. From December 1997 to May
1999, Mr. Webster was the Chief Executive Officer and President of R&B Falcon
Corporation, an offshore drilling contractor, and prior to that, was Chairman
and Chief Executive Officer of Falcon Drilling Company, which he founded in
1988. Mr. Webster is also a director of Grey Wolf, Inc. (an onshore drilling
company), Seabulk International, Inc. (a marine transportation and service
provider), Geokinetics, Inc. (a seismic acquisition and geophysical services
company), Crown Resources Corporation (a precious metals exploration company),
Goodrich Petroleum Corporation (an oil and gas exploration company), Basic
Energy Services, Inc. (a well servicing company) and Brigham Exploration Company
(an oil and gas exploration company), as well as various private companies. He
is also a trust manager of Camden Property Trust (a real estate investment
trust). Mr. Webster holds an M.B.A. degree from Harvard Business School and a
Bachelor of Science in Industrial Management degree from Purdue University.
Christopher C. Behrens has been a director since December 1999. Since 1998, Mr.
Behrens has been a General Partner of J.P. Morgan Partners, LLC (formerly Chase
Capital Partners), the private equity investment affiliate of JP Morgan Chase &
Co. which focuses on energy investments and industrial buyouts. Mr. Behrens is a
director of Brand Services Inc., Interline Brands, Inc. and Berry Plastics
Corporation, as well as various private companies. Mr. Behrens received a B.A.
from the University of California at Berkeley and an M.A. from Columbia
University.
Douglas A. P. Hamilton has been a director since 1993. Mr. Hamilton, a private
investor, has been an active investor in the oil and gas business since 1985.
Mr. Hamilton has been the President of Anatar Investments, Inc., a diversified
investment capital firm with active investments in oil and gas and offshore
contract drilling, since 1979 and is a co-owner of the French Culinary
Institute, a cooking school in New York City. Mr. Hamilton has a degree from the
University of North Carolina and completed the Program for Management
Development at Harvard Business School.
Paul B. Loyd, Jr., has been a director since 1993. Mr. Loyd was Chairman of the
Board and Chief Executive Officer of Reading & Bates Corporation from 1991 to
1997 and from 1999 to 2001 until its merger with Transocean Inc. Mr. Loyd has
been the principal of Loyd & Associates, Inc., a private financial consulting
firm, since 1989. Mr. Loyd was Chief Executive Officer and a director of Chiles-
Alexander International, Inc. from 1987 to 1989, President and a director of
Griffin-Alexander Drilling Company, from 1984 to 1987, and prior to that, a
director and Chief Financial Officer of Houston Offshore International, all of
which are companies in the offshore drilling industry. Mr. Loyd is currently a
director of Transocean Inc. (an offshore drilling contractor) and Frontier Oil
Corporation (a refining and marketing company) and is a member of the Board of
Trustees of Southern Methodist University. Mr. Loyd served as President of our
company from its inception in September 1993 until December 1993. Mr. Loyd holds
an undergraduate degree from Southern Methodist University and an M.B.A. degree
from Harvard Business School.
Bryan R. Martin has been a director since March 2002. Since 2000, he has been a
Principal at J.P. Morgan Partners, LLC (formerly Chase Capital Partners), the
private equity investment affiliate of JP Morgan Chase & Co. which focuses on
energy investments and industrial buyouts. Prior to his role at J.P. Morgan
Partners, LLC, Mr. Martin was a Partner of the Beacon Group since 1994 and
co-manager of the Beacon Group Energy Funds. Prior to that Mr. Martin worked as
an Equity Analyst at Fidelity Investments co-managing the Select Energy and
Specialty Retail portfolios. Mr. Martin holds a bachelors degree from Yale
University and a Masters in Management from the J. L. Kellogg Graduate School of
Management. Mr. Martin is also a director of Coherent Networks, Crosstown
Traders, SmartSynch, Shell Technology Investment Partners and Wellogix. In
addition, Mr. Martin is a member of the Investment Committees of Lime Rock
Partners and Shell Technology Investment Partners.
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F. Gardner Parker has been a director since 2000. He has been Managing Outside
Trust Manager with Camden Property Trust since 1998. He also serves on the
boards of Crown Resources Corporation and Sharps Compliance Corp. (a waste
management services provider). In addition, he serves on the board of directors
of the following private companies: Gillman Automobile Dealerships, Net Near U
Communications, MCS Technologies, Camp Longhorn, Inc., nii communications, inc.,
Sherwood Healthcare Inc., and Arena Power. Mr. Parker also worked with Ernst &
Ernst (now Ernst & Young LLP) for 14 years, seven of which he served as a
partner. He is a graduate of The University of Texas.
Frank A. Wojtek has been a director since 1993. Mr. Wojtek served as our Chief
Financial Officer, Vice President, Secretary and Treasurer from 1993 until
August 2003. From 1992 to 1997, Mr. Wojtek was the Assistant to the Chairman of
the Board of Reading & Bates Corporation (an offshore drilling company). Mr.
Wojtek has also held the positions of Vice President and Secretary/Treasurer of
Loyd & Associates, Inc., a private financial consulting firm, since 1989. Mr.
Wojtek held the positions of Vice President and Chief Financial Officer of
Griffin-Alexander Drilling Company from 1984 to 1987, Treasurer of Chiles-
Alexander International Inc. from 1987 to 1989, and Vice President and Chief
Financial Officer of India Offshore Inc. from 1989 to 1992, all of which were
companies in the offshore drilling industry. Mr. Wojtek is a Certified Public
Accountant and holds a B.B.A. in Accounting with Honors from The University of
Texas.
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DESCRIPTION OF CAPITAL STOCK
The description of our capital stock in this section is a summary and is not
intended to be complete. For a complete description of our capital stock, please
read our amended and restated articles of incorporation and our amended and
restated bylaws, the Statement of Resolution relating to our Series B preferred
stock and the warrant agreements setting forth the terms of our outstanding
warrants, all of which have been filed with the SEC.
GENERAL
Our authorized capital stock consists of (1) 40,000,000 shares of common stock,
par value $0.01 per share, and (2) 10,000,000 shares of preferred stock, par
value $0.01 per share. Immediately following this offering, excluding shares
that may be sold upon exercise of the underwriters' over-allotment option,
approximately 18,010,015 shares of common stock and 68,559 shares of preferred
stock will be outstanding.
COMMON STOCK
The holders of our common stock are entitled to one vote per share on all
matters on which shareholders are permitted to vote. The holders of our common
stock have no preemptive rights to purchase or subscribe for our securities, and
our common stock is not convertible or subject to redemption by us.
Subject to the rights of the holders of any class of our capital stock having
any preference or priority over our common stock, the holders of our common
stock are entitled to dividends in such amounts as may be declared by our board
of directors from time to time out of funds legally available for such payments
and, if we are liquidated, dissolved or wound up, to a ratable share of any
distribution to shareholders, after satisfaction of all our liabilities and the
prior rights of any outstanding class of our preferred stock.
Computershare Trust Company, Inc. is the registrar and transfer agent for our
common stock.
PREFERRED STOCK
Our board of directors has the authority, without shareholder approval, to issue
shares of preferred stock in one or more series, and to fix the number and terms
of each such series. We have no present plan to issue additional shares of
preferred stock.
The issuance of shares of preferred stock could adversely affect the voting
power of holders of our common stock, discourage an unsolicited acquisition
proposal or make it more difficult for a third party to gain control of our
company. For instance, the issuance of a series of preferred stock might impede
a business combination by including class voting rights that would enable the
holder to block such a transaction or facilitate a business combination by
including voting rights that would provide a required percentage vote of the
shareholders. Although our board of directors is required to make any
determination to issue preferred stock based on its judgment as to the best
interests of our shareholders, the board could act in a manner that would
discourage an acquisition attempt or other transaction that some of the
shareholders might believe to be in their best interests or in which
shareholders might receive a premium for their stock over the then market price
of the stock. Our board of directors does not presently intend to seek
shareholder approval prior to any issuance of currently authorized stock unless
otherwise required by law or the rules of the Nasdaq National Market.
Series B Preferred Stock
In February 2002 we adopted a Statement of Resolution establishing a series of
150,000 shares of our preferred stock, designated as Series B Convertible
Participating Preferred Stock, and issued 60,000 shares of our Series B
preferred stock to Mellon and Steven A. Webster. We had 68,559 shares of our
Series B preferred stock outstanding as of September 30, 2003.
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The affirmative vote or written consent of a majority of the holders of our
Series B preferred stock, voting as a class, is required for us to:
- create, authorize or issue, or effect any corporate transaction that
results in the creation or issuance of, any class or series of our equity
securities that rank senior to the Series B preferred stock or on parity
with the Series B preferred stock as to payment of dividends or
distributions upon our liquidation, dissolution or winding up;
- effect any corporate transaction or approve an amendment to our articles of
incorporation that would result in a change in the aggregate number of
authorized shares of Series B preferred stock or a change in the
designations, preferences, limitations or relative rights of the shares of
Series B preferred stock;
- effect any change in our articles of incorporation or bylaws that adversely
affects the rights, preferences or privileges of the Series B preferred
stock;
- materially change the nature of our business; or
- issue any shares of Series B preferred stock except pursuant to the
securities purchase agreement under which we issued the 60,000 shares
described above.
The holders of our Series B preferred stock are not permitted to vote on any
other matters except as required by applicable law. For any matter on which the
holders of our Series B preferred stock are permitted to vote, each such holder
is entitled to one vote per share, and the affirmative vote of the holders of a
majority of the outstanding shares of Series B preferred shares entitled to vote
is required to approve the matter.
The holders may convert the Series B preferred stock into common stock at a
conversion price of $5.70 per share, subject to adjustment for transactions
including issuance of common stock or securities convertible into or exercisable
for common stock at less than the conversion price of the Series B preferred
stock.
Dividends on our Series B preferred stock are payable in either cash at a rate
of 8% per annum or, at our option, by payment in kind of additional shares of
the Series B preferred stock at a rate of 10% per annum. At December 31, 2002
and September 30, 2003, the outstanding balance of the Series B preferred stock
has been increased by $0.5 million (5,294 shares) and $0.9 million (8,559
shares), respectively, for dividends paid in kind. At September 30, 2003, we had
accrued a dividend of $0.2 million that is payable on December 31, 2003. In
addition to the foregoing, if we declare a cash dividend on our common stock,
the holders of shares of Series B preferred stock are entitled to receive for
each share of Series B preferred stock a cash dividend in the amount of the cash
dividend that would be received by a holder of the common stock into which that
share of Series B preferred stock is convertible on the record date for the cash
dividend. Unless all accrued dividends on the Series B preferred stock shall
have been paid and a sum sufficient for the payment thereof set apart, no
distributions may be paid on any Junior Stock (as defined in the Statement of
Resolutions for the Series B preferred stock) (which includes the common stock)
and no redemption of any Junior Stock shall occur other than subject to certain
exceptions.
We must redeem the Series B preferred stock at any time after the third
anniversary of its initial issuance upon request from any holder at a price per
share equal to Purchase Price/Dividend Preference (as defined below). We may
redeem the Series B preferred stock after the third anniversary of its initial
issuance at a price per share equal to the Purchase Price/Dividend Preference
and, prior to that time, at varying preferences to the Purchase Price/Dividend
Preference. "Purchase Price/Dividend Purchase" is defined to mean, generally,
$100 plus all cumulative and accrued dividends on that share of Series B
preferred stock.
In the event of any dissolution, liquidation or winding up or certain mergers or
sales or other disposition by us of all or substantially all of our assets, the
holder of each share of Series B preferred stock then outstanding will be
entitled to be paid per share of Series B preferred stock, prior to payment to
holders of our common stock and out of our assets available for distribution to
our shareholders, the greater of:
- $100 in cash plus all cumulative and accrued dividends; and
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- in specified circumstances, the "as-converted" liquidation distribution, if
any, payable in such liquidation with respect to each share of common
stock.
Upon the occurrence of specified events constituting a "Change of Control" (as
defined in the Statement of Resolutions), we must make an offer to each holder
of Series B preferred stock to repurchase all of that holder's Series B
preferred stock at an offer price per share of Series B preferred stock in cash
equal to 105% of the Change of Control Purchase Price, which is generally
defined to mean $100 plus all cumulative and accrued dividends.
WARRANTS
We have outstanding warrants expiring in February 2007 to purchase up to 252,632
shares of our common stock at a price of $5.94 per share, subject to adjustment.
We sold these warrants to Mellon and Steven A. Webster in connection with our
issuance to them of Series B preferred stock. These warrants are exercisable at
any time after issuance and are valued for accounting purposes at $0.06 per
warrant.
We have outstanding warrants expiring in December 2007 to purchase up to
2,760,189 shares of our common stock at an exercise price of $2.20 per share,
subject to adjustment. We sold these warrants in December 1999 to JPMorgan,
Mellon, Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton in
connection with the sale of $22.0 million principal amount of 9% Senior
Subordinated Notes due 2007. These warrants are exercisable at any time after
issuance and are valued for accounting purposes at $0.25 each.
We have outstanding warrants expiring in January 2005 to purchase up to 250,000
shares of our common stock at an exercise price of $4.00 per share, subject to
adjustment. We initially sold 1,000,000 warrants in January 1998 to certain
parties associated with Enron Corp. at an exercise price of $11.50 per share. In
connection with the 1999 transaction described in the preceding paragraph, we
repurchased 750,000 of those warrants and reduced the exercise price on the
remaining outstanding warrants to $4 per share.
SPECIAL MEETINGS
Our articles of incorporation provide that special meetings of our shareholders
may be called only by the chairman of our board of directors, our president, a
majority of our board of directors or by shareholders holding not less than 50%
of our outstanding voting stock.
VOTING
Our common stock does not have cumulative voting rights. Accordingly, holders of
a majority of the total votes entitled to vote in an election of directors will
be able to elect all of the directors. See "Risk Factors--Certain of our
affiliates control a majority of our outstanding common stock, which may affect
your vote as a shareholder."
Our articles of incorporation or Texas law requires the affirmative vote of
holders of:
- 66 2/3% of the outstanding shares entitled to vote on the matter to approve
any merger, consolidation or share exchange, any disposition of our assets
or any dissolution of our company; and
- a majority of the outstanding shares entitled to vote on the matter to
approve any amendment to our articles of incorporation or any other matter
for which a shareholder vote is required by the Texas Business Corporation
Act. If any class or series of shares is entitled to vote as a class with
regard to these events, the vote required will be the affirmative vote of
the holders of a majority of the outstanding shares within each class or
series of shares entitled to vote thereon as a class and at least a
majority of the outstanding shares of capital stock otherwise entitled to
vote thereon.
Our bylaws provide that shareholders who wish to nominate directors or to bring
business before a shareholders' meeting must notify us and provide pertinent
information at least 80 days before the meeting date, or within 10 days after
public announcement pursuant to our bylaws of the meeting date, if the meeting
date has not been publicly announced at least 90 days in advance.
66
Our articles of incorporation and bylaws provide that no director may be removed
from office except for cause and upon the affirmative vote of the holders of a
majority of the votes entitled to be cast in the election of our directors. The
following events constitute "cause":
- the director has been convicted, or is granted immunity to testify where
another has been convicted, of a felony;
- the director has been found by a court or by the affirmative vote of a
majority of all other directors to be grossly negligent or guilty of
willful misconduct in the performance of duties to us;
- the director is adjudicated mentally incompetent; or
- the director has been found by a court or by the affirmative vote of a
majority of all other directors to have breached his duty of loyalty to us
or our shareholders or to have engaged in a transaction with us from which
the director derived an improper personal benefit.
BUSINESS COMBINATION LAW
We are subject to Part Thirteen (the "Business Corporation Law") of the Texas
Business Corporation Act. In general, the Business Combination Law prevents an
"affiliated shareholder" or its affiliates or associates from entering into or
engaging in a "business combination" with an "issuing public corporation" during
the three-year period immediately following the affiliated shareholder's
acquisition of shares unless:
- before the date the person became an affiliated shareholder, the board of
directors of the issuing public corporation approved the business
combination or the acquisition of shares made by the affiliated shareholder
on that date; or
- not less than six months after the date the person became an affiliated
shareholder, the business combination is approved by the affirmative vote
of holders of at least two-thirds of the issuing public corporation's
outstanding voting shares not beneficially owned by the affiliated
shareholder or its affiliates or associates.
For the purposes of the Business Combination Law, an "affiliated shareholder" is
defined generally as a person who is or was within the preceding three-year
period the beneficial owner of 20% or more of a corporation's outstanding voting
shares. A "business combination" is defined generally to include:
- mergers or share exchanges;
- dispositions of assets having an aggregate value equal to 10% or more of
the market value of the assets or of the outstanding common stock
representing 10% or more of the earning power or net income of the
corporation;
- certain issuances or transaction by the corporation that would increase the
affiliated shareholder's number of shares of the corporation;
- certain liquidations or dissolutions; and
- the receipt of tax, guarantee, loan or other financial benefits by an
affiliated shareholder of the corporation.
An "issuing public corporation" is defined generally as a Texas corporation with
100 or more shareholders, any voting shares registered under the Securities
Exchange Act of 1934 or any voting shares qualified for trading in a national
market system.
The Business Combination Law does not apply to a business combination of an
issuing public corporation that elects not be governed thereby through either
its original articles of incorporation or bylaws or by an amendment thereof. Our
articles of incorporation and bylaws do not so provide, nor do we currently
intend to make any such amendments.
As a result of the approval of the Board of Directors of the acquisition of
shares by our original shareholders, none of Steven A. Webster, Douglas A. P.
Hamilton, Paul B. Loyd, Jr. or Frank A. Wojtek (those shareholders of our
company owning 20% or more of the outstanding voting shares prior to our initial
public offering) will be subject to the restrictions imposed on affiliated
shareholders by the Business
67
Combination Law, nor is JPMorgan, Mellon or the parties subject to current
shareholder agreements with these entities subject to such restrictions as a
result of either their current investments in our company or those shareholder
agreements.
In discharging the duties of a director under Texas law, a director, in
considering the best interests of our company, may consider the long-term as
well as the short-term interests of our company and our shareholders, including
the possibility that those interests may be best served by our continued
independence.
LIMITATION OF DIRECTOR LIABILITY AND INDEMNIFICATION ARRANGEMENTS
Our articles of incorporation contain a provision that limits the liability of
our directors as permitted by the Texas Business Corporation Act. The provision
eliminates the personal liability of a director to us and our shareholders for
monetary damages for an act or omission in the director's capacity as a
director. The provision does not change the liability of a director for breach
of his duty of loyalty to us or to our shareholders, for an act or omission not
in good faith that involves intentional misconduct or a knowing violation of
law, for an act or omission for which the liability of a director is expressly
provided for by an applicable statute, or in respect of any transaction from
which a director received an improper personal benefit. Pursuant to our articles
of incorporation, the liability of directors will be further limited or
eliminated without action by shareholders if Texas law is amended to further
limit or eliminate the personal liability of directors.
Our bylaws provide for the indemnification of our officers and directors, and
the advancement to them of expenses in connection with proceedings and claims,
to the fullest extent permitted by the Texas Business Corporation Act. We have
also entered into indemnification agreements with each of our directors and some
of our officers that contractually provide for indemnification and expense
advancement and include related provisions meant to facilitate the indemnitee's
receipt of such benefits. In addition, we may purchase directors', and officers'
liability insurance policies for our directors and officers in the future. Our
bylaws and these agreements with directors and officers provide for
indemnification for amounts:
- in respect of the deductibles for these insurance policies;
- that exceed the liability limits of our insurance policies; and
- that are available, were available or become available to us or are
generally available to companies comparable to us but which our officers or
directors determine is inadvisable for us to purchase, given the cost.
Such indemnification may be made even though our directors and officer would not
otherwise be entitled to indemnification under other provisions of our bylaws or
these agreements.
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UNDERWRITING
We and the selling shareholders have entered into an underwriting agreement with
the underwriters named below. CIBC World Markets Corp., First Albany Capital
Inc., Hibernia Southcoast Capital, Inc. and Johnson Rice & Company L.L.C. are
acting as representatives of the underwriters.
The underwriting agreement provides for the purchase of a specific number of
shares of common stock by each of the underwriters. The underwriters'
obligations are several, which means that each underwriter is required to
purchase a specified number of shares, but is not responsible for the commitment
of any other underwriter to purchase shares. Subject to the terms and conditions
of the underwriting agreement, each underwriter has severally agreed to purchase
the number of shares of common stock set forth opposite its name below:
UNDERWRITER NUMBER OF SHARES
----------- ----------------
CIBC World Markets Corp.....................................
First Albany Capital Inc....................................
Hibernia Southcoast Capital, Inc. ..........................
Johnson Rice & Company L.L.C. ..............................
---------
Total..................................................... 5,700,000
=========
The underwriters have agreed to purchase all of the shares offered by this
prospectus (other than those covered by the over-allotment option described
below) if any are purchased. Under the underwriting agreement, if an underwriter
defaults in its commitment to purchase shares, the commitments of nondefaulting
underwriters may be increased or the underwriting agreement may be terminated,
depending on the circumstances.
The shares should be ready for delivery on or about , 2004, against
payment in immediately available funds. The underwriters are offering the shares
subject to various conditions and may reject all or part of any order. The
representatives have advised us and the selling shareholders that the
underwriters propose to offer the shares directly to the public at the public
offering price that appears on the cover page of this prospectus. In addition,
the representatives may offer some of the shares to other securities dealers at
such price less a concession of $ per share. The underwriters may also
allow, and such dealers may reallow, a concession not in excess of $
per share to other dealers. After the shares are released for sale to the public
the representatives may change the offering price and other selling terms at
various times.
We and some of the selling shareholders have granted the underwriters an
over-allotment option, exercisable for up to 30 days after the date of this
prospectus, which permits the underwriters to purchase a maximum of 855,000
additional shares (256,500 from us and 598,500 from the selling shareholders) to
cover over-allotments. If the underwriters exercise all or part of this option,
they will purchase shares covered by the option at the public offering price
that appears on the cover page of this prospectus, less the underwriting
discount. If this option is exercised in full, the total price to the public
will be $ . The total proceeds to us will be $ and the total proceeds to
the selling shareholders will be $ . The underwriters have severally agreed
that, to the extent the over-allotment option is exercised, they will each
purchase a number of additional shares proportionate to the underwriter's
initial amount reflected in the foregoing table.
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The following table provides information regarding the amount of the discount to
be paid to the underwriters by us and the selling shareholders:
TOTAL WITHOUT TOTAL WITH FULL
EXERCISE OF OVER- EXERCISE OF OVER-
PER SHARE ALLOTMENT OPTION ALLOTMENT OPTION
--------- ----------------- -----------------
Carrizo Oil & Gas, Inc........................... $ $ $
Selling Shareholders.............................
----- -----
Total..........................................
===== =====
We estimate that the total expenses of the offering, excluding the underwriting
discount, will be approximately $ .
We and the selling shareholders have agreed to indemnify the underwriters
against certain liabilities, including liabilities under the Securities Act of
1933.
We, our officers and directors and the selling shareholders have agreed to a
90-day "lock up" with respect to all of the shares of common stock that they
beneficially own, including securities that are convertible into shares of
common stock and securities that are exchangeable or exercisable for shares of
common stock. This means that, subject to certain exceptions, for a period of 90
days following the date of this prospectus, we and such persons may not offer,
sell, pledge or otherwise dispose of these securities without the prior written
consent of CIBC World Markets Corp.
Other than in the United States, no action has been taken by us, the selling
shareholders or the underwriters that would permit a public offering of the
shares of common stock offered by this prospectus in any jurisdiction where
action for that purpose is required. The shares of common stock offered by this
prospectus may not be offered or sold, directly or indirectly, nor may this
prospectus or any other offering material or advertisements in connection with
the offer and sale of any such shares of common stock be distributed or
published in any jurisdiction, except under circumstances that will result in
compliance with the applicable rules and regulations of that jurisdiction.
Persons into whose possession this prospectus comes are advised to inform
themselves about, and to observe any restrictions relating to the offering and
the distribution of this prospectus. This prospectus does not constitute an
offer to sell or a solicitation of an offer to buy any shares of common stock
offered by this prospectus in any jurisdiction in which such an offer or a
solicitation is unlawful.
Our common stock is traded on the Nasdaq National Market under the symbol
"CRZO."
Hibernia National Bank, the lender under our credit facility, is an affiliate of
Hibernia Southcoast Capital, Inc. Hibernia National Bank will receive more than
10% of the proceeds of this offering from the sale of primary shares in a
temporary repayment of indebtedness under our credit facility. Accordingly, this
offering is being made in compliance with the requirements of 2710(c)(8) of the
National Association of Securities Dealers, Inc. Conduct Rules.
Rules of the SEC may limit the ability of the underwriters to bid for or
purchase shares before the distribution of the shares is completed. However, the
underwriters may engage in the following activities in accordance with the
rules:
- Stabilizing transactions--The representatives may make bids or purchases
for the purpose of pegging, fixing or maintaining the price of the shares,
so long as stabilizing bids do not exceed a specified maximum.
- Over-allotments and syndicate covering transactions--The underwriters may
sell more shares of common stock in connection with this offering than the
number of shares that they have committed to purchase. This over-allotment
creates a short position for the underwriters. This short sales position
may involve either "covered" short sales or "naked" short sales. Covered
short sales are short sales made in an amount not greater than the
underwriters' over-allotment option to purchase additional shares in this
offering described above. The underwriters may close out any covered short
position either by exercising their over-allotment option or by purchasing
shares in the open market.
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To determine how they will close the covered short position, the
underwriters will consider, among other things, the price of shares
available for purchase in the open market, as compared to the price at
which they may purchase shares through the over-allotment option. Naked
short sales are short sales in excess of the over-allotment option. The
underwriters must close out any naked short position by purchasing shares
in the open market. A naked short position is more likely to be created if
the underwriters are concerned that, in the open market after pricing,
there may be downward pressure on the price of the shares that could
adversely affect investors who purchase shares in this offering.
- Penalty bids--If the representatives purchase shares in the open market in
a stabilizing transaction or syndicate covering transaction, they may
reclaim a selling concession from the underwriters and selling group
members who sold those shares as part of this offering.
- Passive market making--Market makers in the shares who are underwriters or
prospective underwriters may make bids for or purchases of shares, subject
to limitations, until the time, if ever, at which a stabilizing bid is
made.
Similar to other purchase transactions, the underwriters' purchases to cover the
syndicate short sales or to stabilize the market price of our common stock may
have the effect of raising or maintaining the market price of our common stock
or preventing or mitigating a decline in the market price of our common stock.
As a result, the price of the shares of our common stock may be higher than the
price that might otherwise exist in the open market. The imposition of a penalty
bid might also have an effect on the price of the shares if it discourages
resale of the shares.
Neither we nor the underwriters make any representation or prediction as to the
effect that the transactions described above may have on the price of the shares
These transactions may occur on the Nasdaq National Market or otherwise. If such
transactions are commenced, they may be discontinued without notice at any time.
The underwriters have an agreement with Yahoo! Net Roadshow to host the roadshow
on the internet for qualified investors only, and they will follow the guidance
set forth by the staff of the SEC regarding such roadshows. The preliminary
prospectus will be posted on the roadshow website for informational purposes
only. We do not intend to engage in any other electronic distribution of the
prospectus.
LEGAL MATTERS
Certain legal matters in connection with the shares of common stock being
offered hereby are being passed upon for us by Baker Botts L.L.P., Houston,
Texas. Certain legal matters in connection with this offering are being passed
upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.
EXPERTS
The consolidated financial statements of Carrizo Oil & Gas, Inc. appearing or
incorporated by reference in this prospectus and registration statement have
been audited by Ernst & Young LLP, independent auditors, to the extent indicated
in their report thereon also appearing elsewhere herein and in the registration
statement or incorporated by reference. Such consolidated financial statements
have been included herein or incorporated herein by reference in reliance upon
such report given on the authority of such firm as experts in accounting and
auditing.
The audited financial statements as of December 31, 2000 and 2001 included in
this prospectus and elsewhere in the registration statement have been audited by
Arthur Andersen LLP, our previous independent public accountants, as indicated
in their report with respect thereto, and are included herein in reliance upon
the authority of said firm as experts in giving said report. Arthur Andersen LLP
completed its audit of our consolidated financial statements at December 31,
2001 and 2000 and for each of the three years in the period ended December 31,
2001 and issued its report with respect to such
71
consolidated financial statements on March 20, 2002. On April 11, 2002, we
dismissed Arthur Andersen LLP as our independent public accountants.
Your ability to recover for claims against Arthur Andersen LLP may be limited.
In particular, you may not be able to effectively recover against Arthur
Andersen LLP for any claims you may have under securities or other laws as a
result of Arthur Andersen LLP's previous role as our independent public
accountants and as author of the audit report for the audited financial
statements for the years ended December 31, 2000 and 2001 included in this
prospectus.
The letter reports of Ryder Scott Company and Fairchild and Wells, Inc. included
as Appendix A to this prospectus and certain information with respect to our
natural gas and oil reserves derived therefrom have been included herein in
reliance upon such firms as experts with respect to such matters.
72
WHERE YOU CAN FIND MORE INFORMATION
We have filed a registration statement on Form S-2 with the SEC in connection
with this offering. We file annual, quarterly and current reports, proxy
statements and other information with the SEC. You may read and copy the
registration statement and any other documents we have filed at the SEC's Public
Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call
the SEC at 1-800-SEC-0330 for further information on the Public Reference Room.
Our SEC filings are also available to the public at the SEC's Internet site at
http://www.sec.gov.
This prospectus is part of the registration statement and does not contain all
of the information included in the registration statement. Whenever a reference
is made in this prospectus to any of our contracts or other documents, the
reference may not be complete and, for a copy of the contract or document, you
should refer to the exhibits that are part of the registration statement.
The SEC allows us to "incorporate by reference" into this prospectus the
information we file with it, which means that we can disclose important
information to you by referring you to those documents. Information incorporated
by reference is part of this prospectus, except for any information that is
superseded by information included directly in this prospectus. Later
information filed with the SEC will update and supersede this information. We
incorporate by reference the documents listed below.
- Our Annual Report on Form 10-K for the year ended December 31, 2002;
- Our Quarterly Report on Form 10-Q for the quarter ended March 31, 2003;
- Item 5 of our Current Report on Form 8-K filed on April 29, 2003;
- Item 5 of our Current Report on Form 8-K filed on May 8, 2003;
- Our Quarterly Report on Form 10-Q for the quarter ended June 30, 2003;
- Item 5 of our Current Report on Form 8-K filed on August 6, 2003;
- Our Quarterly Report on Form 10-Q for the quarter ended September 30, 2003;
and
- Item 5 of our Current Report on Form 8-K filed on November 6, 2003.
You may request a copy of these filings, at no cost, by contacting us at:
Carrizo Oil & Gas, Inc.
Attention: Investor Relations
14701 St. Mary's Lane, Suite 800
Houston, Texas 77079
(281) 496-1352
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GLOSSARY OF CERTAIN OIL AND GAS TERMS
The definitions set forth below apply to the indicated terms as used in this
prospectus. All volumes of natural gas referred to in this prospectus are stated
at the legal pressure base of the state or area where the reserves exist 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, used herein in
reference to oil or other liquid hydrocarbons.
Bbls/d. Stock tank barrels per day.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of
natural gas to one Bbl of oil, condensate or natural gas liquids.
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Completion. The installation of permanent equipment for the production of
natural gas or oil or, in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
Developed acreage. The number of acres that are allocated or assignable to
producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or 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 hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
Exploratory well. A well drilled to find and produce natural gas or oil reserves
not classified as proved, to find a new reservoir in a field previously found to
be productive of natural gas or oil 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.
Finding costs. Costs associated with acquiring and developing proved oil and
natural gas reserves, which we capitalize pursuant to generally accepted
accounting principles, including all costs involved in acquiring acreage,
geological and geophysical work and the cost of drilling and completing wells.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBbls/d. One thousand barrels of oil or other liquid hydrocarbons per day.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. 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 oil, condensate or natural gas liquids.
MMBtu. One million British Thermal Units.
MMcf. One million cubic feet.
MMcf/d. One million cubic feet per day.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of oil, condensate or natural gas liquids, which
approximates the relative energy content of oil, condensate
74
and natural gas liquids as compared to natural gas. Historically prices often
have been higher or substantially higher for oil than natural gas on an energy
equivalent basis, although there have been periods in which they have been lower
or substantially lower.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Net Revenue Interest. The operating interest used to determine the owner's share
of total production.
NYMEX. The New York Mercantile Exchange.
Present value. When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using prices
and costs in effect as of the date indicated, without giving effect to
nonproperty-related expenses such as general and administrative expenses, debt
service and future income tax expense 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 hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
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 reserves. Proved reserves that are expected to be recovered
from new wells on undrilled acreage or from existing wells where a relatively
major expenditure is required for recompletion.
PV-10 Value. The present value of estimated future revenues to be generated from
the production of proved reserves calculated in accordance with SFAS No. 69 and
SEC guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation, without
giving effect to nonproperty related expenses such as general and administrative
expenses, debt service, future income tax expense and depreciation, depletion
and amortization, discounted using an annual discount rate of 10%.
Recompletion. The completion for production of an existing well bore in a
formation other than that in which the well has been previously completed.
Reserve Replacement Percentage. Estimated net reserves added to proved reserves
through extensions, discoveries and revisions, divided by production for the
period.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil and/or gas that is confined by impermeable rock
or water barriers and is individual and separate from other reservoirs.
Royalty interest. An interest in an oil and natural gas property entitling the
owner to a share of natural gas or oil production free of costs of production.
Standardized Measure. The after-tax present value of estimated future revenues
to be generated from the production of proved reserves calculated in accordance
with Securities and Exchange Commission guidelines, net of estimated production
and future development costs, using prices and costs as of the date of
estimation without future escalation, without giving effect to non-property
related expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.
3-D seismic data. Three-dimensional pictures of the subsurface created by
collecting and measuring the intensity and timing of sound waves transmitted
into the earth as they reflect back to the surface.
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.
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.
75
INDEX TO FINANCIAL STATEMENTS
Reports of Independent Accountants.......................... F-2
Consolidated Balance Sheets as of December 31, 2002 and
2001...................................................... F-4
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001, and 2000......................... F-5
Consolidated Statements of Shareholders' Equity for the
Years Ended December 31, 2002, 2001, and 2000............. F-6
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001, and 2000......................... F-7
Notes to the Consolidated Financial Statements.............. F-8
Consolidated Balance Sheets as of September 30, 2003 and
December 31, 2002......................................... F-26
Consolidated Statements of Operations for the Three and Nine
Months Ended September 30, 2003 and 2002.................. F-27
Consolidated Statements of Cash Flows for the Nine Months
Ended September 30, 2003 and 2002......................... F-28
Notes to the Consolidated Financial Statements.............. F-29
F-1
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Shareholders of
Carrizo Oil & Gas, Inc.
We have audited the accompanying consolidated balance sheet of Carrizo Oil &
Gas, Inc. as of December 31, 2002, and the related consolidated statements of
operations, shareholders' equity and cash flows for the year 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 audit. The consolidated financial statements of Carrizo Oil & Gas, Inc. as
of December 31, 2001 and for the two years then ended, were audited by other
auditors who have ceased operations and whose report dated March 20, 2002,
expressed an unqualified opinion on those statements, before the revisions
described in Note 5.
We conducted our audit in accordance with auditing standards generally accepted
in the United States. 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 2002 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of the Company
as of December 31, 2002, and the results of its operations and its cash flows
for the year then ended, in conformity with accounting principles generally
accepted in the United States.
As discussed above, the consolidated financial statements of the Company as of
December 31, 2001 and for the two years then ended were audited by other
auditors who have ceased operations. As described in Note 5, the Company revised
the reported amounts of certain temporary differences at December 31, 2001. We
audited the adjustments described in Note 5 that were applied to revise the
reported amounts of temporary differences in the 2001 consolidated financial
statements. Our procedures included (a) agreeing the revised temporary
differences to the Company's underlying records obtained from management, and
(b) testing the mathematical accuracy of the revisions to the temporary
differences. In our opinion, such adjustments are appropriate and have been
properly applied. However, we were not engaged to audit, review, or apply any
procedures to the 2001 consolidated financial statements of the Company other
than with respect to such adjustments and, accordingly, we do not express an
opinion or any other form of assurance on the 2001 consolidated financial
statements taken as a whole.
ERNST & YOUNG LLP
Houston, Texas
March 14, 2003
F-2
THIS IS A COPY OF AN ACCOUNTANTS' REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN
LLP. THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP. AS DESCRIBED IN
NOTE 5 TO CARRIZO'S CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, 2002,
THE FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 2001 REFERRED TO IN
THIS REPORT HAVE BEEN REVISED SUBSEQUENT TO THE DATE OF THE REPORT TO REFLECT
REVISIONS TO TEMPORARY DIFFERENCES IN THE RECOGNITION OF INCOME AND EXPENSES FOR
FINANCIAL REPORTING PURPOSES AND FOR TAX PURPOSES. THE REVISIONS HAVE BEEN
REPORTED ON BY ERNST & YOUNG LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and
Board of Directors of
Carrizo Oil & Gas, Inc.:
We have audited the accompanying consolidated balance sheets of Carrizo Oil &
Gas, Inc. (a Texas corporation) as of December 31, 2000 and 2001, and the
related consolidated statements of operations, shareholders' equity and cash
flows for each of the three years in the period ended December 31, 2001. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of the Company as of
December 31, 2000 and 2001, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States.
As explained in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities to conform with Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities". Additionally, as explained in Note 10 to the consolidated financial
statements, effective January 1, 1999, the Company changed its method of
accounting for start up costs.
ARTHUR ANDERSEN LLP
Houston, Texas
March 20, 2002
F-3
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31,
-------------------
2001 2002
-------- --------
(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 3,236 $ 4,743
Accounts receivable, trade (net of allowance for doubtful
accounts of $0.5 million at December 31, 2001 and 2002,
respectively).......................................... 8,111 8,207
Advances to operators..................................... 509 501
Deposits.................................................. 48 46
Other current assets...................................... 600 605
-------- --------
Total current assets................................... 12,504 14,102
PROPERTY AND EQUIPMENT, net (full-cost method of accounting
for oil and natural gas properties)....................... 104,132 120,526
Deferred financing costs.................................... 756 760
-------- --------
$117,392 $135,388
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade................................... $ 10,263 $ 9,957
Accrued liabilities....................................... 348 1,014
Advances for joint operations............................. 368 1,550
Current maturities of long-term debt...................... 2,107 1,609
Current maturities of seismic obligation payable.......... - 1,414
-------- --------
Total current liabilities.............................. 13,086 15,544
LONG-TERM DEBT.............................................. 36,081 37,886
SEISMIC OBLIGATION PAYABLE.................................. - 1,103
DEFERRED INCOME TAXES....................................... 5,021 7,666
COMMITMENTS AND CONTINGENCIES (Note 9)
CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000 shares
of preferred stock authorized, of which 150,000 are shares
designated as convertible participating shares, with
65,294 convertible participating shares issued and
outstanding at December 31, 2002)(Note 8)................. - 6,373
SHAREHOLDERS' EQUITY:
Warrants (3,010,189 and 3,262,821 outstanding at December
31, 2001 and 2002, respectively)....................... 765 780
Common stock, par value $.01, (40,000,000 shares
authorized with 14,064,077 and 14,177,383 issued and
outstanding at December 31, 2001 and 2002,
respectively).......................................... 141 142
Additional paid in capital................................ 62,736 63,224
Retained earnings (deficit)............................... (1,144) 3,058
Accumulated other comprehensive income (loss)............. 706 (388)
-------- --------
63,204 66,816
-------- --------
$117,392 $135,388
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
2000 2001 2002
--------- --------- ---------
(in thousands except for
per share amounts)
OIL AND NATURAL GAS REVENUES................................ $26,834 $26,226 $26,802
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of
depreciation shown separately below)................... 4,941 4,138 4,908
Depreciation, depletion and amortization.................. 7,170 6,492 10,574
General and administrative................................ 3,143 3,333 4,133
Stock option compensation................................. 652 (558) (84)
------- ------- -------
Total costs and expenses............................... 15,906 13,405 19,531
------- ------- -------
OPERATING INCOME............................................ 10,928 12,821 7,271
OTHER INCOME AND EXPENSES:
Other income and expenses................................. 1,482 1,777 274
Interest income........................................... 592 275 55
Interest expense.......................................... (1,459) (1,040) (846)
Interest expense, related parties......................... (2,118) (2,137) (2,255)
Capitalized interest...................................... 3,564 3,171 3,100
------- ------- -------
INCOME BEFORE INCOME TAXES.................................. 12,989 14,867 7,599
INCOME TAXES................................................ 1,004 5,336 2,809
------- ------- -------
NET INCOME.................................................. $11,985 $ 9,531 $ 4,790
======= ======= =======
DIVIDENDS AND ACCRETION ON PREFERRED STOCK.................. - - 588
------- ------- -------
NET INCOME AVAILABLE TO
COMMON SHAREHOLDERS....................................... $11,985 $ 9,531 $ 4,202
======= ======= =======
BASIC EARNINGS
PER COMMON SHARE.......................................... $ 0.85 $ 0.68 $ 0.30
======= ======= =======
DILUTED EARNINGS PER COMMON SHARE........................... $ 0.74 $ 0.57 $ 0.26
======= ======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
WARRANTS COMMON STOCK ADDITIONAL RETAINED
------------------ ------------------- PAID IN COMPREHENSIVE EARNINGS
NUMBER AMOUNT SHARES AMOUNT CAPITAL INCOME (DEFICIT)
--------- ------ ---------- ------ ---------- ------------- ---------
(dollars in thousands)
BALANCE, January 1, 2000.... 3,010,189 $765 14,011,364 $141 $62,608 - $(22,660)
Net income.................. - - - - - - 11,985
Common stock issued......... - - 43,697 - 100 - -
--------- ---- ---------- ---- ------- ------- --------
BALANCE, December 31,
2000....................... 3,010,189 765 14,055,061 141 62,708 - (10,675)
--------- ---- ---------- ---- ------- ------- --------
Comprehensive income
Net income.................. - - - - - $ 9,531 9,531
Cumulative effect of change
in accounting principle.... - - - - - (1,967) -
Reclassification adjustments
for cumulative effect of
change in accounting
principle.................. - - - - - 1,967 -
Reclassification adjustments
for settled contracts...... - - - - - (2,020) -
Net change in fair value of
hedging instruments........ - - - - - 2,726 -
--------- ---- ---------- ---- ------- ------- --------
Comprehensive income $10,237
=======
Common stock issued......... - - 9,016 - 28 -
--------- ---- ---------- ---- ------- --------
BALANCE, December 31,
2001....................... 3,010,189 765 14,064,077 141 62,736 (1,144)
--------- ---- ---------- ---- ------- --------
Net income.................. - - - - - 4,790 4,790
Net change in fair value of
hedging instruments........ - - - - - (1,094) -
--------- ---- ---------- ---- ------- ------- --------
Comprehensive income $ 3,696
=======
Warrants issued............. 252,632 15 - - -
Common stock issued......... - - 113,306 1 488 -
Dividends and accretion of
discount on preferred
stock...................... - - - - (588)
--------- ---- ---------- ---- ------- --------
BALANCE, December 31,
2002....................... 3,262,821 $780 14,177,383 $142 $63,224 $ 3,058
========= ==== ========== ==== ======= ========
ACCUMULATED
OTHER
COMPREHENSIVE SHAREHOLDERS'
INCOME (LOSS) EQUITY
------------- -------------
(dollars in thousands)
BALANCE, January 1, 2000.... - $40,854
Net income.................. - 11,985
Common stock issued......... - 100
------- -------
BALANCE, December 31,
2000....................... - 52,939
------- -------
Comprehensive income
Net income.................. - 9,531
Cumulative effect of change
in accounting principle.... $(1,967) (1,967)
Reclassification adjustments
for cumulative effect of
change in accounting
principle.................. 1,967 1,967
Reclassification adjustments
for settled contracts...... (2,020) (2,020)
Net change in fair value of
hedging instruments........ 2,726 2,726
------- -------
Comprehensive income
Common stock issued......... - 28
------- -------
BALANCE, December 31,
2001....................... 706 63,204
------- -------
Net income.................. - 4,790
Net change in fair value of
hedging instruments........ (1,094) (1,094)
------- -------
Comprehensive income
Warrants issued............. - 15
Common stock issued......... - 489
Dividends and accretion of
discount on preferred
stock...................... - (588)
------- -------
BALANCE, December 31,
2002....................... $ (388) $66,816
======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------
2000 2001 2002
-------- -------- --------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income............................................ $ 11,985 $ 9,531 $ 4,790
Adjustment to reconcile net income to net cash
provided by operating activities--
Depreciation, depletion and amortization........... 7,170 6,492 10,574
Discount accretion................................. 82 85 86
Ineffective derivative instruments................. - 706 (706)
Interest payable in kind........................... 1,227 1,282 1,353
Stock option compensation (benefit)................ 652 (558) (84)
Gain on sale of Michael Petroleum Corporation...... - (3,900) -
Finders fee........................................ (1,544) - -
Deferred income taxes.............................. 902 5,204 2,645
Changes in assets and liabilities--
Accounts receivable................................ (2,968) (719) 530
Deposits and other current assets.................. (625) 200 206
Other assets....................................... (236) (57) (265)
Accounts payable................................... (155) 6,555 643
Accrued liabilities................................ 643 (870) 153
-------- -------- --------
Net cash provided by operating activities........ 17,133 23,951 19,925
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures.................................. (19,746) (38,264) (24,696)
Proceeds from sale of Michael Petroleum Corporation... - 5,445 -
Proceeds for sale of Metro Project.................... 5,075 - -
Proceeds from the sale of oil and natural gas
properties......................................... - - 355
Change in capital expenditure accrual................. (587) 355 (949)
Advances to operators................................. (490) 1,248 8
Advances for joint operations......................... (690) (8) 1,182
-------- -------- --------
Net cash used in investing activities............ (16,438) (31,224) (24,100)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from sale of common stock................ 100 27 14
Net proceeds from sale of preferred stock............. - - 5,800
Net proceeds from debt issuance....................... - 7,744 8,613
Debt repayments....................................... (3,923) (5,479) (8,745)
-------- -------- --------
Net cash provided by (used in) financing
activities.................................... (3,823) 2,292 5,682
-------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.... (3,128) (4,981) 1,507
CASH AND CASH EQUIVALENTS, beginning of year............ 11,345 8,217 3,236
-------- -------- --------
CASH AND CASH EQUIVALENTS, end of year.................. $ 8,217 $ 3,236 $ 4,743
======== ======== ========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized)... $ - $ - $ 1
======== ======== ========
Cash paid for income taxes............................ $ - $ - $ -
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
CARRIZO OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS
Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its
subsidiary, affiliates and predecessors, the Company) is an independent energy
company formed in 1993 and is engaged in the exploration, development,
exploitation and production of oil and natural gas. Its operations are focused
on Texas and Louisiana Gulf Coast trends, primarily the Frio, Wilcox and
Vicksburg trends. The Company, through CCBM Inc. (a wholly-owned subsidiary)
("CCBM") acquired interests in certain oil and natural gas leases in Wyoming and
Montana in areas prospective for coalbed methane. CCBM has an obligation to fund
$2.5 million of drilling costs on behalf of Rocky Mountain Gas, Inc. ("RMG"),
from whom the interests in the leases were acquired. Through December 31, 2002,
CCBM has satisfied $1.5 million of its drilling obligations on behalf of RMG.
The exploration for oil and natural gas is a business with a significant amount
of inherent risk requiring large amounts of capital. The Company intends to
finance its exploration and development program through cash from operations,
existing credit facilities or arrangements with other industry participants.
Should the sources of capital currently available to the Company not be
sufficient to explore and develop its prospects and meet current and near-term
obligations, the Company may be required to seek additional sources of financing
which may not be available on terms acceptable to the Company. This lack of
additional financing could force the Company to defer its planned exploration
and development drilling program which could adversely affect the recoverability
and ultimate value of the Company's oil and natural gas properties.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statement are presented in accordance with generally
accepted accounting principles in the United States. The consolidated financial
statements include the accounts of the Company and its subsidiary. All
intercompany accounts and transactions have been eliminated in consolidation.
CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from these estimates.
The Company believes the following critical accounting policies affect its more
significant judgements and estimates used in the preparation of its consolidated
financial statements:
Oil and Natural Gas Properties
Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and natural gas properties. The Company capitalized
compensation costs for employees working directly on exploration activities of
$0.9 million, $1.0 million and $1.0 million in 2000, 2001 and 2002,
respectively. Maintenance and repairs are expensed as incurred.
F-8
Oil and natural gas properties are amortized based on the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the projects
can be determined or until they are impaired. Unevaluated properties are
evaluated periodically for impairment on a property-by-property basis. If the
results of an assessment indicate that the properties are impaired, the amount
of impairment is added to the proved oil and natural gas property costs to be
amortized. The amortizable base includes estimated future development costs and,
where significant, dismantlement, restoration and abandonment costs, net of
estimated salvage values. The depletion rate per Mcfe for 2000, 2001 and 2002
was $1.03, $1.15 and $1.41 respectively.
Dispositions of oil and natural gas properties are accounted for as adjustments
to capitalized costs with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and proved
reserves.
The net capitalized costs of proved oil and natural gas properties are subject
to a "ceiling test", which limits such costs to the estimated present value,
discounted at a 10% interest rate, of future net revenues from proved reserves,
based on current economic and operating conditions. If net capitalized costs
exceed this limit, the excess is charged to operations through depreciation,
depletion and amortization. No write-down of the Company's oil and natural gas
assets was necessary in 2000, 2001 or 2002. Based on oil and natural gas prices
in effect on December 31, 2001, the unamortized cost of oil and natural gas
properties exceeded the cost center ceiling. As permitted by full cost
accounting rules, improvements in pricing subsequent to December 31, 2001
removed the necessity to record a write-down. Using prices in effect on December
31, 2001 the pretax write-down would have been approximately $0.7 million.
Because of the volatility of oil and natural gas prices, no assurance can be
given that the Company will not experience a write-down in future periods.
Depreciation of other property and equipment is provided using the straight-line
method based on estimated useful lives ranging from five to 10 years.
OIL AND NATURAL GAS RESERVE ESTIMATES
The process of estimating quantities of proved reserves is inherently uncertain,
and the reserve data included in this document are estimates prepared by Ryder
Scott Company and Fairchild and Wells, Inc., Independent Petroleum Engineers.
Reserve engineering is a subjective process of estimating underground
accumulations of hydrocarbons that cannot be measured in an exact manner. The
process relies on interpretation of available geologic, geophysical, engineering
and production data. The extent, quality and reliability of this data can vary.
The process also requires certain economic assumptions regarding drilling and
operating expense, capital expenditures, taxes and availability of funds. The
SEC mandates some of these assumptions such as oil and natural gas prices and
the present value discount rate.
Proved reserve estimates prepared by others may be substantially higher or lower
than the Company's estimates. Because these estimates depend on many
assumptions, all of which may differ from actual results, reserve quantities
actually recovered may be significantly different than estimated. Material
revisions to reserve estimates may be made depending on the results of drilling,
testing, and rates of production.
You should not assume that the present value of future net cash flows is the
current market value of the Company's estimated proved reserves. In accordance
with SEC requirements, the Company based the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the estimate.
The Company's rate of recording depreciation, depletion and amortization expense
for proved properties is dependent on the Company's estimate of proved reserves.
If these reserve estimates decline, the rate at which the Company records these
expenses will increase.
F-9
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include highly liquid investments with maturities of
three months or less when purchased.
REVENUE RECOGNITION AND NATURAL GAS IMBALANCES
The Company follows the sales method of accounting for revenue recognition and
natural gas imbalances, which recognizes over and under lifts of natural gas
when sold, to the extent sufficient natural gas reserves or balancing agreements
are in place. Natural gas sales volumes are not significantly different from the
Company's share of production.
FINANCING COSTS
Long-term debt financing costs of $0.8 million and $0.8 million are included in
other assets as of December 31, 2001 and 2002, respectively, are being amortized
using the effective yield method over the term of the loans (through January 31,
2005 for a credit facility and through December 15, 2007 for subordinated notes
payable).
SUPPLEMENTAL CASH FLOW INFORMATION
The Statement of Cash Flows for the year ended December 31, 2002 does not
reflect the following non-cash transactions: the $2.5 million of seismic data
acquisitions, the acquisition $0.5 million in oil and natural gas properties
through the issuance of common stock, and the $0.6 million reduction of oil and
natural gas properties for the amount of insurance recoveries expected to be
received related to difficulties encountered in the drilling of a well.
FINANCIAL INSTRUMENTS
The Company's recorded financial instruments consist of cash, receivables,
payables and long-term debt. The carrying amount of cash, receivables and
payables approximates fair value because of the short-term nature of these
items. The carrying amount of bank debt approximates fair value as this
borrowing bears interest at floating market interest rates. The fair value of
the Subordinated Notes payable and the RMG note at December 31, 2002 was $32.6
million and $5.6 million, respectively. Fair values for the Subordinated Notes
payable and the RMG note were determined based upon interest rates available to
the Company at December 31, 2002 with similar terms.
Stock-Based Compensation
The Company accounts for employee stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees" and related interpretations. Under
this method, the Company records no compensation expense for stock options
granted when the exercise price of those options is equal to or greater than the
market price of the Company's common stock on the date of grant. Repriced
options are accounted for as compensatory options using variable accounting
treatment. Under variable plan accounting, compensation expense is adjusted for
increases or decreases in the fair market value of the Company's common stock.
Variable plan accounting is applied to the repriced options until the options
are exercised, forfeited, or expire unexercised.
Derivative Instruments and Hedging Activities
In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards ("SFAS") No. 133 "Accounting for Derivative
Instruments and Hedging Activities". This statement, as amended by SFAS No. 137
and SFAS No. 138, establishes standards of accounting for and disclosures of
derivative instruments and hedging activities. This statement requires all
derivative instruments to be carried on the balance sheet at fair value with
changes in a derivative instrument's fair value recognized currently in earnings
unless specific hedge accounting criteria are met.
F-10
SFAS No. 133 was effective for the Company beginning January 1, 2001 and was
adopted by the Company on that date. In accordance with the current transition
provisions of SFAS No. 133, the Company recorded a cumulative effect transition
adjustment of $2.0 million (net of related tax expense of $1.1 million) in
accumulated other comprehensive income to recognize the fair value of its
derivatives designated as cash flow hedging instruments at the date of adoption.
Upon entering into a derivative contract, the Company designates the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of the
Company's derivative instruments at January 1, 2001, December 31, 2001 and
December 31, 2002 were designated and effective as cash flow hedges except for
its positions with an affiliate of Enron Corp. discussed in Note 12.
When hedge accounting is discontinued because it is probable that a forecasted
transaction will not occur, the derivative will continue to be carried on the
balance sheet at its fair value and gains and losses that were accumulated in
other comprehensive income will be recognized in earnings immediately. In all
other situations in which hedge accounting is discontinued, the derivative will
be carried at fair value on the balance sheet with future changes in its fair
value recognized in future earnings.
The Company typically uses fixed rate swaps and costless collars to hedge its
exposure to material changes in the price of natural gas and oil. The Company
formally documents all relationships between hedging instruments and hedged
items, as well as its risk management objectives and strategy for undertaking
various hedge transactions. This process includes linking all derivatives that
are designated cash flow hedges to forecasted transactions. The Company also
formally assesses, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.
The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.
INCOME TAXES
Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"),
"Accounting for Income Taxes", deferred income taxes are recognized at each
year-end for the future tax consequences of differences between the tax bases of
assets and liabilities and their financial reporting amounts based on tax laws
and statutory tax rates applicable to the periods in which the differences are
expected to affect taxable income. Valuation allowances are established when
necessary to reduce the deferred tax asset to the amount expected to be
realized.
CONCENTRATION OF CREDIT RISK
Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other conditions. Historically,
the Company has not experienced credit losses on such receivables. Derivative
contracts subject the Company to concentration of credit risk. The Company
transacts the majority of its derivative contracts with two counterparties. The
Company does not require collateral from its customers.
F-11
MAJOR CUSTOMERS
The Company sold oil and natural gas production representing more than 10% of
its oil and natural gas revenues for the year ended December 31, 2001 to Cokinos
Natural Gas Company (17%); for the year ended December 31, 2002 to Cokinos
Natural Gas Company (12%) and Discovery Producer Services, LLC (10%). Because
alternate purchasers of oil and natural gas are readily available, the Company
believes that the loss of any of its purchasers would not have a material
adverse effect on the financial results of the Company.
EARNINGS PER SHARE
Supplemental earnings per share information is provided below:
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------------------
INCOME SHARES PER-SHARE AMOUNT
------------------------- ------------------------------------ ---------------------
2000 2001 2002 2000 2001 2002 2000 2001 2002
------- ------ ------ ---------- ---------- ---------- ----- ----- -----
(in thousands except share and per share amounts)
Basic Earnings per
Common Share:
Net income............ $11,985 $9,531 $4,790
Less: Dividends and
Accretion of
Discount on
Preferred Shares.... - - 588
------- ------ ------
Net income available
to common
shareholders...... $11,985 $9,531 $4,202 14,028,176 14,059,151 14,158,438 $0.85 $0.68 $0.30
======= ====== ====== ========== ========== ========== ===== ===== =====
Diluted Earnings per
Common Share:
Net Income............ $11,985 $9,531 $4,790 14,028,176 14,059,151 14,158,438
Less: Dividends and
Accretion of
Discount on
Preferred Shares.... - - 588
Stock Options......... 558,960 807,628 514,077
Warrants.............. 1,668,519 1,864,222 1,475,928
------- ------ ------ ---------- ---------- ----------
Net income available
to common
shareholders...... $11,985 $9,531 $4,202 16,255,655 16,731,001 16,148,443 $0.74 $0.57 $0.26
======= ====== ====== ========== ========== ========== ===== ===== =====
Basic earnings per common share has been computed by dividing net income by the
weighted average number of shares of Common Stock outstanding during the
periods. Diluted earnings per common share is based on the weighted average
number of common shares and all dilutive potential common shares outstanding
during the period. The Company had outstanding 149,000, 79,500 and 172,333 stock
options at December 31, 2000, 2001 and 2002, respectively, that were
antidilutive. The Company had outstanding 252,632 warrants at December 31, 2002
that were antidilutive. These antidilutive stock options and warrants were not
included in the calculation because the exercise price of these instruments
exceeded the underlying market value of the options and warrants as of the dates
presented. The Company had 1,145,515 convertible preferred shares at December
31, 2002 that were antidilutive and were not included in the calculation.
CONTINGENCIES
Liabilities and other contingencies are recognized upon determination of an
exposure, which when analyzed indicates that it is both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimable.
F-12
NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations". This Statement is effective for
fiscal years beginning after June 15, 2002, and the Company will adopt the
Statement effective January 1, 2003. On January 1, 2003, the Company recorded
$0.4 million as proved properties and $0.5 million as a liability for its
plugging and abandonment expenses.
The Company has adopted the disclosure requirements of SFAS No. 148, "Accounting
for Stock Based Compensation--Transition and Disclosure", issued in December
2002, effective with its December 31, 2002 consolidated financial statements and
related footnotes.
3. INVESTMENT IN MICHAEL PETROLEUM CORPORATION
In 2000 the Company received a finder's fee valued at $1.5 million from
affiliates of Donaldson, Lufkin & Jenrette ("DLJ") in connection with their
purchase of a significant minority shareholder interest in Michael Petroleum
Corporation ("MPC"). MPC is a privately held exploration and production company
which focuses on the prolific natural gas producing Lobo Trend in South Texas.
The minority shareholder interest in MPC was purchased by entities affiliated
with DLJ. The Company elected to receive the fee in the form of 18,947 shares of
common stock, 1.9% of the outstanding common shares of MPC, which, until its
sale in 2001, was accounted for as a cost basis investment. Steven A. Webster,
who is the Chairman of the Board of the Company, and a Managing Director of
Global Energy Partners Ltd., a merchant banking affiliate of DLJ which makes
investments in energy companies, joined the Board of Directors of MPC in
connection with the transaction.
In 2001, the Company agreed to sell its interest in MPC pursuant to an agreement
between MPC and its shareholders for the sale of a majority interest in MPC to
Calpine Natural Gas Company. The Company received total cash proceeds of $5.7
million, of which $5.5 million was paid to the Company during the third quarter
of 2001, resulting in a financial statement gain of $3.9 million being reflected
in the third quarter 2001 financial results. The remaining amounts will be paid
in 2003.
4. PROPERTY AND EQUIPMENT
At December 31, 2001 and 2002, property and equipment consisted of the
following:
AS OF DECEMBER 31,
--------------------
2001 2002
-------- --------
(in thousands)
Proved oil and natural gas properties....................... $104,005 $133,032
Unproved oil and natural gas properties..................... 44,416 42,020
Other equipment............................................. 609 685
-------- --------
Total property and equipment.............................. 149,030 175,737
Accumulated depreciation, depletion and amortization........ (44,898) (55,211)
-------- --------
Property and equipment, net................................. $104,132 $120,526
======== ========
Oil and natural gas properties not subject to amortization consist of the cost
of unevaluated leaseholds, seismic costs associated with specific unevaluated
properties, exploratory wells in progress, and secondary recovery projects
before the assignment of proved reserves. These unproved costs are reviewed
periodically by management for impairment, with the impairment provision
included in the cost of oil and natural gas properties subject to amortization.
Factors considered by management in its impairment assessment include drilling
results by the Company and other operators, the terms of oil and natural gas
leases not held by production, production response to secondary recovery
activities and available funds for exploration and development. Of the $42.0
million of unproved property costs at December 31, 2002 being excluded from the
amortizable base, $2.7 million, $11.7 million and $6.3 million were incurred in
2000, 2001 and 2002, respectively and $21.3 million was incurred in prior years.
These costs are primarily seismic and
F-13
lease acquisition costs. The Company expects it will complete its evaluation of
the properties representing the majority of these costs within the next two to
five years.
5. INCOME TAXES
All of the Company's income is derived from domestic activities. Actual income
tax expense differs from income tax expense computed by applying the U.S.
federal statutory corporate rate of 35% to pretax income as follows:
YEAR ENDED DECEMBER 31,
---------------------------
2000 2001 2002
------- ------ ------
(in thousands)
Provision at the statutory tax rate......................... $ 4,546 $5,204 $2,660
Decrease in valuation allowance pertaining to expected net
operating loss utilization................................ (3,644) - -
Other....................................................... 102 132 149
------- ------ ------
Income tax provision........................................ $ 1,004 $5,336 $2,809
======= ====== ======
Deferred income tax provisions result from temporary differences in the
recognition of income and expenses for financial reporting purposes and for tax
purposes. At December 31, 2001 and 2002, the tax effects of these temporary
differences resulted principally from the following:
AS OF DECEMBER 31,
-------------------
2001 2002
------- --------
(in thousands)
Deferred income tax asset:
Net operating loss carryforward........................... $1,797 $ 2,462
Hedge valuation........................................... - 209
------ -------
1,797 2,671
------ -------
Deferred income tax liabilities:
Oil and gas acquisition, exploration and development costs
deducted for tax purposes in excess of financial
statement DD&A......................................... 4,084 6,309
Capitalized interest...................................... 2,734 3,819
------ -------
6,818 10,128
------ -------
Net deferred income tax liability...................... $5,021 $ 7,457
====== =======
The December 31, 2001 deferred income tax asset relating to the net operating
loss carry forward and the deferred income tax liability relating to oil and
natural gas acquisition, exploration and development costs deducted for tax
purposes in excess of financial statement DD&A have been revised to reflect the
2001 results of operations as a reduction of the deferred income tax asset
relating to the net operating loss carry forward. This revision adjustment
resulted in a $1.4 million decrease in the deferred income tax asset relating to
net operating loss carry forward and a corresponding decrease to the deferred
income tax liability relating to oil and natural gas acquisition, exploration
and development costs deducted for tax purposes in excess of financial statement
DD&A. The net effect of these revisions resulted in no change to the net
deferred income tax liability as reflected on the December 31, 2001 balance
sheet.
F-14
The net deferred income tax liability is classified as follows:
AS OF DECEMBER 31,
------------------
2001 2002
------- -------
(in thousands)
Other current assets........................................ $ - $ 209
Deferred income taxes....................................... 5,021 7,666
------ ------
Net deferred income tax liability........................... $5,021 $7,457
====== ======
Realization of the net deferred tax asset is dependent on the Company's ability
to generate taxable earnings in the future. The Company believes it will
generate taxable income in the NOL carryforward period. As such management
believes that it is more likely than not that its deferred tax assets will be
fully realized. The Company has net operating loss carryforwards totaling
approximately $7.0 million, which begin expiring in 2012.
6. LONG-TERM DEBT
At December 31, 2001 and 2002, long-term debt consisted of the following:
AS OF DECEMBER 31,
------------------
2001 2002
------- -------
(in thousands)
Compass Facility............................................ $ 7,166 $ -
Hibernia Facility........................................... - 8,500
Senior subordinated notes, related parties.................. 24,039 25,478
Capital lease obligations................................... 233 267
Non-recourse note payable to RMG............................ 6,750 5,250
------- -------
38,188 39,495
Less: current maturities.................................. (2,107) (1,609)
------- -------
$36,081 $37,886
======= =======
On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a revolving line of credit of up to $30.0 million. It
is secured by substantially all of the Company's assets and is guaranteed by the
Company's subsidiary.
The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The initial borrowing base was
$12.0 million, and the borrowing base as of October 31, 2002 was $13.0 million.
Each party to the credit agreement can request one unscheduled borrowing base
determination subsequent to each scheduled determination. The borrowing base
will at all times equal the borrowing base most recently determined by Hibernia
National Bank, less quarterly borrowing base reductions required subsequent to
such determination. Hibernia National Bank will reset the borrowing base amount
at each scheduled and each unscheduled borrowing base determination date. The
initial quarterly borrowing base reduction, which commenced on June 30, 2002,
was $1.3 million. The quarterly borrowing base reduction effective January 31,
2003 is $1.8 million.
On December 12, 2002, the Company entered into an Amended and Restated Credit
Agreement with Hibernia National Bank that provided additional availability
under the Hibernia Facility in the amount of $2.5 million which is structured as
an additional "Facility B" under the Hibernia Facility. As such, the total
borrowing base under the Hibernia Facility as of December 31, 2002 was $15.5
million, of which $8.5 million is currently drawn. The Facility B bears interest
at LIBOR plus 3.375%, is secured by certain leases and working interests in oil
and natural gas wells and matures on April 30, 2003.
F-15
If the principal balance of the Hibernia Facility ever exceeds the borrowing
base as reduced by the quarterly borrowing base reduction (as described above),
the principal balance in excess of such reduced borrowing base will be due as of
the date of such reduction. Otherwise, any unpaid principal or interest will be
due at maturity.
If the principal balance of the Hibernia Facility ever exceeds any re-determined
borrowing base, the Company has the option within thirty days to (individually
or in combination): (i) make a lump sum payment curing the deficiency; (ii)
pledge additional collateral sufficient in Hibernia National Bank's opinion to
increase the borrowing base and cure the deficiency; or (iii) begin making equal
monthly principal payments that will cure the deficiency within the ensuing
six-month period. Such payments are in addition to any payments that may come
due as a result of the quarterly borrowing base reductions.
For each tranche of principal borrowed under the revolving line of credit, the
interest rate will be, at the Company's option: (i) the Eurodollar Rate, plus an
applicable margin equal to 2.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
90%, but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.
The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders, plus 50% of all positive earning occurring subsequent to such
quarter end, all ratios as more particularly discussed in the credit facility.
The Hibernia Facility also places restrictions on additional indebtedness,
dividends to non-preferred stockholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, change of
control, repurchase or redemption for cash of the Company's common or preferred
stock, speculative commodity transactions, and other matters.
At December 31, 2001, amounts outstanding under the Compass Facility totaled
$7.2 million, with an additional $0.6 million available for future borrowings.
At December 31, 2002, amounts outstanding under the Hibernia Facility totaled
$8.5 million with an additional $4.3 million available for future borrowings. No
amounts under the Compass Facility were outstanding at December 31, 2002. At
December 31, 2001, one letter of credit was issued and outstanding under the
Compass Facility in the amount of $0.2 million. At December 31, 2002, one letter
of credit was issued and outstanding under the Hibernia Facility in the amount
of $0.2 million.
On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"),
issued a non-recourse promissory note payable in the amount of $7.5 million to
RMG as consideration for certain interests in oil and natural gas leases held by
RMG in Wyoming and Montana. The RMG note is payable in 41-monthly principal
payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001
with the balance due December 31, 2004. The RMG note is secured solely by CCBM's
interests in the oil and natural gas leases in Wyoming and Montana. At December
31, 2001 and 2002, the outstanding principal balance of this note was $6.8
million and $5.3 million, respectively.
In December 2001, the Company entered into a capital lease agreement secured by
certain production equipment in the amount of $0.2 million. The lease is payable
in one payment of $11,323 and 35 monthly payments of $7,549 including interest
at 8.6% per annum. In October 2002, the Company entered a capital lease
agreement secured by certain production equipment in the amount of $0.1 million.
The lease is payable in 36 monthly payments of $3,462 including interest at 6.4%
per annum. The Company has the option to acquire the equipment at the conclusion
of the lease for $1, under both leases. DD&A on the capital leases for year
ended December 31, 2002 amounted to $28,000 and accumulated DD&A on the leased
equipment at December 31, 2002 amounted to $28,000.
F-16
In December 1999, the Company consummated the sale of $22.0 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and
$8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2
million, $0.8 million, $0.8 million and $0.8 million principal amount of
Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of
the Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006
Warrants to CB Capital Investors, L.P. (now JPMorgan), Mellon, Paul B. Loyd,
Jr., Steven A. Webster and Douglas A.P. Hamilton, respectively. The Subordinated
Notes were sold at a discount of $0.7 million, which is being amortized over the
life of the notes. Interest payments are due quarterly commencing on March 31,
2000. The Company may elect, for a period of up to five years, to increase the
amount of the Subordinated Notes for 60% of the interest which would otherwise
be payable in cash. As of December 31, 2001 and 2002, the outstanding balance of
the Subordinated Notes had been increased by $2.6 million and $3.9 million,
respectively, for such interest paid in kind.
The Company is subject to certain covenants under the terms under the
Subordinated Notes securities purchase agreement, including but not limited to,
(a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, and (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a JPMorgan appointed director).
Estimated maturities of long-term debt are $1.6 million in 2003, $3.9 million in
2004, $8.5 million in 2005 and the remainder in 2007.
At December 31, 2002, the Company believes it was in compliance with all of its
debt covenants.
7. SEISMIC OBLIGATION PAYABLE
In 2002 the Company acquired (or obtained the right to acquire) certain seismic
data in its core areas in the Texas and Louisiana Gulf Coast regions. Under the
terms of the acquisition agreements, the Company is required to make monthly
payments of $0.1 million through March 2004 and additional payments of $0.8
million are due in April 2004.
8. CONVERTIBLE PARTICIPATING PREFERRED STOCK
In February 2002, the Company consummated the sale of 60,000 shares of
Convertible Participating Series B Preferred Stock (the "Series B Preferred
Stock") and Warrants to purchase Carrizo 252,632 shares of common stock for an
aggregate purchase price of $6.0 million. The Company sold 40,000 and 20,000
shares of Series B Preferred Stock and 168,422 and 84,210 Warrants to Mellon and
Steven A. Webster, respectively. The Series B Preferred Stock is convertible
into common stock by the investors at a conversion price of $5.70 per share,
subject to adjustments, and is initially convertible into 1,052,632 shares of
common stock. Dividends on the Series B Preferred Stock will be payable in
either cash at a rate of 8% per annum or, at the Company's option, by payment in
kind of additional shares of the same series of preferred stock at a rate of 10%
per annum. At December 31, 2002, the outstanding balance of the Series B
Preferred Stock has been increased by $0.5 million (5,294 shares) for dividends
paid in kind. The Series B Preferred Stock is redeemable at varying prices in
whole or in part at the holders' option after three years or at the Company's
option at any time. The Series B Preferred Stock will also participate in any
dividends declared on the common stock. Holders of the Series B Preferred Stock
will receive a liquidation preference upon the liquidation of, or certain
mergers or sales of substantially all assets involving, the Company. Such
holders will also have the option of receiving a change of control repayment
price upon certain deemed change of control transactions. The warrants have a
five-year term and entitle the holders to purchase up to 252,632 shares of
Carrizo's common stock at a price of $5.94 per share, subject to adjustments,
and are exercisable at any time after issuance. The warrants may be exercised on
a cashless exercise basis.
Net proceeds of this financing were approximately $5.8 million and were used
primarily to fund the Company's ongoing exploration and development program and
general corporate purposes.
F-17
9. COMMITMENTS AND CONTINGENCIES
From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position or results of
operations of the Company.
The operations and financial position of the Company continue to be affected
from time to time in varying degrees by domestic and foreign political
developments as well as legislation and regulations pertaining to restrictions
on oil and natural gas production, imports and exports, natural gas regulation,
tax increases, environmental regulations and cancellation of contract rights.
Both the likelihood and overall effect of such occurrences on the Company vary
greatly and are not predictable.
In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in N. La Copita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. The Company, along
with GMT and other partners, reached a final settlement with ExxonMobil on
February 11, 2003. Under the terms of the settlement, the Company recovered the
balance of its drilling costs (approximately $0.1 million) and certain other
costs and retained no further interest in the property. No reserves with respect
to these properties were included in the Company's reported proved reserves as
of December 31, 2001 and 2002.
During August 2001, the Company entered into an agreement whereby the lessor
will provide to the Company up to $0.8 million in financing for production
equipment utilizing capital leases. At December 31, 2002, two leases in the
amount of $0.5 million had been executed under this facility.
At December 31, 2002, the Company was obligated under a noncancelable operating
lease for office space. Rent expense for the years ended December 31, 2000, 2001
and 2002 was $0.2 million. The Company is obligated for remaining lease payments
of $0.2 million per year through December 31, 2004.
CCBM has an obligation to fund $2.5 million of drilling costs on behalf of RMG.
Through December 31, 2002, CCBM has satisfied $1.5 million of its drilling
obligations on behalf of RMG.
10. SHAREHOLDERS' EQUITY
The Company issued 9,016 and 113,306 shares of common stock valued at $28,000
and $0.5 million for the years ended December 31, 2001 and 2002, respectively.
Of these shares, 106,472 were issued as partial consideration for the
acquisition of interests in certain oil and natural gas properties during 2002.
The following table summarizes information for the options outstanding at
December 31, 2002:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------- ----------------------
WEIGHTED NUMBER OF
NUMBER OF AVERAGE WEIGHTED OPTIONS WEIGHTED
OPTIONS REMAINING AVERAGE EXERCISABLE AVERAGE
OUTSTANDING CONTRACTUAL EXERCISE AT EXERCISE
RANGE OF EXERCISE PRICES AT 12/31/02 LIFE IN YEARS PRICE 12/31/02 PRICE
------------------------ ----------- ------------- -------- ----------- --------
$1.75-2.25.......................... 718,870 7.04 $2.19 522,203 $2.17
$3.14-4.00.......................... 341,120 5.34 $3.21 279,453 $3.56
$4.01-5.00.......................... 420,500 8.88 $4.26 136,000 $4.24
$5.17-8.00.......................... 149,833 6.88 $6.71 110,555 $6.72
F-18
In June of 1997, the Company established the Incentive Plan of Carrizo Oil &
Gas, Inc. (the "Incentive Plan"). In October 1995, the FASB issued SFAS No. 123,
"Accounting for Stock-Based Compensation", which requires the Company to record
stock-based compensation at fair value. In December 2002, the FASB issued SFAS
No. 148, "Accounting for Stock Based Compensation--Transition and Disclosure".
The Company has adopted the disclosure requirements of SFAS No. 148 and has
elected to record employee compensation expense utilizing the intrinsic value
method permitted under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees". The Company accounts for its
employees' stock-based compensation plan under APB Opinion No. 25 and its
related interpretations. Accordingly, any deferred compensation expense would be
recorded for stock options based on the excess of the market value of the common
stock on the date the options were granted over the aggregate exercise price of
the options. This deferred compensation would be amortized over the vesting
period of each option. Had compensation cost been determined consistent with
SFAS No. 123 "Accounting for Stock Based Compensation" for all options, the
Company's net income (loss) and earnings per share would have been as follows:
2000 2001 2002
-------- -------- -------
(in thousands except per share
amounts)
Net income as reported...................................... $11,985 $ 9,531 $4,790
Less: Total stock-based employee compensation expense
determined under fair value method for all awards, net of
related tax effects....................................... (498) (1,369) (872)
------- ------- ------
Pro forma net income........................................ $11,487 $ 8,162 $3,918
======= ======= ======
Net income per common share, as reported:
Basic..................................................... $ 0.85 $ 0.68 $ 0.30
Diluted................................................... 0.74 0.57 0.26
Pro Forma net income per common share, as if value method
had been applied to all awards:
Basic..................................................... $ 0.82 $ 0.58 $ 0.28
Diluted................................................... 0.71 0.49 0.24
The fair value of each option grant was estimated on the date of grant using the
Black-Scholes option pricing model with the following assumptions used for
grants in 2000, 2001 and 2002: risk free interest rate of 6.7%, 4.9% and 4.8%,
respectively, expected dividend yield of 0%, expected life of 10 years and
expected volatility of 70.8%, 80.7% and 77.7% respectively.
The Company may grant options ("Incentive Plan Options") to purchase up to
1,850,000 shares under the Incentive Plan and has granted options on 1,566,000
shares through December 31, 2002. Through
F-19
December 31, 2002, 56,797 stock options had been exercised. A summary of the
status of the Company's stock options at December 31, 2000, 2001 and 2002 is
presented in the table below:
2000
---------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- -------- -------------
Outstanding at beginning of year................... 827,120 $6.01 $1.75 - $8.00
Granted (Incentive Plan Options)................... 425,000 $3.85 $2.20 - $8.00
Exercised (Pre-IPO Options)........................ (3,000) $3.60 $3.60
Exercised (Incentive Plan Options)................. (40,697) $2.20 $2.00 - $6.00
Expired (Incentive Plan Options)................... (2,000) $3.50 $3.50
---------- -----
Outstanding at end of year......................... 1,206,423 $5.20 $2.00 - $8.00
========== =====
Exercisable at end of year......................... 316,388 $3.79
========== =====
Weighted average of fair value of options granted
during the year.................................. $ 2.94
==========
2001
---------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- -------- -------------
Outstanding at beginning of year................... 1,206,423 $5.20 $1.75 - $8.00
Granted (Incentive Plan Options)................... 436,500 $4.34 $4.01 - $7.40
Exercised (Pre-IPO Options)........................ (3,000) $3.60 $3.60
Exercised (Incentive Plan Options)................. (3,266) $2.13 $2.00 - $2.25
---------- -----
Outstanding at end of year......................... 1,636,657 $3.49 $1.75 - $8.00
========== =====
Exercisable at end of year......................... 625,701 $3.45
========== =====
Weighted average of fair value of options granted
during the year.................................. $ 3.57
==========
2002
---------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- -------- -------------
Outstanding at beginning of year................... 1,636,657 $3.49 $1.75 - $8.00
Granted (Incentive Plan Options)................... 54,500 $4.31 $3.76 - $5.37
Exercised (Incentive Plan Options)................. (6,834) $2.12 $2.00 - $2.25
Expired (Incentive Plan Options)................... (54,000) $6.38 $1.75 - $8.00
---------- -----
Outstanding at end of year......................... 1,630,323 $3.35 $1.75 - $8.00
========== =====
Exercisable at end of year......................... 1,048,212 $3.28
========== =====
Weighted average of fair value of options granted
during the year.................................. $ 3.57
==========
F-20
In March of 2000, the FASB issued Interpretation No. 44 "Accounting for Certain
Transactions involving Stock Compensation--an interpretation of APB No. 25"
("the Interpretation") which was effective July 1, 2000 and clarifies the
application of APB No. 25 for certain issues associated with the issuance or
subsequent modifications of stock compensation. For certain modifications,
including stock option repricings made subsequent to December 15, 1998, the
Interpretation requires that variable plan accounting be applied to those
modified awards prospectively from July 1, 2000. This requires that the change
in the intrinsic value of the modified awards be recognized as compensation
expense. On February 17, 2000, Carrizo repriced certain employee and director
stock options covering 348,500 shares of stock with a weighted average exercise
price of $9.13 to a new exercise price of $2.25 through the cancellation of
existing options and issuance of new options at current market prices.
Subsequent to the adoption of the Interpretation, the Company is required to
record the effects of any changes in its stock price over the remaining vesting
period through February 2010 on the corresponding intrinsic value of the
repriced options in its results of operations as compensation expense until the
repriced options either are exercised or expire. Stock option compensation
expense (benefit) relating to the repriced options for the years ended December
31, 2001 and 2002 amounted to $(0.6 million) and $(0.1 million), respectively.
11. RELATED-PARTY TRANSACTIONS
During the years ended December 31, 2001 and 2002, the Company incurred drilling
costs in the amount of $6.3 million and $2.9 million, respectively, with Grey
Wolf Drilling. Mr. Webster is the Chairman of the Board of Carrizo and a member
of the Board of Directors of Grey Wolf Drilling. It is management's opinion that
these transactions with Grey Wolf were performed at prevailing market rates.
At December 31, 2002, the Company had outstanding related party accounts
receivable, payable and advances for joint operations balances of $1.2 million,
$1.2 million and $0.3 million, respectively.
During the years ended December 31, 2001 and 2002, the Company participated in
the drilling of two wells and one well, respectively, that were operated by a
subsidiary of Brigham Exploration Company. During the year ended December 31,
2002, Brigham Exploration Company ("Brigham") participated in the drilling of
two wells operated by the Company. Mr. Webster is a member of the Board of
Directors of Brigham. Mr. Webster is also a managing director of a merchant
banking affiliate of the beneficial owner of approximately 35% of the common
stock of the parent company of Brigham Oil and Gas, LP. The terms of the
operating agreements between the Company and Brigham are consistent with
standard industry practices.
During the year ended December 31, 2002, the Company sold a 2% working interest
in certain leases in Matagorda County, TX to Mr. Webster. The terms of the sale
were the same as other sales of working interests in the same leases to industry
partners.
See Notes 6 and 8 for a discussion of the Subordinated Notes and Series B
Preferred Stock, respectively, with parties that include members of the
Company's Board of Directors.
In December 1999, the Company reduced the exercise price of certain warrants
originally issued to affiliates of Enron Corp. in January 1998. There were
250,000 of these warrants that expire in January 2005 to purchase the Company's
common stock at $4.00 per share outstanding as of December 31, 2001 and 2002.
12. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
The Company's operations involve managing market risks related to changes in
commodity prices. Derivative financial instruments, specifically swaps, futures,
options and other contracts, are used to reduce and manage those risks. The
Company addresses market risk by selecting instruments whose value fluctuations
correlate strongly with the underlying commodity being hedged. The Company
enters into swaps, options, collars and other derivative contracts to hedge the
price risks associated with a portion of anticipated future oil and natural gas
production. While the use of hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. Under
F-21
these agreements, payments are received or made based on the differential
between a fixed and a variable product price. These agreements are settled in
cash at expiration or exchanged for physical delivery contracts. The Company
enters into the majority of its hedging transactions with two counterparties and
a netting agreement is in place with those counterparties. The Company does not
obtain collateral to support the agreements but monitors the financial viability
of counterparties and believes its credit risk is minimal on these transactions.
In the event of nonperformance, the Company would be exposed to price risk. The
Company has some risk of accounting loss since the price received for the
product at the actual physical delivery point may differ from the prevailing
price at the delivery point required for settlement of the hedging transaction.
In November 2001, the Company had no-cost collars with an affiliate of Enron
Corp., designated as hedges, covering 2,553,000 MMBtu of natural gas production
from December 2001 through December 2002. The value of these derivatives at that
time was $0.8 million. Because of Enron's financial condition, the Company
concluded that the derivatives contracts were no longer effective and thus did
not qualify for hedge accounting treatment. As required by SFAS No. 133, the
value of these derivative instruments as of November 2001 $(0.8 million) was
recorded in accumulated other comprehensive income and will be reclassified into
earnings over the original term of the derivative instruments. An allowance for
the related asset totalling $0.8 million, net of tax of $0.4 million, was
charged to other expense. At December 31, 2001, $0.7 million, net of tax of $0.4
million, remained in accumulated other comprehensive income related to the
deferred gains on these derivatives. The remaining balance in other
comprehensive income was reported as oil and natural gas revenues in 2002 as the
terms of the original derivative expired.
As of December 31, 2002, $0.4 million, net of tax of $0.2 million, remained in
accumulated other comprehensive income related to the valuation of the Company's
hedging positions.
Total oil purchased and sold under swaps and collars during 2000, 2001 and 2002
were 87,900 Bbls, 18,000 Bbls and 131,300 Bbls, respectively. Total natural gas
purchased and sold under swaps and collars in 2000, 2001 and 2002 were 1,590,000
MMBtu and 3,087,000 MMBtu and 2,314,000 MMBtu, respectively. The net gains and
(losses) realized by the Company under such hedging arrangements were $(1.5
million), $2.0 million and $(0.9 million) for 2000, 2001 and 2002, respectively,
and are included in oil and natural gas revenues.
At December 31, 2001 the Company had no derivative instruments outstanding
designated as hedge positions. At December 31, 2002 the Company had the
following outstanding hedge positions:
DECEMBER 31, 2002
------------------------------------------------------------
CONTRACT VOLUMES
---------------- AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ ------- ----------- ----------- -------------
First Quarter 2003................... 27,000 $24.85
First Quarter 2003................... 36,000 $23.50 $26.50
First Quarter 2003................... 540,000 3.40 5.25
Second Quarter 2003.................. 27,300 24.85
Second Quarter 2003.................. 36,000 23.50 26.50
Second Quarter 2003.................. 546,000 3.40 5.25
Third Quarter 2003................... 552,000 3.40 5.25
Fourth Quarter 2003.................. 552,000 3.40 5.25
13. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
The following disclosures provide unaudited information required by SFAS No. 69,
"Disclosures About Oil and Gas Producing Activities".
F-22
COSTS INCURRED
Costs incurred in oil and natural gas property acquisition, exploration and
development activities are summarized below:
YEAR ENDED DECEMBER 31,
---------------------------
2000 2001 2002
------- ------- -------
(in thousands)
Property acquisition costs
Unproved.................................................. $ 6,641 $12,607 $ 6,402
Proved.................................................... 337 800 660
Exploration cost............................................ 7,843 18,356 14,194
Development costs........................................... 1,361 3,065 2,351
------- ------- -------
Total costs incurred(1)................................ $16,182 $34,828 $23,607
======= ======= =======
---------------------------
(1) Excludes capitalized interest on unproved properties of $3.6 million, $3.2
million and $3.1 million for the years ended December 31, 2000, 2001 and
2002, respectively.
OIL AND NATURAL GAS RESERVES
Proved reserves are estimated quantities of oil and natural gas which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Proved developed reserves are proved reserves that can reasonably be
expected to be recovered through existing wells with existing equipment and
operating methods.
Proved oil and natural gas reserve quantities at December 31, 2001 and 2002, and
the related discounted future net cash flows before income taxes are based on
estimates prepared by Ryder Scott Company and Fairchild and Wells, Inc.,
independent petroleum engineers. Such estimates have been prepared in accordance
with guidelines established by the Securities and Exchange Commission.
The Company's net ownership interests in estimated quantities of proved oil and
natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below:
THOUSANDS OF BARRELS OF
OIL AND CONDENSATE
AT DECEMBER 31,
------------------------
2000 2001 2002
------ ------ ------
Proved developed and undeveloped reserves--
Beginning of year......................................... 4,877 6,397 6,857
Discoveries and extensions................................ 93 600 369
Revisions................................................. 1,625 20 1,568
Sales of oil and gas properties in place.................. - - (12)
Production................................................ (198) (160) (401)
----- ----- -----
End of year................................................. 6,397 6,857 8,381
===== ===== =====
Proved developed reserves at beginning of year.............. 1,070 1,017 1,158
===== ===== =====
Proved developed reserves at end of year.................... 1,017 1,158 1,393
===== ===== =====
F-23
MILLIONS OF CUBIC FEET
OF NATURAL GAS
AT DECEMBER 31,
------------------------
2000 2001 2002
------ ------ ------
Proved developed and undeveloped reserves--
Beginning of year......................................... 11,323 10,992 17,858
Purchases of oil and gas properties in place.............. - - 585
Discoveries and extensions................................ 4,179 12,560 3,280
Revisions................................................. 1,553 (1,262) (3,726)
Sales of oil and gas properties in place.................. (603) - (274)
Production................................................ (5,460) (4,432) (4,801)
------ ------ ------
End of year................................................. 10,992 17,858 12,922
====== ====== ======
Proved developed reserves at beginning of year.............. 10,680 10,351 13,754
====== ====== ======
Proved developed reserves at end of year.................... 10,351 13,754 12,826
====== ====== ======
STANDARDIZED MEASURE
The standardized measure of discounted future net cash flows relating to the
Company's ownership interests in proved oil and natural gas reserves as of
year-end is shown below:
YEAR ENDED DECEMBER 31,
------------------------------
2000 2001 2002
-------- -------- --------
(in thousands)
Future cash inflows....................................... $266,725 $169,856 $305,087
Future oil and natural gas operating expenses............. 126,526 76,348 138,106
Future development costs.................................. 14,284 16,083 15,259
Future income tax expenses................................ 25,242 5,822 32,133
-------- -------- --------
Future net cash flows..................................... 100,673 71,603 119,589
10% annual discount for estimating timing of cash flows... 30,567 27,026 54,292
-------- -------- --------
Standard measure of discounted future net cash flows...... $ 70,106 $ 44,577 $ 65,297
======== ======== ========
Future cash flows are computed by applying year-end prices of oil and natural
gas to year-end quantities of proved oil and natural gas reserves. Average
prices used in computing year end 2000, 2001 and 2002 future cash flows were
$24.85, $17.71 and $29.16 for oil, respectively and $10.34, $2.76 and $4.70 for
natural gas, respectively. Future operating expenses and development costs are
computed primarily by the Company's petroleum engineers by estimating the
expenditures to be incurred in developing and producing the Company's proved oil
and natural gas reserves at the end of the year, based on year end costs and
assuming continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for tax
basis and availability of applicable tax assets. A discount factor of 10% was
used to reflect the timing of future net cash flows. The standardized measure of
discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company's oil and natural gas properties. An
estimate of fair value would also take into account, among other things, the
recovery of reserves not presently classified as proved, anticipated future
changes in prices and costs, and a discount factor more representative of the
time value of money and the risks inherent in reserve estimates.
F-24
CHANGE IN STANDARDIZED MEASURE
Changes in the standardized measure of future net cash flows relating to proved
oil and natural gas reserves are summarized below:
YEAR ENDED DECEMBER 31,
------------------------------
2000 2001 2002
-------- -------- --------
(in thousands)
Changes due to current-year operations--
Sales of oil and natural gas, net of oil and natural gas
operating expenses................................... $(21,893) $(23,622) $(23,377)
Extensions and discoveries.............................. 26,214 28,009 20,680
Purchases of oil and gas properties..................... - - 888
Changes due to revisions in standardized variables
Prices and operating expenses........................... 16,686 (38,472) 37,023
Income taxes............................................ (14,090) 13,367 (14,692)
Estimated future development costs...................... (1,122) (1,070) 417
Revision of quantities.................................. 2,921 (1,109) 8,910
Sales of reserves in place.............................. (254) - (191)
Accretion of discount................................... 4,736 8,768 4,820
Production rates, timing and other...................... 14,178 (11,400) (13,758)
-------- -------- --------
Net change................................................ 27,376 (25,529) 20,720
Beginning of year......................................... 42,730 70,106 44,577
-------- -------- --------
End of year............................................... $ 70,106 $ 44,577 $ 65,297
======== ======== ========
Sales of oil and natural gas, net of oil and natural gas operating expenses, are
based on historical pretax results. Sales of oil and natural gas properties,
extensions and discoveries, purchases of minerals in place and the changes due
to revisions in standardized variables are reported on a pretax discounted
basis, while the accretion of discount is presented on an after-tax basis.
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
FIRST SECOND THIRD FOURTH
-------- -------- -------- --------
(unaudited)
(in thousands except per share amounts)
2002
Revenues............................................... $4,027 $6,780 $6,752 $9,243
Costs and expenses, net................................ 3,883 5,706 5,576 6,847
------ ------ ------ ------
Net income............................................. 144 1,074 1,176 2,396
Dividends and accretion................................ 74 168 173 173
------ ------ ------ ------
Net income available to common shareholders............ $ 70 $ 906 $1,003 $2,223
====== ====== ====== ======
Basic net income per share(1).......................... $ 0.00 $ 0.06 $ 0.07 $ 0.30
====== ====== ====== ======
Diluted net income per share(1)........................ $ 0.00 $ 0.06 $ 0.06 $ 0.26
====== ====== ====== ======
2001
Revenues............................................... $8,727 $7,092 $6,162 $4,245
Costs and expenses, net................................ 5,263 4,792 2,616 4,023
------ ------ ------ ------
Net income............................................. $3,464 $2,300 $3,546 $ 222
====== ====== ====== ======
Basic net income per share(1).......................... $ 0.25 $ 0.16 $ 0.25 $ 0.02
====== ====== ====== ======
Diluted net income per share(1)........................ $ 0.21 $ 0.14 $ 0.22 $ 0.01
====== ====== ====== ======
---------------------------
(1) The sum of individual quarterly net income per common share may not agree
with year-to-date net income per common share as each period's computation
is based on the weighted average number of common shares outstanding during
that period.
F-25
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, SEPTEMBER 30,
2002 2003
------------ -------------
(unaudited)
(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 4,743 $ 4,426
Accounts receivable, trade (net of allowance for doubtful
accounts of $0.5 million at December 31, 2002 and
September 30, 2003, respectively)...................... 8,207 8,643
Advances to operators..................................... 501 2,697
Other current assets...................................... 651 92
-------- --------
Total current assets................................... 14,102 15,858
PROPERTY AND EQUIPMENT, net (full-cost method of accounting
for oil and natural gas properties)....................... 120,526 124,030
Investment in Pinnacle Gas Resources, Inc. (Note 4)......... - 7,101
Deferred financing costs.................................... 760 646
-------- --------
$135,388 $147,635
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade................................... $ 9,957 $ 13,502
Accrued liabilities....................................... 1,014 1,466
Advances for joint operations............................. 1,550 3,222
Current maturities of long-term debt...................... 1,609 811
Current maturities of seismic obligation payable.......... 1,414 1,456
-------- --------
Total current liabilities.............................. 15,544 20,457
LONG-TERM DEBT.............................................. 37,886 34,154
SEISMIC OBLIGATION PAYABLE.................................. 1,103 -
ASSET RETIREMENT OBLIGATION................................. - 704
DEFERRED INCOME TAXES....................................... 7,666 11,326
COMMITMENTS AND CONTINGENCIES (Note 7)
CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000 shares
of preferred stock authorized, of which 150,000 are shares
designated as convertible participating shares, with
65,294 and 68,559 convertible participating shares issued
and outstanding at December 31, 2002 and September 30,
2003, respectively) (Note 8).............................. 6,373 6,925
SHAREHOLDERS' EQUITY:
Warrants (3,262,821 outstanding at December 31, 2002 and
September 30, 2003, respectively)...................... 780 780
Common stock, par value $.01 (40,000,000 shares authorized
with 14,177,383 and 14,385,551 issued and outstanding
at December 31, 2002 and September 30, 2003,
respectively).......................................... 142 144
Additional paid in capital................................ 63,224 63,821
Retained earnings......................................... 3,058 9,391
Accumulated other comprehensive loss...................... (388) (67)
-------- --------
66,816 74,069
-------- --------
$135,388 $147,635
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-26
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE FOR THE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------- -----------------
2002 2003 2002 2003
------ ------- ------- -------
(unaudited)
(in thousands except per share
amounts)
OIL AND NATURAL GAS REVENUES................................ $6,753 $10,123 $17,559 $29,615
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of
depreciation shown separately below).................... 1,334 1,587 3,687 5,071
Depreciation, depletion and amortization.................. 2,726 3,086 7,332 8,727
General and administrative................................ 990 1,624 3,049 4,274
Accretion expense related to asset retirement
obligations............................................. - 11 - 29
Stock option compensation................................. (14) 296 (70) 319
------ ------- ------- -------
Total costs and expenses.................................... 5,036 6,604 13,998 18,420
------ ------- ------- -------
OPERATING INCOME............................................ 1,717 3,519 3,561 11,195
OTHER INCOME AND EXPENSES:
Equity in loss of Pinnacle Gas Resources, Inc............. - (168) - (177)
Other income and expenses................................. 117 (17) 245 14
Interest income........................................... 16 13 44 50
Interest expense.......................................... (58) (103) (169) (419)
Interest expense, related parties......................... (590) (599) (2,023) (1,773)
Capitalized interest...................................... 648 696 2,192 2,176
------ ------- ------- -------
INCOME BEFORE INCOME TAXES.................................. 1,850 3,341 3,850 11,066
INCOME TAXES (Note 6)....................................... 674 1,259 1,456 4,053
------ ------- ------- -------
NET INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE................................................. 1,176 2,082 2,394 7,013
DIVIDENDS AND ACCRETION ON PREFERRED STOCK.................. 173 190 415 552
------ ------- ------- -------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS BEFORE
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE....... 1,003 1,892 1,979 6,461
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE......... - - - 128
------ ------- ------- -------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS................. $1,003 $ 1,892 $ 1,979 $ 6,333
====== ======= ======= =======
BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE............................ $ 0.07 $ 0.13 $ 0.14 $ 0.46
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF
INCOME TAXES.............................................. - - - (0.01)
------ ------- ------- -------
BASIC EARNINGS PER COMMON SHARE............................. $ 0.07 $ 0.13 $ 0.14 $ 0.45
====== ======= ======= =======
DILUTED EARNINGS PER COMMON SHARE BEFORE CUMULATIVE EFFECT
OF CHANGE IN ACCOUNTING PRINCIPLE......................... $ 0.06 $ 0.11 $ 0.12 $ 0.39
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF
INCOME TAXES.............................................. - - - (0.01)
------ ------- ------- -------
DILUTED EARNINGS PER COMMON SHARE........................... $ 0.06 $ 0.11 $ 0.12 $ 0.38
====== ======= ======= =======
PRO FORMA AMOUNTS ASSUMING ASSET
RETIREMENTS OBLIGATION IS APPLIED RETROACTIVELY:
BASIC EARNINGS PER COMMON SHARE........................... $ 0.07 $ 0.13 $ 0.14 $ 0.46
====== ======= ======= =======
DILUTED EARNINGS PER COMMON SHARE......................... $ 0.06 $ 0.11 $ 0.12 $ 0.39
====== ======= ======= =======
The accompanying notes are an integral part of these consolidated financial
statements.
F-27
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
FOR THE NINE MONTHS
ENDED SEPTEMBER 30,
-------------------
2002 2003
---- ----
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income before cumulative effect of change in
accounting principle................................... $ 2,394 $ 7,013
Adjustment to reconcile net income to net cash provided by
operating activities-
Depreciation, depletion and amortization............... 7,332 8,727
Discount accretion..................................... 64 93
Equity in loss of Pinnacle Gas Resources, Inc.......... - 177
Ineffective derivative instruments..................... (548) -
Interest payable in kind............................... 1,008 1,063
Stock option compensation (benefit).................... (70) 319
Deferred income taxes.................................. 1,333 3,918
Changes in assets and liabilities-
Accounts receivable.................................... 1,302 (436)
Other assets........................................... (744) 326
Accounts payable....................................... 107 1,682
Other liabilities...................................... 161 627
-------- --------
Net cash provided by operating activities............ 12,339 23,509
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures...................................... (20,854) (20,368)
Change in capital expenditure accrual..................... 3,496 1,864
Advances to operators..................................... (33) (2,196)
Advances for joint operations............................. 647 1,672
-------- --------
Net cash used in investing activities................ (16,744) (19,028)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from the sale of common stock................ 13 599
Net proceeds from the sale of preferred stock............. 5,785 -
Net proceeds from the sale of warrants.................... 15 -
Advances under Borrowing Base Credit Facility............. 6,500 -
Debt repayments........................................... (8,346) (5,397)
-------- --------
Net cash provided by (used in) financing
activities.......................................... 3,967 (4,798)
-------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ (438) (317)
CASH AND CASH EQUIVALENTS, beginning of period.............. 3,236 4,743
-------- --------
CASH AND CASH EQUIVALENTS, end of period.................... $ 2,798 $ 4,426
======== ========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized)....... $ - $ -
======== ========
Cash paid for income taxes................................ $ - $ -
======== ========
Common stock issued for oil and gas property (Note 8)..... $ 475 $ -
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-28
CARRIZO OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. ACCOUNTING POLICIES
The consolidated financial statements included herein have been prepared by
Carrizo Oil & Gas, Inc. (the Company), and are unaudited, except for the balance
sheet at December 31, 2002, which has been prepared from the audited financial
statements at that date. The financial statements reflect the accounts of the
Company and its subsidiary after elimination of all significant intercompany
transactions and balances. The financial statements reflect necessary
adjustments, all of which were of a recurring nature, and are in the opinion of
management necessary for a fair presentation. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been omitted pursuant to the
rules and regulations of the Securities and Exchange Commission (SEC). The
Company believes that the disclosures presented are adequate to allow the
information presented not to be misleading. The financial statements included
herein should be read in conjunction with the audited financial statements and
notes thereto included in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002.
2. MAJOR CUSTOMERS
The Company sold oil and natural gas production representing more than 10% of
its oil and natural gas revenues for the nine months ended September 30, 2002 to
Cokinos Natural Gas Company (11%); for the nine months ended September 30, 2003
to Gulfmark Energy, Inc. (17%), Cokinos Natural Gas Company (15%) and WMJ
Investments Corp. (14%). Because alternate purchasers of oil and natural gas are
readily available, the Company believes that the loss of any of its purchaser
would not have a material adverse effect on the financial results of the
Company.
3. EARNINGS PER COMMON SHARE
Supplemental earnings per share information is provided below:
FOR THE THREE MONTHS ENDED SEPTEMBER 30,
---------------------------------------------------------
PER-SHARE
INCOME SHARES AMOUNT
--------------- ----------------------- -------------
2002 2003 2002 2003 2002 2003
------ ------ ---------- ---------- ----- -----
(in thousands except share and per share amounts)
Net income....................... $1,176 $2,082
Less: Dividends and Accretion of
Discount on Preferred Shares... (173) (190)
------ ------
Basic Earnings per Share
Net income available to common
shareholders................ 1,003 1,892 14,176,528 14,264,639 $0.07 $0.13
===== =====
Dilutive effect of Stock Options,
Warrants and Preferred Stock
conversions................. - - 1,725,826 2,625,991
------ ------ ---------- ----------
Diluted Earnings per Share
Net income available to common
shareholders plus assumed
conversions................. $1,003 $1,892 15,902,354 16,890,630 $0.06 $0.11
====== ====== ========== ========== ===== =====
F-29
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
------------------------------------------------------------
INCOME SHARES PER-SHARE AMOUNT
--------------- ----------------------- ----------------
2002 2003 2002 2003 2002 2003
------ ------ ---------- ---------- ------ ------
(in thousands except share and per share amounts)
Net income before cumulative
effect of change in accounting
principle..................... $2,394 $7,013
Less: Dividends and Accretion of
Discount on Preferred
Shares........................ (415) (552)
------ ------
Basic Earnings per Share
Net income available to common
shareholders............... 1,979 6,461 14,152,239 14,224,893 $0.14 $0.46
===== =====
Dilutive effect of Stock
Options, Warrants and
Preferred Stock conversions... - - 1,776,091 2,349,345
------ ------ ---------- ----------
Diluted Earnings per Share
Net income available to common
shareholders plus assumed
conversions................ $1,979 $6,461 15,928,330 16,574,238 $0.12 $0.39
====== ====== ========== ========== ===== =====
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
----------------------------------------------------------
INCOME SHARES PER-SHARE AMOUNT
------------ ----------------------- -----------------
2002 2003 2002 2003 2002 2003
---- ----- ---------- ---------- ------ -------
(in thousands except share and per share amounts)
Cumulative effect of change in
accounting principle net of
income taxes................... $ - $(128)
Basic Earnings per Share
Net loss available to common
shareholders................ - - 14,152,239 14,224,893 $0.00 $(0.01)
===== ======
Dilutive effect of Stock Options,
Warrants and Preferred Stock
conversions.................... - - 1,776,091 2,349,345
--- ----- ---------- ----------
Diluted Earnings per Share
Net income available to common
shareholders plus assumed
conversions................. $ - $(128) 15,928,330 16,574,238 $0.00 $(0.01)
=== ===== ========== ========== ===== ======
F-30
FOR THE NINE MONTHS ENDED SEPTEMBER 30,
------------------------------------------------------------
INCOME SHARES PER-SHARE AMOUNT
--------------- ----------------------- ----------------
2002 2003 2002 2003 2002 2003
------ ------ ---------- ---------- ------ ------
(in thousands except share and per share amounts)
Net income...................... $2,394 $6,885
Less: Dividends and Accretion of
Discount on Preferred
Shares........................ (415) (552)
------ ------
Basic Earnings per Share
Net income available to common
shareholders............... 1,979 6,333 14,152,239 14,224,893 $0.14 $0.45
===== =====
Dilutive effect of Stock
Options, Warrants and
Preferred Stock conversions... - - 1,776,091 2,349,345
------ ------ ---------- ----------
Diluted Earnings per Share
Net income available to common
shareholders plus assumed
conversions................ $1,979 $6,333 15,928,330 16,574,238 $0.12 $0.38
====== ====== ========== ========== ===== =====
Basic earnings per common share is based on the weighted average number of
shares of common stock outstanding during the periods. Diluted earnings per
common share is based on the weighted average number of common shares and all
dilutive potential common shares outstanding during the periods. The Company had
outstanding 393,833 and 57,000 stock options and 252,632 and zero warrants
during the three months ended September 30, 2002 and 2003, respectively, which
were antidilutive and were not included in the calculation because the exercise
price of these instruments exceeded the underlying market value of the options
and warrants. The Company had outstanding 406,833 and 129,000 stock options and
252,632 warrants during the nine months ended September 30, 2002 and 2003,
respectively, which were antidilutive and were not included in the calculation
because the exercise price of these instruments exceeded the underlying market
value of the options and warrants. At September 30, 2002 and 2003, the Company
also had 1,090,649 and 1,202,791 shares, respectively, based on the assumed
conversion of the Series B Convertible Participating Preferred Stock, that were
antidilutive and were not included in the calculation.
4. INVESTMENT IN PINNACLE GAS RESOURCES, INC.
THE PINNACLE TRANSACTION
On June 23, 2003, pursuant to a Subscription and Contribution Agreement by and
among the Company and its wholly-owned subsidiary, CCBM, Inc. ("CCBM"), Rocky
Mountain Gas, Inc. ("RMG") and the Credit Suisse First Boston Private Equity
entities, named therein (the "CSFB Parties"), CCBM and RMG contributed their
respective interests, having a estimated fair value of approximately $7.5
million each, in (1) leases in the Clearmont, Kirby, Arvada and Bobcat project
areas and (2) oil and gas reserves in the Bobcat project area to a newly formed
entity, Pinnacle Gas Resources, Inc., a Delaware corporation ("Pinnacle"). In
exchange for the contribution of these assets, CCBM and RMG each received 37.5%
of the common stock of Pinnacle ("Pinnacle Common Stock") as of the closing date
and options to purchase Pinnacle Common Stock ("Pinnacle Stock Options"). CCBM
no longer has a drilling obligation in connection with the oil and natural gas
leases contributed to Pinnacle (see "General Overview" in Management's
Discussion and Analysis of Financial Condition and Results of Operations for a
further discussion).
Simultaneously with the contribution of these assets, the CSFB Parties
contributed approximately $17.6 million of cash to Pinnacle in return for the
Redeemable Preferred Stock of Pinnacle ("Pinnacle Preferred Stock"), 25% of the
Pinnacle Common Stock as of the closing date and warrants to purchase Pinnacle
Common Stock ("Pinnacle Warrants"). The CSFB Parties also agreed to contribute
additional cash, under certain circumstances, of up to approximately $11.8
million to Pinnacle to fund future drilling,
F-31
development and acquisitions. The CSFB Parties currently have greater than 50%
of the voting power of the Pinnacle capital stock through their ownership of
Pinnacle Common Stock and Pinnacle Preferred Stock.
Currently, on a fully diluted basis, assuming that all parties exercised their
Pinnacle Warrants and Pinnacle Options, the CSFB Parties, CCBM and RMG would
have ownership interests of approximately 46.2%, 26.9% and 26.9%, respectively.
On a fully-diluted basis, assuming the additional $11.8 million of cash was
contributed by the CSFB Parties and all Pinnacle Warrants and Pinnacle Options
were exercised by all parties, the CSFB Parties would own 54.6% of Pinnacle and
CCBM and RMG would each own 22.7% of Pinnacle.
Immediately following the contribution and funding, Pinnacle used approximately
$6.2 million of the proceeds from the funding to acquire an approximate 50%
working interest in existing leases and approximately 36,529 gross acres
prospective for coalbed methane development in the Powder River Basin of Wyoming
from Gastar Exploration, Ltd. The leases include 95 producing coalbed methane
wells currently in the early stages of dewatering. These wells are producing at
a combined gross rate of approximately 2.5 MMcfd, or an estimated 1 MMcfd net to
Pinnacle. Pinnacle also agreed to fund up to $14.9 million of future drilling
and development costs on these properties on behalf of Gastar prior to December
31, 2005. The drilling and development work will be done under the terms of an
earn-in joint venture agreement between Pinnacle and Gastar. The majority of
these leases are part of, or adjacent to, the Bobcat project area. All of CCBM
and RMG's interests in the Bobcat project area, the only producing coalbed
methane property owned by CCBM prior to the transaction, were contributed to
Pinnacle. As of June 30, 2003, Pinnacle owned interests in approximately 131,000
gross acres in the Powder River Basin.
Prior to and in connection with its contribution of assets to Pinnacle, CCBM
paid RMG approximately $1.8 million in cash as part of its outstanding purchase
obligation on the coalbed methane property interests CCBM previously acquired
from RMG. The approximate $1.0 million remaining balance of CCBM's obligation to
RMG is scheduled to be paid in monthly installments of approximately $52,805
through November 2004 and a balloon payment on December 31, 2004. The RMG note
is secured solely by CCBM's interests in the remaining oil and natural gas
leases in Wyoming and Montana. In connection with the Company's investment in
Pinnacle, the Company received a reduction in the principal amount of the RMG
note of approximately $1.5 million and relinquished the right to receive certain
revenues related to the properties contributed to Pinnacle.
CCBM continues its coalbed methane business activities and, in addition to its
interest in Pinnacle, owns direct interests in approximately 189,000 gross acres
of coalbed methane properties in the Castle Rock project area in Montana and the
Oyster Ridge project area in Wyoming, which were not contributed to Pinnacle.
CCBM and RMG will continue to conduct exploration and development activities on
these properties as well as pursue other potential acquisitions. The Bobcat
property was producing approximately 400 Mcfe of coalbed methane gas net to
CCBM's interest immediately prior to its contribution to Pinnacle. Other than
indirectly through Pinnacle, CCBM currently has no proved reserves of, and is no
longer receiving revenue from, coalbed methane gas.
ACCOUNTING AND TAX TREATMENT
For accounting purposes, the transaction will be treated as a reclassification
of a portion of CCBM's investments in the contributed properties. The property
contribution made by CCBM to Pinnacle is intended to be treated as a
tax-deferred exchange as constituted by property transfers under section 351(a)
of the Internal Revenue Code of 1986, as amended.
The FASB issued Interpretation 46, "Consolidation of Variable Interest Entities"
("FIN 46"), in January 2003. FIN 46 requires the consolidation of certain types
of entities in which a company absorbs a majority of another entity's expected
losses, receives a majority of the other entity's expected residual returns, or
both, as a result of ownership, contractual or other financial interests in the
other entity. These entities are called "variable interest entities". The
provisions of FIN 46 are effective for the Company in the second
F-32
quarter for new transactions or entities formed in 2003 and in the third quarter
for transactions or entities formed prior to 2003.
If an entity is determined to be a "variable interest entity" ("VIE"), the
entity must be consolidated by the "primary beneficiary". The primary
beneficiary is the holder of the variable interests that absorbs a majority of
the variable interest entity's expected losses or receives a majority of the
entity's residual returns in the event no holder has a majority of the expected
losses. The determination of the primary beneficiary is based on projected cash
flows at the inception of the variable interests. Because Steven A. Webster,
Chairman of Carrizo, is also a managing director of Credit Suisse First Boston
(see "Related Parties in the Pinnacle Transaction" below), Carrizo could be
defined as the primary beneficiary if the projected cash flows analysis
indicated losses in excess of the equity invested. The initial determination of
whether an entity is a VIE is to be reconsidered only when one or more of the
following occur (1) the entity's governing documents or the contractual
arrangements among the parties involved change, (2) the equity investment of
some part thereof is returned to the investors, and other parties become exposed
to expected losses or (3) the entity undertakes additional activities or
acquires additional assets that increase the entity's expected losses.
We have determined that we should not consolidate Pinnacle, under FIN 46,
because our current projected cash flow analysis of Pinnacle's operations at
inception indicates that Pinnacle is not a VIE. Accordingly, our investment in
Pinnacle has been recorded using the equity method of accounting.
The reclassification of investments in contributed properties resulting from the
transaction with Pinnacle are reflected in accordance with the full cost method
of accounting in the Company's balance sheet included in this Form 10-Q for the
nine months ended September 30, 2003.
RELATED PARTIES IN THE PINNACLE TRANSACTION
Steven A. Webster, Chairman of the Board of the Company, is also a managing
director of Credit Suisse First Boston Private Equity and is therefore a related
party to this transaction.
TRANSITION SERVICES AGREEMENT
The Company entered into a transition services agreement with Pinnacle pursuant
to which the Company will provide certain accounting, treasury, tax, insurance
and financial reporting functions to Pinnacle through the end of 2003 for a
monthly fee equal to the Company's actual cost to provide such services. After
December 31, 2003, the agreement will automatically renew on a quarterly basis
unless one of the parties gives notice of its intent to terminate the agreement.
Similarly, Pinnacle has also entered into a transition services agreement with
RMG to provide Pinnacle assistance in setting up operational accounting and
management systems for a monthly fee equal to the actual cost to provide such
services. After December 31, 2003, the agreement will automatically renew on a
quarterly basis unless one of the parties gives notice of its intent to
terminate the agreement.
F-33
5. LONG-TERM DEBT
At December 31, 2002 and September 30, 2003, long-term debt consisted of the
following:
DECEMBER 31, SEPTEMBER 30,
2002 2003
------------ -------------
Borrowing base facility..................................... $ 8,500 $ 7,000
Senior subordinated notes, related parties.................. 25,478 26,605
Capital lease obligations................................... 267 338
Non-recourse note payable to Rocky Mountain Gas, Inc. ...... 5,250 1,022
------- -------
39,495 34,965
Less: current maturities.................................... (1,609) (811)
------- -------
$37,886 $34,154
======= =======
On May 24, 2002, the Company entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid its existing facility with Compass Bank (the "Compass Facility"). The
Hibernia Facility provides a revolving line of credit of up to $30.0 million. It
is secured by substantially all of the Company's producing oil and gas
properties assets and is guaranteed by the Company's wholly owned subsidiary
CCBM, Inc.
The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The initial borrowing base was
$12.0 million, and the borrowing base as of September 30, 2003 was $13.5
million. Each party to the credit agreement can request one unscheduled
borrowing base determination subsequent to each scheduled determination. The
borrowing base will at all times equal the borrowing base most recently
determined by Hibernia National Bank, less quarterly borrowing base reductions
required subsequent to such determination. Hibernia National Bank will reset the
borrowing base amount at each scheduled and each unscheduled borrowing base
determination date. The initial quarterly borrowing base reduction, which
commenced on June 30, 2002, was $1.3 million. The quarterly borrowing base
reduction effective January 31, 2003 was $1.8 million. There was an increase in
the borrowing base for the quarter ended June 30, 2003 of $2.2 million.
On December 12, 2002, the Company entered into an Amended and Restated Credit
Agreement with Hibernia National Bank that provided additional availability
under the Hibernia Facility in the amount of $2.5 million which was structured
as an additional "Facility B" under the Hibernia Facility. As such, the total
borrowing base under the Hibernia Facility as of December 31, 2002 and September
30, 2003 was $15.5 million and $13.5 million, respectively, of which $8.5
million and $7.0 million was outstanding on December 31, 2002 and September 30,
2003, respectively. The Facility B bore interest at LIBOR plus 3.375%, was
secured by certain leases and working interests in oil and natural gas wells and
matured on April 30, 2003.
If the principal balance of the Hibernia Facility ever exceeds the borrowing
base as reduced by the quarterly borrowing base reduction (as described above),
the principal balance in excess of such reduced borrowing base will be due as of
the date of such reduction. Otherwise, any unpaid principal or interest will be
due at maturity.
If the principal balance of the Hibernia Facility ever exceeds any re-determined
borrowing base, the Company has the option within thirty days to (individually
or in combination): (i) make a lump sum payment curing the deficiency; (ii)
pledge additional collateral sufficient in Hibernia National Bank's opinion to
increase the borrowing base and cure the deficiency; or (iii) begin making equal
monthly principal payments that will cure the deficiency within the ensuing
six-month period. Such payments are in addition to any payments that may come
due as a result of the quarterly borrowing base reductions.
For each tranche of principal borrowed under the revolving line of credit, the
interest rate will be, at the Company's option: (i) the Eurodollar Rate, plus an
applicable margin equal to 2.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than
F-34
90% but greater than or equal to 50% of the borrowing base, or 1.625% if the
amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate,
plus an applicable margin of 0.375% if the amount borrowed is greater than or
equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.
The Company is subject to certain covenants under the terms of the Hibernia
Facility, including, but not limited to the maintenance of the following
financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (ii) a minimum quarterly debt services
coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders, plus 50% of all positive earning occurring subsequent to such
quarter end, all ratios as more particularly discussed in the credit facility.
The Hibernia Facility also places restrictions on additional indebtedness,
dividends to non-preferred stockholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, change of
control, repurchase or redemption for cash of the Company's common or preferred
stock, speculative commodity transactions, and other matters.
At December 31, 2002 and September 30, 2003, amounts outstanding under the
Hibernia Facility totaled $8.5 million and $7.0 million, respectively, with an
additional $4.3 million and $6.5 million, respectively, under Facility A and
$2.5 million under Facility B at December 31, 2002 available for future
borrowings. No amounts under the Compass Facility were outstanding at December
31, 2002. At December 31, 2002 and September 30, 2003, one letter of credit was
issued and outstanding under the Hibernia Facility in the amount of $0.2
million.
On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company ("CCBM"),
issued a non-recourse promissory note payable in the amount of $7.5 million to
RMG as consideration for certain interests in oil and natural gas leases held by
RMG in Wyoming and Montana. The RMG note was payable in 41 monthly principal
payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001
with the balance due December 31, 2004. The RMG note is secured solely by CCBM's
interests in the oil and natural gas leases in Wyoming and Montana. At December
31, 2002 and September 30, 2003, the outstanding principal balance of this note
was $5.3 million and $1.0 million, respectively. In connection with the
Company's investment in Pinnacle (see Note 3), the Company received a reduction
in the principal amount of the RMG note of approximately $1.5 million and
relinquished the right to certain revenues related to the properties contributed
to Pinnacle.
In December 2001, the Company entered into a capital lease agreement secured by
certain production equipment in the amount of $0.2 million. The lease is payable
in one payment of $11,323 and 35 monthly payments of $7,549 including interest
at 8.6% per annum. In October 2002, the Company entered into a capital lease
agreement secured by certain production equipment in the amount of $0.1 million.
The lease is payable in 36 monthly payments of $3,462 including interest at 6.4%
per annum. In May 2003, the Company entered into a capital lease agreement
secured by certain production equipment in the amount of $0.1 million. The lease
is payable in 36 monthly payments of $3,030 including interest at 5.5% per
annum. In August 2003, the Company entered into a capital lease agreement
secured by certain production equipment in the amount of $0.1 million. The lease
is payable in 36 monthly payments of $2,179 including interest at 6.0% per
annum. The Company has the option to acquire the equipment at the conclusion of
the lease for $1 under all of these leases. DD&A on the capital leases for the
three months ended September 30, 2002 and 2003 amounted to $6,000 and $14,000,
respectively. DD&A on the capital leases for the nine months ended September 30,
2002 and 2003 amounted to $18,000 and $35,000 respectively, and accumulated DD&A
on the leased equipment at December 31, 2002 and September 30, 2003 amounted to
$28,000 and $62,000, respectively.
In December 1999, the Company consummated the sale of $22.0 million principal
amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and
$8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2
million, $0.8 million, $0.8 million and $0.8 million principal amount of
Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of
the
F-35
Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006
Warrants to CB Capital Investors, L.P. (now known as J.P. Morgan Partners (23A
SBIC), LLC), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and
Douglas A.P. Hamilton, respectively. The Subordinated Notes were sold at a
discount of $0.7 million, which is being amortized over the life of the notes.
Interest payments are due quarterly commencing on March 31, 2000. The Company
may elect, until December 2004, to increase the amount of the Subordinated Notes
for 60% of the interest which would otherwise be payable in cash. As of December
31, 2002 and September 30, 2003, the outstanding balance of the Subordinated
Notes had been increased by $3.9 million and $5.0 million, respectively, for
such interest paid in kind.
The Company is subject to certain covenants under the terms of the Subordinated
Notes securities purchase agreement, including but not limited to, (a)
maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, and (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors and a J.P. Morgan Partners (23A SBIC), LLC
appointed director), as well as limits on the Company's ability to (i) incur
indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation,
sales of assets and acquisitions, (iv) declare dividends and effect certain
distributions (including restrictions on distributions upon the Common Stock),
(v) engage in transactions with affiliates and (vi) make certain repayments and
prepayments, including any prepayment of the subordinated debt, indebtedness
that is guaranteed or credit-enhanced by any affiliate of the Company, and
prepayments that effect certain permanent reductions in revolving credit
facilities. EBITDA was part of a negotiated covenant with the purchasers and is
presented here as a disclosure of the Company's covenant obligations.
At December 31, 2002 and September 30, 2003, the Company believes it was in
compliance with all of its debt covenants.
6. INCOME TAXES
The Company estimates its annual effective tax rate to be approximately 35%,
which also approximates its statutory rate. The Company provided deferred tax
expense of $0.6 million and $1.2 million for the three months ended September
30, 2002 and 2003, respectively, and $1.3 million and $3.9 million for the nine
months ended September 30, 2002 and 2003, respectively.
7. COMMITMENTS AND CONTINGENCIES
From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position or results of
operations of the Company.
The operations and financial position of the Company continue to be affected
from time to time in varying degrees by domestic and foreign political
developments as well as legislation and regulations pertaining to restrictions
on oil and natural gas production, imports and exports, natural gas regulation,
tax increases, environmental regulations and cancellation of contract rights.
Both the likelihood and overall effect of such occurrences on the Company vary
greatly and are not predictable.
Pursuant to agreements entered into with RMG in June 2001, CCBM has an
obligation to fund $2.5 million of drilling costs on behalf of RMG. Through
September 30, 2003, CCBM had satisfied $2.2 million of the drilling obligation
on behalf of RMG.
8. CONVERTIBLE PARTICIPATING PREFERRED STOCK
In February 2002, the Company consummated the sale of 60,000 shares of
Convertible Participating Series B Preferred Stock (the "Series B Preferred
Stock") and Warrants to purchase 252,632 shares of Carrizo's common stock for an
aggregate purchase price of $6.0 million. The Company sold 40,000 and
F-36
20,000 shares of Series B Preferred Stock and 168,422 and 84,210 Warrants to
Mellon and Steven A. Webster, respectively. The Series B Preferred Stock is
convertible into common stock by the investors at a conversion price of $5.70
per share, subject to adjustments, and is initially convertible into 1,052,632
shares of common stock. Dividends on the Series B Preferred Stock will be
payable in either cash at a rate of 8% per annum or, at the Company's option, by
payment in kind of additional shares of the same series of preferred stock at a
rate of 10% per annum. At December 31, 2002 and September 30, 2003, the
outstanding balance of the Series B Preferred Stock had been increased by $0.5
million (5,294 shares) and $0.9 million (8,559 shares), respectively, for
dividends paid in kind. At September 30, 2003, the Company had accrued a
dividend of $0.2 million (1,714 shares) that is payable on December 31, 2003.
The Series B Preferred Stock is redeemable at varying prices in whole or in part
at the holders' option after three years or at the Company's option at any time.
The Series B Preferred Stock will also participate in any dividends declared on
the common stock. Holders of the Series B Preferred Stock will receive a
liquidation preference upon the liquidation of, or certain mergers or sales of
substantially all assets involving, the Company. Such holders will also have the
option of receiving a change of control repayment price upon certain deemed
change of control transactions. The warrants have a five-year term and entitle
the holders to purchase up to 252,632 shares of Carrizo's common stock at a
price of $5.94 per share, subject to adjustments, and are exercisable at any
time after issuance. The warrants may be exercised on a cashless exercise basis.
Net proceeds of this financing were approximately $5.8 million and were used
primarily to fund the Company's ongoing exploration and development program and
for general corporate purposes.
9. SHAREHOLDER'S EQUITY
The Company issued 106,472 and 208,168 shares of common stock during the nine
months ended September 30, 2002 and 2003, respectively. The shares issued during
the nine months ended September 30, 2002 were partial consideration for the
acquisition of an interest in certain oil and natural gas properties and the
shares issued during the nine months ended September 30, 2003 were the result of
the exercise of options granted under the Company's Incentive Plan.
In June of 1997, the Company established the Incentive Plan of Carrizo Oil &
Gas, Inc. (the "Incentive Plan"). In October 1995, the FASB issued SFAS No. 123,
"Accounting for Stock-Based Compensation", which requires the Company to record
stock-based compensation at fair value. In December 2002, the FASB issued SFAS
No. 148, "Accounting for Stock Based Compensation--Transition and Disclosure".
The Company has adopted the disclosure requirements of SFAS No. 148 and has
elected to record employee compensation expense utilizing the intrinsic value
method permitted under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees". The Company accounts for its
employees' stock-based compensation plan under APB Opinion No. 25 and its
related interpretations. Accordingly, any deferred compensation expense would be
recorded for stock options based on the excess of the market value of the common
stock on the date the options were granted over the aggregate exercise price of
the options. This deferred compensation would be amortized over the vesting
period of each option. Had compensation cost been determined consistent with
SFAS No. 123 "Accounting for Stock-
F-37
Based Compensation" for all options, the Company's net income (loss) and
earnings per share would have been as follows:
FOR THE THREE FOR THE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- -------------------
2002 2003 2002 2003
-------- -------- -------- --------
(in thousands (in thousands
except except
per share amounts) per share amounts)
Net income available to common shareholders, as
reported............................................. $1,003 $1,892 $1,979 $6,333
Less: Total stock-based employee compensation expense
determined under fair value method for all awards,
net of related tax effects........................... (193) (132) (452) (397)
------ ------ ------ ------
Pro forma net income (loss) available to common
shareholders......................................... $ 810 $1,760 $1,527 $5,936
====== ====== ====== ======
Net income per common share, as reported:
Basic................................................ $ 0.07 $ 0.13 $ 0.14 $ 0.45
Diluted.............................................. 0.06 0.11 0.12 0.38
Pro Forma net income (loss) per common share, as if
value method had been applied to all awards:
Basic................................................ $ 0.06 $ 0.12 $ 0.11 $ 0.42
Diluted.............................................. 0.05 0.10 0.10 0.36
Diluted earnings per share amounts for the three months ended September 30, 2002
and 2003 are based upon 15,902,354 and 16,890,630 shares, respectively, that
include the dilutive effect of assumed stock option and warrant exercises of
1,725,826 and 2,625,911, respectively. Diluted earnings per share amounts for
the nine months ended September 30, 2002 and 2003 are based upon 15,928,330 and
16,574,238 shares, respectively, that include the dilutive effect of assumed
stock options and warrant exercises of 1,776,091 and 2,349,345, respectively.
Comprehensive income for the three and nine months ended September 30, 2002 and
2003 was as follows:
FOR THE THREE
MONTHS ENDED FOR THE NINE MONTHS
SEPTEMBER 30, ENDED SEPTEMBER 30,
--------------- --------------------
2002 2003 2002 2003
------ ------ --------- --------
Net income............................................ $1,176 $2,082 $ 2,394 $6,885
Net change in fair value of hedging instruments....... (586) 612 (1,083) 321
------ ------ ------- ------
Comprehensive income.................................. $ 590 $2,694 $ 1,311 $7,206
====== ====== ======= ======
10. CHANGE IN ACCOUNTING PRINCIPLE
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations". This Statement is effective for
fiscal years beginning after June 15, 2002, and the Company adopted the
Statement effective January 1, 2003. During the three months ended March 31,
2003, the Company recorded a cumulative effect of change in accounting principle
of $0.1 million, $0.4 million as proved properties and $0.5 million as a
liability for its plugging and abandonment expenses. The Company includes Asset
Retirement Obligation costs, liabilities and related discounted cash flows in
its ceiling test calculations.
11. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
The Company's operations involve managing market risks related to changes in
commodity prices. Derivative financial instruments, specifically swaps, futures,
options and other contracts, are used to reduce and manage those risks. The
Company addresses market risk by selecting instruments whose value fluctuations
correlate strongly with the underlying commodity being hedged. The Company
enters into
F-38
swaps, options, collars and other derivative contracts to hedge the price risks
associated with a portion of anticipated future oil and natural gas production.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit future gains from favorable movements. Under these
agreements, payments are received or made based on the differential between a
fixed and a variable product price. These agreements are settled in cash at
expiration or exchanged for physical delivery contracts. The Company enters into
the majority of its hedging transactions with two counterparties and a netting
agreement is in place with those counterparties. The Company does not obtain
collateral to support the agreements but monitors the financial viability of
counterparties and believes its credit risk is minimal on these transactions. In
the event of nonperformance, the Company would be exposed to price risk. The
Company has some risk of accounting loss since the price received for the
product at the actual physical delivery point may differ from the prevailing
price at the delivery point required for settlement of the hedging transaction.
As of December 31, 2002 and September 30, 2003, $0.4 million and $67,000, net of
tax of $0.2 million and $36,000, respectively, remained in accumulated other
comprehensive income related to the valuation of the Company's hedging
positions.
Total oil purchased and sold under swaps and collars during the three months
ended September 30, 2002 and 2003 was 33,600 Bbls and 24,400 Bbls, respectively.
Total natural gas purchased and sold under swaps and collars during the three
months ended September 30, 2002 and 2003 was 731,000 MMBtu and 828,000 MMBtu,
respectively. Total oil purchased and sold under swaps and collars during the
nine months ended September 30, 2002 and 2003 was 79,100 Bbls and 150,700 Bbls,
respectively. Total natural gas purchased and sold under swaps and collars
during the nine months ended September 30, 2002 and 2003 was 3,094,000 MMBtu and
2,187,000 MMBtu, respectively. The net losses realized by the Company under such
hedging arrangements was $0.1 million and $0.1 million for the three months
ended September 30, 2002 and 2003, respectively, and are included in oil and
natural gas revenues. The net losses realized by the Company under such hedging
arrangements were $0.4 million and $1.8 million for the nine months ended
September 30, 2002 and 2003, respectively, and are included in oil and natural
gas revenues.
At December 31, 2002 and September 30, 2003 the Company had the following
outstanding hedge positions:
AS OF DECEMBER 31, 2002
------------------------------------------------------------
CONTRACT VOLUMES
---------------- AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ ------- ----------- ----------- -------------
First Quarter 2003................... 27,000 $24.85
First Quarter 2003................... 36,000 $23.50 $26.50
First Quarter 2003................... 540,000 3.40 5.25
Second Quarter 2003.................. 27,300 24.85
Second Quarter 2003.................. 36,000 23.50 26.50
Second Quarter 2003.................. 546,000 3.40 5.25
Third Quarter 2003................... 552,000 3.40 5.25
Fourth Quarter 2003.................. 552,000 3.40 5.25
F-39
AS OF SEPTEMBER 30, 2003
------------------------------------------------------------
CONTRACT VOLUMES
---------------- AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ ------- ----------- ----------- -------------
Fourth Quarter 2003.................. 30,700 $30.22
Fourth Quarter 2003.................. 552,000 3.40 5.25
First Quarter 2004................... 546,000 4.10 7.00
Second Quarter 2004.................. 273,000 4.00 5.20
Third Quarter 2004................... 276,000 4.00 5.20
Fourth Quarter 2004.................. 93,000 4.00 5.20
During October 2003, the Company entered into swap arrangements covering 30,200
Bbls of oil for November 2003 through February 2004 production with an average
fixed price of $30.26.
In addition to the hedge positions above, during the second quarter of 2003, the
Company acquired options to sell 6,000 MMBtu of natural gas per day for the
period July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for
approximately $119,000. The Company acquired these options to protect its cash
position against potential margin calls on certain natural gas derivatives due
to large increases in the price of natural gas. These options were classified as
derivatives. As of September 30, 2003, these options have expired and a charge
of $28,000 and $119,000 has been included in other income and expense for the
three and nine months ended September 30, 2003, respectively.
12. NEW ACCOUNTING PRONOUNCEMENTS
The FASB issued Interpretation 46, "Consolidation of Variable Interest Entities"
("FIN 46"), in January 2003. FIN 46 requires the consolidation of certain types
of entities in which a company absorbs a majority of another entity's expected
losses, receives a majority of the other entity's expected residual returns, or
both, as a result of ownership, contractual or other financial interests in the
other entity. The Company has identified no transactions or related entities
that required consolidation under this interpretation.
SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Intangible Assets," were issued by the FASB in June 2001 and became effective
for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires
all business combinations initiated after June 30, 2001 to be accounted for
using the purchase method. Additionally, SFAS No. 141 requires companies to
disaggregate and report separately from goodwill certain intangible assets. SFAS
No. 142 establishes new guidelines for accounting for goodwill and other
intangible assets. Under SFAS No. 142, goodwill and certain other intangible
assets are not amortized but rather are reviewed annually for impairment.
Natural gas and oil mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves for both
undeveloped and developed leaseholds may have to be classified separately from
natural gas and oil properties as intangible assets on our consolidated balance
sheets. In addition, the disclosures required by SFAS No. 141 and 142 relative
to intangibles would be included in the notes to the consolidated financial
statements. Historically, we, like many other natural gas and oil companies,
have included these rights as part of natural gas and oil properties, even after
SFAS No. 141 and 142 became effective.
In the event this interpretation is adopted, a substantial portion of the
acquisition costs of oil and gas properties would be required to be classified
on the balance sheet as an intangible asset. The Company would not be required
to reclassify proved reserve leasehold acquisitions prior to June 30, 2001
because the Company did not separately value or account for these costs prior to
the adoption date of SFAS No. 141. The Company believes this interpretation
would not have a material effect on our results of operations for the periods
presented or in the future as these intangible assets would be depleted using
the units of production method in a manner consistent with the method currently
used to calculate depletion, depreciation, and amortization expense ("DD&A") on
those assets.
F-40
As of September 30, 2003, December 31, 2002 and December 31, 2001, we had
leasehold costs incurred of approximately $3.4 million, $1.4 million and $1.4
million, respectively, that would be classified on our consolidated balance
sheet as "intangible leasehold costs" if we applied the interpretation discussed
above.
13. SUBSEQUENT EVENTS
EXCHANGE TRANSACTION ON OCTOBER 10, 2003
Pursuant to an exchange election provided in a letter agreement, dated May 1,
2001, with certain participants in the Carrizo 2001 Seismic and Acreage Program
(the "2001 Program"), the Company is issuing to such participants, who have
exercised their election, approximately 168,000 shares of its common stock in
exchange for the participants' entire interest in the 2001 Program, including
approximately 350 square miles of 3-D seismic data and working interests in
certain producing properties. The exchange transaction was effective on October
10, 2003 and was valued using the closing price of the Company's stock on that
date, for a total of approximately $1.2 million.
F-41
APPENDIX A TO PROSPECTUS
SUMMARY RESERVE REPORTS
A-1
March 26, 2003
Carrizo Oil & Gas, Inc.
14701 St. Mary's Lane, Suite 800
Houston, Texas 77079
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of Carrizo Oil & Gas, Inc. (Carrizo) as of December 31, 2002. The subject
properties are located in the states of Louisiana and Texas. The income data
were estimated using the Securities and Exchange Commission (SEC) guidelines for
future price and cost parameters.
The estimated reserves and future income amounts presented in this report are
related to hydrocarbon prices. December 31, 2002 hydrocarbon prices were used in
the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from December 31, 2002 prices. Therefore,
volumes of reserves actually recovered and amounts of income actually received
may differ significantly from the estimated quantities presented in this report.
The results of this study are summarized below.
SEC PARAMETERS
ESTIMATED NET RESERVES AND INCOME DATA
CERTAIN LEASEHOLD AND ROYALTY INTERESTS OF
CARRIZO OIL & GAS, INC.
AS OF DECEMBER 31, 2002
PROVED
-------------------------------------
DEVELOPED
------------------------- TOTAL
PRODUCING NON-PRODUCING PROVED
--------- ------------- ---------
NET REMAINING RESERVES
Oil/Condensate -- Barrels........................... 428,969 214,238 643,207
Plant Products -- Barrels........................... 25,964 83,660 109,624
Gas -- MMCF......................................... 5,592 6,087 11,679
INCOME DATA ($M)
Future Gross Revenue................................ $37,853.6 $35,042.8 $72,896.4
Deductions.......................................... 7,544.7 6,633.4 14,178.1
--------- --------- ---------
Future Net Income (FNI)............................. $30,308.9 $28,409.4 $58,718.3
Discounted FNI @ 10%................................ $26,627.8 $20,572.8 $47,200.6
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes
are sales gas expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas reserves are
located.
The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs, development costs, and certain abandonment
costs net of salvage. The future net income is before the deduction of state and
federal income taxes and general administrative overhead, and has not been
adjusted for outstanding loans that may exist nor does it include any adjustment
for cash on hand or undistributed income. No attempt was made to quantify or
otherwise account for any accumulated gas production imbalances that may exist.
Gas reserves account for approximately 73 percent and liquid hydrocarbon
reserves account for the remaining 27 percent of total future gross revenue from
proved reserves.
A-2
Carrizo Oil & Gas, Inc.
March 26, 2003
Page 2
RESERVES INCLUDED IN THIS REPORT
The proved reserves included herein conform to the definition as set forth in
the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletins. The definitions
of proved reserves are included in the section entitled "Petroleum Reserves
Definitions" which is attached with this report.
The proved and probable developed non-producing reserves included herein are
comprised of shut-in and behind pipe categories. The various reserve status
categories are defined in the section entitled "Petroleum Reserves Definitions"
which is attached with this report.
ESTIMATES OF RESERVES
In general, the reserves included herein were estimated by performance methods
or the volumetric method; however, other methods were used in certain cases
where characteristics of the data indicated such other methods were more
appropriate in our opinion. The reserves estimated by the performance method
utilized extrapolations of various historical data in those cases where such
data were definitive. Reserves were estimated by the volumetric method in those
cases where there were inadequate historical performance data to establish a
definitive trend or where the use of production performance data as a basis for
the reserve estimates was considered to be inappropriate.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for the
effects of curtailment where appropriate, until a decline in ability to produce
was anticipated. An estimated rate of decline was then applied to depletion of
the reserves. If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
Carrizo.
In general, we estimate that future gas production rates limited by allowables
or marketing conditions will continue to be the same as the average rate for the
latest available 12 months of actual production until such time that the well or
wells are incapable of producing at this rate. The well or wells were then
projected to decline at their decreasing delivery capacity rate. Our general
policy on estimates of future gas production rates is adjusted when necessary to
reflect actual gas market conditions in specific cases.
The future production rates from wells now on production may be more or less
than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
HYDROCARBON PRICES
Carrizo furnished us with hydrocarbon prices in effect at December 31, 2002 and
with its forecasts of future prices which take into account SEC and Financial
Accounting Standards Board (FASB) rules, current market prices, contract prices,
and fixed and determinable price escalations where applicable.
A-3
Carrizo Oil & Gas, Inc.
March 26, 2003
Page 3
In accordance with FASB Statement No. 69, December 31, 2002 market prices were
determined using the daily oil price or daily gas sales price ("spot price")
adjusted for oilfield or gas gathering hub and wellhead price differences (e.g.
grade, transportation, gravity, sulfur and BS&W) as appropriate. Also in
accordance with SEC and FASB specifications, changes in market prices subsequent
to December 31, 2002 were not considered in this report.
For hydrocarbon products sold under contract, the contract price including fixed
and determinable escalations, exclusive of inflation adjustments, was used until
expiration of the contract. Upon contract expiration, the price was adjusted to
the current market price for the area and held at this adjusted price to
depletion of the reserves.
COSTS
Operating costs for the leases and wells in this report are based on the
operating expense reports of Carrizo and include only those costs directly
applicable to the leases or wells. When applicable, the operating costs include
a portion of general and administrative costs allocated directly to the leases
and wells under terms of operating agreements. No deduction was made for
indirect costs such as general administration and overhead expenses, loan
repayments, interest expenses, and exploration and development prepayments that
are not charged directly to the leases or wells.
Development costs were furnished to us by Carrizo and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. The estimated net cost of abandonment after salvage was included for
properties where abandonment costs net of salvage are significant. At the
request of Carrizo, their estimate of zero abandonment costs after salvage value
for onshore properties was used in this report. Ryder Scott has not performed a
detailed study of the abandonment costs nor the salvage value and makes no
warranty for Carrizo's estimate.
Current costs were held constant throughout the life of the properties.
GENERAL
While it may reasonably be anticipated that the future prices received for the
sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.
The estimates of reserves presented herein were based upon a detailed study of
the properties in which Carrizo owns an interest; however, we have not made any
field examination of the properties. No consideration was given in this report
to potential environmental liabilities which may exist nor were any costs
included for potential liability to restore and clean up damages, if any, caused
by past operating practices. Carrizo has informed us that they have furnished us
all of the accounts, records, geological and engineering data, and reports and
other data required for this investigation. The ownership interests, prices, and
other factual data furnished by Carrizo were accepted without independent
verification. The estimates presented in this report are based on data available
through December 2002.
Carrizo has assured us of their intent and ability to proceed with the
development activities included in this report, and that they are not aware of
any legal, regulatory or political obstacles that would significantly alter
their plans.
Neither we nor any of our employees have any interest in the subject properties
and neither the employment to make this study nor the compensation is contingent
on our estimates of reserves and future income for the subject properties.
A-4
Carrizo Oil & Gas, Inc.
March 26, 2003
Page 4
This report was prepared for the exclusive use and sole benefit of Carrizo Oil &
Gas, Inc. The data, work papers, and maps used in this report are available for
examination by authorized parties in our offices. Please contact us if we can be
of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
/s/ MICHAEL F. STELL, P.E.
--------------------------------------
Michael F. Stell, P.E.
Vice President
MFS/sw
A-5
PETROLEUM RESERVES DEFINITIONS
SECURITIES AND EXCHANGE COMMISSION
INTRODUCTION
Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree
of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain
to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in
their recoverability. It should be noted that Securities and Exchange Commission
Regulation S-K prohibits the disclosure of estimated quantities of probable or
possible reserves of oil and gas and any estimated value thereof in any
documents publicly filed with the Commission.
Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage or processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery
methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate
recovery. Examples of such methods are pressure maintenance, cycling,
waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed
in the future as petroleum technology continues to evolve.
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a)
defines proved reserves as follows:
Proved Oil and Gas Reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes:
(A) that portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
A-6
PETROLEUM RESERVES DEFINITIONS
Page 2
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) 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.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves";
(B) crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
Proved Developed Oil and Gas Reserves. Proved developed oil and gas reserves
are reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves" only after testing by
a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.
Proved Undeveloped Reserves. Proved undeveloped oil and gas reserves are
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for
recompletion. Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
Certain Staff Accounting Bulletins published subsequent to the promulgation of
Regulation S-X have dealt with matters relating to the application of financial
accounting and disclosure rules for oil and gas producing activities. In
particular, the following interpretations extracted from Staff Accounting
Bulletins set forth the Commission staff's view on specific questions pertaining
to proved oil and gas reserves.
Economic producibility of estimated proved reserves can be supported to the
satisfaction of the Office of Engineering if geological and engineering data
demonstrate with reasonable certainty that those reserves can be recovered in
future years under existing economic and operating conditions. The relative
importance of the many pieces of geological and engineering data which should be
evaluated when classifying reserves cannot be identified in advance. In certain
instances, proved reserves may be assigned to reservoirs on the basis of a
combination of electrical and other type logs and core analyses which indicate
the reservoirs are analogous to similar reservoirs in the same field which are
producing or have demonstrated the ability to produce on a formation test.
(extracted from SAB-35)
A-7
PETROLEUM RESERVES DEFINITIONS
Page 3
In determining whether "proved undeveloped reserves" encompass acreage on which
fluid injection (or other improved recovery technique) is contemplated, is it
appropriate to distinguish between (i) fluid injection used for pressure
maintenance during the early life of a field and (ii) fluid injection used to
effect secondary recovery when a field is in the late stages of depletion? ...
The Office of Engineering believes that the distinction identified in the above
question may be appropriate in a few limited circumstances, such as in the case
of certain fields in the North Sea. The staff will review estimates of proved
reserves attributable to fluid injection in the light of the strength of the
evidence presented by the registrant in support of a contention that enhanced
recovery will be achieved. (extracted from SAB-35)
Companies should report reserves of natural gas liquids which are net to their
leasehold interest, i.e., that portion recovered in a processing plant and
allocated to the leasehold interest. It may be appropriate in the case of
natural gas liquids not clearly attributable to leasehold interests ownership to
follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such
reserves separately and describe the nature of the ownership. (extracted from
SAB-35)
The staff believes that since coalbed methane gas can be recovered from coal in
its natural and original location, it should be included in proved reserves,
provided that it complies in all other respects with the definition of proved
oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement
that methane production be economical at current prices, costs, (net of the tax
credit) and existing operating conditions. (extracted from SAB-85)
Statements in Staff Accounting Bulletins are not rules or interpretations of the
Commission nor are they published as bearing the Commission's official approval;
they represent interpretations and practices followed by the Division of
Corporation Finance and the Office of the Chief Accountant in administering the
disclosure requirements of the Federal securities laws.
SUB-CATEGORIZATION OF DEVELOPED RESERVES (SPE/WPC DEFINITIONS)
In accordance with guidelines adopted by the Society of Petroleum Engineers
(SPE) and the World Petroleum Congress (WPC), developed reserves may be
sub-categorized as producing or non-producing.
Producing. Reserves sub-categorized as producing are expected to be recovered
from completion intervals which are open and producing at the time of the
estimate. Improved recovery reserves are considered producing only after the
improved recovery project is in operation.
Non-Producing. Reserves sub-categorized as non-producing include shut-in and
behind pipe reserves. Shut-in reserves are expected to be recovered from (1)
completion intervals which are open at the time of the estimate but which have
not started producing, (2) wells which were shut-in awaiting pipeline
connections or as a result of a market interruption, or (3) wells not capable of
production for mechanical reasons. Behind pipe reserves are expected to be
recovered from zones in existing wells, which will require additional completion
work or future recompletion prior to the start of production.
A-8
[FAIRCHILD AND WELLS, INC. LETTERHEAD]
February 20, 2002
Carrizo Oil & Gas, Inc.
14701 St. Mary's Lane, Suite 800
Houston, Texas 77079
RE: RESERVES EVALUATION TO THE INTERESTS OF CARRIZO OIL & GAS CORP. HEAVY OIL
PROPERTIES, ANDERSON COUNTY, TEXAS
Gentlemen:
Fairchild and Wells, Inc. (FAW) has performed an engineering evaluation to
estimate proved reserves and future cash flows from heavy oil (steamflood)
properties to the interests of Carrizo Oil & Gas Corporation in Anderson County,
Texas. This evaluation was authorized by Mr. S.P. Johnson IV, President of
Carrizo Oil & Gas Corporation (Carrizo). Projections of the anticipated future
annual oil production and future cash flows have also been prepared utilizing
property development schedules provided by Carrizo. The reserves and future cash
flows to the evaluated interests were based on economic parameters and operating
conditions considered applicable and are pursuant to the financial reporting
requirements of the Securities and Exchange Commission (SEC). December, 2002
hydrocarbon prices were used in the preparation of this report and current costs
were held constant throughout the life of the properties.
The results of the study are summarized below.
SUMMARY
ESTIMATED PROVED RESERVES AND FUTURE CASH FLOWS
CAMP HILL FIELD ANDERSON COUNTY, TEXAS TO THE INTERESTS OF
CARRIZO OIL & GAS CORP.
EFFECTIVE 1/1/2003
FUTURE CASH FLOWS, BEFORE NPI
(M$)
NET RESERVES --------------------------------
MBBLS UNDISCOUNTED DISCOUNTED AT 10%
-------------- ------------ -----------------
Proved Producing
18 Pattern Leases............................ 682.7 9,659.5 7,307.4
10 Pattern Lease............................. 67.2 957.4 810.7
------- -------- --------
Total Proved Producing......................... 750.0 10,616.9 8,118.2
Proved Undeveloped
Delaney A Lease.............................. 704.6 7,166.3 4,215.5
Temple Eastex C Lease........................ 1,359.5 15,880.2 8,938.6
Moore A Lease............................. 405.5 6,232.0 2,656.0
Moore B Lease............................. 93.8 1,202.8 606.5
Hanks Lease............................... 137.1 1,731.6 866.5
C. Rosson................................. 2,161.6 23,796.5 8,229.8
Royall.................................... 2,125.5 25,326.5 4,531.3
------- -------- --------
Total Proved Undeveloped....................... 6,987.7 81,335.9 30,044.2
Total Proved................................... 7,737.6 91,952.8 38,162.4
A-9
Carrizo Oil & Gas, Inc.
February 20, 2003
FUTURE CASH FLOW -- TOTAL PROJECT BY YEAR
(AFTER NET PROFITS INTEREST)
FUTURE CASH FLOWS AFTER NPI (M$)
--------------------------------
YEAR UNDISCOUNTED DISCOUNTED AT 10%
---- ------------ -----------------
2003....................................................... 116.2 110.8
2004....................................................... 76.9 66.6
2005....................................................... 5,358.9 4,222.7
2006....................................................... 4,895.9 3,507.2
2007....................................................... 4,793.8 3,121.8
2008....................................................... 5,424.5 3,211.5
2009....................................................... 5,593.9 3,010.7
2010....................................................... 6,517.2 3,188.7
2011....................................................... 4,986.3 2,217.9
2012....................................................... 4,361.1 1,763.5
2013....................................................... 5,229.8 1,922.5
2014....................................................... 7,265.8 2,428.1
2015....................................................... 4,907.8 1,491.0
2016....................................................... 4,008.7 1,107.1
2017....................................................... 2,205.4 553.7
2018....................................................... 2,949.1 673.1
2019....................................................... 2,375.1 492.8
2020....................................................... 2,441.4 460.5
2021....................................................... 2,735.7 469.1
2022....................................................... 3,260.7 508.3
2023....................................................... 2,211.5 313.4
2024....................................................... 2,166.2 279.1
2025....................................................... 2,356.0 276.0
2026....................................................... 1,026.0 109.3
2027....................................................... 197.9 19.2
-------- --------
TOTAL...................................................... 87,461.9 35,524.8
The estimated reserves and future cash flows shown in this report are for proved
developed producing and proved undeveloped reserves. Our estimates do not
include any value which might be attributed to interests in undeveloped acreage
beyond those tracts for which reserves have been assigned.
In performance of this evaluation, we have relied upon information furnished by
Carrizo with respect to property interests owned, production from such
properties, current costs of operation and development, current prices for
production, agreements relating to current and future operations and sale of
production. With respect to the technical files supplied by Carrizo, we have
accepted the authenticity and sufficiency of the data contained therein.
Future cash flow is presented after deducting production taxes and after
deducting future capital costs and operating expenses, but before consideration
of Federal income taxes. The future cash flow has been discounted at an annual
rate of 10 percent to determine its "present worth." The present worth is shown
to indicate the effect of time on the value of money and should not be
A-10
Carrizo Oil & Gas, Inc.
February 20, 2003
construed as being the fair market value of the properties Our estimates of
future revenue do not include any salvage value for the lease and well equipment
Fairchild and Wells, Inc. expresses no opinion as to the fair market value of
the evaluated properties.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Because of governmental
policies and uncertainties of supply and demand, the actual sales rates and the
prices actually received for the reserves along with the costs incurred in
recovering such reserves may vary from those assumptions included in this
report. Also, estimates of reserves may increase or decrease as a result of
future operations.
In evaluating the information at our disposal concerning this report, we have
excluded from our consideration all matters as to which legal or accounting,
rather than engineering, interpretation may be controlling. As in all aspects of
oil and gas evaluation, there are uncertainties inherent in the interpretation
of engineering data and, therefore, our conclusions necessarily represent only
informed professional judgments.
The titles to the properties have not been examined by Fairchild and Wells, Inc.
nor has the actual degree or type of interest owned been independently
confirmed. We are independent petroleum engineers and geologists; we do not own
an interest in these properties and are not employed on a contingent basis.
Basic geologic and field performance data together with our engineering work
sheets are maintained on file in our office and are available for review.
It has been a pleasure to serve you by preparing this engineering evaluation.
Yours very truly,
FAIRCHILD AND WELLS, INC.
/s/ JAMES FAIRCHILD
--------------------------------------
James Fairchild
President
A-11
March 28, 2003
CCBM, Inc.
14701 St. Mary's Lane, Suite 800
Houston, Texas 77079
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold interests of CCBM, Inc.
(CCBM) as of December 31, 2002. The subject properties are located in the Bobcat
Field, Campbell County, Wyoming. The income data were estimated using the
Securities and Exchange Commission (SEC) requirements for future price and cost
parameters.
The estimated reserves and future income amounts presented in this report are
related to hydrocarbon prices. Hydrocarbon prices in effect at December 31, 2002
were used in the preparation of this report as required by SEC rules; however,
actual future prices may vary significantly from December 31, 2002 prices.
Therefore, volumes of reserves actually recovered and amounts of income actually
received may differ significantly from the estimated quantities presented in
this report. The results of this study are summarized below.
SEC PARAMETERS
ESTIMATED NET RESERVES AND INCOME DATA
CERTAIN LEASEHOLD INTERESTS OF
CCBM, INC.
BOBCAT FIELD
AS OF DECEMBER 31, 2002
PROVED
---------------------------------------
DEVELOPED
PRODUCING UNDEVELOPED TOTAL PROVED
---------- ----------- ------------
NET REMAINING RESERVES
Gas -- MMCF........................................ 490 96 586
INCOME DATA
Future Gross Revenue............................... $1,394,130 $273,082 $1,667,212
Deductions......................................... 473,728 142,180 615,908
---------- -------- ----------
Future Net Income (FNI)............................ $ 920,402 $130,902 $1,051,304
Discounted FNI @ 10%............................... $ 793,481 $ 94,947 $ 888,428
All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at the
official temperature and pressure bases of Wyoming, which are 60 degrees and
14.73 psia.
A-12
March 26, 2003
Page 2
The future gross revenue is after the deduction of production taxes. The
deductions comprise the normal direct costs of operating the wells, ad valorem
taxes, completion costs, and development costs. The future net income is before
the deduction of state and federal income taxes and general administrative
overhead, and has not been adjusted for outstanding loans that may exist nor
does it include any adjustment for cash on hand or undistributed income. No
attempt was made to quantify or otherwise account for any accumulated gas
production imbalances that may exist. Gas reserves account for 100 percent of
total future gross revenue from proved reserves.
RESERVES INCLUDED IN THIS REPORT
The proved reserves included herein conform to the definition as set forth in
the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletins. The definition of
proved reserves is included in the section entitled "Petroleum Reserves
Definitions" which is attached with this report.
Because of the direct relationship between volumes of proved undeveloped
reserves and development plans, we include in the proved undeveloped category
only reserves assigned to undeveloped locations that we have been assured will
definitely be drilled.
The various reserve status categories are in the section entitled "Petroleum
Reserves Definitions" which is attached with this report.
ESTIMATES OF RESERVES
Producing reserves were estimated based on performance analysis and volumetric
calculations. Undeveloped reserves were based on analogy to offset wells. All of
the reserves are based on primary recovery from coal seams.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
that are not currently producing. If no production decline trend had been
established, future production rates were inclined during the dewatering phase
or held constant, as appropriate, until a decline in ability to produce was
anticipated. An estimated rate of decline was then applied to depletion of the
reserves. If a decline trend had been established, this trend was used as the
basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
CCBM.
The future production rates from wells now on production may be more or less
than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations that are not currently producing may start
producing earlier or later than anticipated in our estimates of their future
production rates.
A-13
March 26, 2003
Page 3
HYDROCARBON PRICES
In accordance with FASB Statement No. 69, December 31, 2002 market prices were
determined using the daily gas sales price ("spot price") adjusted for gas
gathering hub and wellhead price differences (e.g. grade, transportation,
gravity, sulfur and BS&W) as appropriate. Also in accordance with SEC and FASB
specifications, changes in market prices subsequent to December 31, 2002 were
not considered in this report.
The December 31, 2002 gas price of $3.00 per MCF was used in this report, which
was based on a Henry Hub benchmark price of $4.75 per MMBTU, less a historical
differential of $1.75 per MMBTU, times 1000 BTU per cubic foot. This December
31, 2002 gas price was held constant throughout the life of the properties.
The effects of derivative instruments designated as price hedges of oil and gas
quantities were not considered or included in this report.
COSTS
Because the historical operating cost for the subject properties are still
affected by non-reoccurring start-up cost, operating costs for the leases and
wells in this report were estimated and provided by CCBM. Operating costs were
based on the operating expense reports of CCBM and include only those costs
directly applicable to the leases or wells. When applicable, the operating costs
include a portion of general and administrative costs allocated directly to the
leases and wells under terms of operating agreements. No deduction was made for
indirect costs such as general administration and overhead expenses, loan
repayments, interest expenses, and exploration and development prepayments that
are not charged directly to the leases or wells.
Development costs were furnished to us by CCBM and are based on authorizations
for expenditure for the proposed work or actual costs for similar projects. At
the request of CCBM, their estimate of zero abandonment costs after salvage
value for these onshore properties was used in this report. Ryder Scott has not
performed a detailed study of the abandonment costs or the salvage value and
makes no warranty for CCBM's estimate.
Current costs were held constant throughout the life of the properties.
GENERAL
While it may reasonably be anticipated that the future prices received for the
sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.
The estimates of reserves presented herein were based upon a detailed study of
the properties in which CCBM owns an interest; however, we have not made any
field examination of the properties. No consideration was given in this report
to potential environmental liabilities that may exist nor were any costs
included for potential liability to restore and clean up damages, if any, caused
by past operating practices. CCBM has informed us that they have furnished us
all of the accounts, records, geological and engineering data, and reports and
other data required for this investigation. The ownership interests, prices, and
other factual data furnished by CCBM were accepted without independent
verification. The estimates presented in this report are based on data available
through December 2002.
A-14
March 26, 2003
Page 4
CCBM has assured us of their intent and ability to proceed with the development
activities included in this report, and that they are not aware of any legal,
regulatory or political obstacles that would significantly alter their plans.
Neither we nor any of our employees have any interest in the subject properties
and neither the employment to make this study nor the compensation is contingent
on our estimates of reserves and future income for the subject properties.
This report was prepared for the exclusive use and sole benefit of CCBM, Inc.
The data, work papers, and maps used in this report are available for
examination by authorized parties in our offices. Please contact us if we can be
of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
/s/ JOSEPH E. BLANKENSHIP, P.E.
--------------------------------------
Joseph E. Blankenship, P.E.
Senior Vice President
JEB/sw
A-15
PETROLEUM RESERVES DEFINITIONS
SECURITIES AND EXCHANGE COMMISSION
INTRODUCTION
Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree
of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain
to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in
their recoverability. It should be noted that Securities and Exchange Commission
Regulation S-K prohibits the disclosure of estimated quantities of probable or
possible reserves of oil and gas and any estimated value thereof in any
documents publicly filed with the Commission.
Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage or processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery
methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate
recovery. Examples of such methods are pressure maintenance, cycling,
waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed
in the future as petroleum technology continues to evolve.
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a)
defines proved reserves as follows:
Proved Oil and Gas Reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes:
(A) that portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.
A-16
PETROLEUM RESERVES DEFINITIONS
Page 2
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) 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.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves";
(B) crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
Proved Developed Oil and Gas Reserves. Proved developed oil and gas reserves
are reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves" only after testing by
a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.
Proved Undeveloped Reserves. Proved undeveloped oil and gas reserves are
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for
recompletion. Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
Certain Staff Accounting Bulletins published subsequent to the promulgation of
Regulation S-X have dealt with matters relating to the application of financial
accounting and disclosure rules for oil and gas producing activities. In
particular, the following interpretations extracted from Staff Accounting
Bulletins set forth the Commission staff's view on specific questions pertaining
to proved oil and gas reserves.
Economic producibility of estimated proved reserves can be supported to the
satisfaction of the Office of Engineering if geological and engineering data
demonstrate with reasonable certainty that those reserves can be recovered in
future years under existing economic and operating conditions. The relative
importance of the many pieces of geological and engineering data which should be
evaluated when classifying reserves cannot be identified in advance. In certain
instances, proved reserves may be assigned to reservoirs on the basis of a
combination of electrical and other type logs and core analyses which indicate
the reservoirs are analogous to similar reservoirs in the same field which are
producing or have demonstrated the ability to produce on a formation test.
(extracted from SAB-35)
A-17
PETROLEUM RESERVES DEFINITIONS
Page 3
In determining whether "proved undeveloped reserves" encompass acreage on which
fluid injection (or other improved recovery technique) is contemplated, is it
appropriate to distinguish between (i) fluid injection used for pressure
maintenance during the early life of a field and (ii) fluid injection used to
effect secondary recovery when a field is in the late stages of depletion? ...
The Office of Engineering believes that the distinction identified in the above
question may be appropriate in a few limited circumstances, such as in the case
of certain fields in the North Sea. The staff will review estimates of proved
reserves attributable to fluid injection in the light of the strength of the
evidence presented by the registrant in support of a contention that enhanced
recovery will be achieved. (extracted from SAB-35)
Companies should report reserves of natural gas liquids which are net to their
leasehold interest, i.e., that portion recovered in a processing plant and
allocated to the leasehold interest. It may be appropriate in the case of
natural gas liquids not clearly attributable to leasehold interests ownership to
follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such
reserves separately and describe the nature of the ownership. (extracted from
SAB-35)
THE STAFF BELIEVES THAT SINCE COALBED METHANE GAS CAN BE RECOVERED FROM COAL IN
ITS NATURAL AND ORIGINAL LOCATION, IT SHOULD BE INCLUDED IN PROVED RESERVES,
PROVIDED THAT IT COMPLIES IN ALL OTHER RESPECTS WITH THE DEFINITION OF PROVED
OIL AND GAS RESERVES AS SPECIFIED IN RULE 4-10(a)(2) INCLUDING THE REQUIREMENT
THAT METHANE PRODUCTION BE ECONOMICAL AT CURRENT PRICES, COSTS, (NET OF THE TAX
CREDIT) AND EXISTING OPERATING CONDITIONS. (EXTRACTED FROM SAB-85)
Statements in Staff Accounting Bulletins are not rules or interpretations of the
Commission nor are they published as bearing the Commission's official approval;
they represent interpretations and practices followed by the Division of
Corporation Finance and the Office of the Chief Accountant in administering the
disclosure requirements of the Federal securities laws.
SUB-CATEGORIZATION OF DEVELOPED RESERVES (SPE/WPC DEFINITIONS)
In accordance with guidelines adopted by the Society of Petroleum Engineers
(SPE) and the World Petroleum Congress (WPC), developed reserves may be
sub-categorized as producing or non-producing.
Producing. Reserves sub-categorized as producing are expected to be recovered
from completion intervals which are open and producing at the time of the
estimate. Improved recovery reserves are considered producing only after the
improved recovery project is in operation.
Non-Producing. Reserves sub-categorized as non-producing include shut-in and
behind pipe reserves. Shut-in reserves are expected to be recovered from (1)
completion intervals which are open at the time of the estimate but which have
not started producing, (2) wells which were shut-in awaiting pipeline
connections or as a result of a market interruption, or (3) wells not capable of
production for mechanical reasons. Behind pipe reserves are expected to be
recovered from zones in existing wells, which will require additional completion
work or future recompletion prior to the start of production.
A-18
--------------------------------------------------------------------------------
(CARRIZO OIL & GAS, INC. LOGO)
5,700,000 SHARES
COMMON STOCK
---------------------------
PROSPECTUS
---------------------------
, 2004
CIBC WORLD MARKETS
FIRST ALBANY CAPITAL
HIBERNIA SOUTHCOAST CAPITAL
JOHNSON RICE & COMPANY L.L.C.
--------------------------------------------------------------------------------
YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED OR INCORPORATED BY REFERENCE
IN THIS PROSPECTUS. NO DEALER, SALESPERSON OR OTHER PERSON IS AUTHORIZED TO GIVE
INFORMATION THAT IS NOT CONTAINED IN THIS PROSPECTUS. THIS PROSPECTUS IS NOT AN
OFFER TO SELL NOR IS IT SEEKING AN OFFER TO BUY THESE SECURITIES IN ANY
JURISDICTION WHERE THE OFFER OR SALE IS NOT PERMITTED. THE INFORMATION CONTAINED
IN THIS PROSPECTUS IS CORRECT ONLY AS OF THE DATE OF THIS PROSPECTUS, REGARDLESS
OF THE TIME OF THE DELIVERY OF THIS PROSPECTUS OR ANY SALE OF THESE SECURITIES.
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
The following table sets forth the costs and expenses, other than the
underwriters' discount and commissions, payable by us in connection with the
sale of common stock being registered. All amounts are estimates except the SEC
registration fee.
SEC registration fee........................................ $
NASD filing fee.............................................
Nasdaq National Market listing fee.......................... 22,500
Printing expenses........................................... 50,000
Legal fees and expenses.....................................
Accounting fees and expenses................................
Miscellaneous expenses......................................
--------
Total..................................................... $
========
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Article 2.02-1 of the Texas Business Corporation Act provides that a corporation
may indemnify any director or officer who was, is or is threatened to be made a
named defendant or respondent in a proceeding because he is or was a director or
officer, provided that the director or officer (i) conducted himself in good
faith, (ii) reasonably believed (a) in the case of conduct in his official
capacity, that his conduct was in the corporation's best interests or (b) in all
other cases, that his conduct was at least not opposed to the corporation's best
interests and (iii) in the case of any criminal proceeding, had no reasonable
cause to believe his conduct was unlawful. Subject to certain exceptions, a
director or officer may not be indemnified if the person is found liable to the
corporation or if the person is found liable on the basis that he improperly
received a personal benefit. Under Texas law, the corporation may pay or
reimburse, in advance of a final disposition of the proceeding, reasonable
expenses incurred by a director or officer after the corporation receives a
written affirmation by the director or officer of his good faith belief that he
has met the standard of conduct necessary for indemnification and a written
undertaking by or on behalf of the director or officer to repay the amount if it
is ultimately determined that the director or officer is not entitled to
indemnification by the corporation. Texas law requires a corporation to
indemnify an officer or director against reasonable expenses incurred in
connection with the proceeding in which he is named defendant or respondent
because he is or was a director or officer if he is wholly successful in defense
of the proceeding.
Texas law also permits a corporation to purchase and maintain insurance or
another arrangement on behalf of any person who is or was a director or officer
against any liability asserted against him and incurred by him in such a
capacity or arising out of his status as such a person, whether or not the
corporation would have the power to indemnify him against that liability under
Article 2.02-1.
Our bylaws provide for the indemnification of our officers and directors, and
the advancement to them of expenses in connection with proceedings and claims,
to the fullest extent permitted by the Texas Business Corporation Act. We also
have entered into indemnification agreements with each of our directors and
certain of our officers that contractually provide for indemnification and
expense advancement and include related provisions meant to facilitate the
indemnitee's receipt of such benefits. These provisions, among other things:
- specify the method of determining entitlement to indemnification and the
selection of independent counsel that will in some cases make such
determination;
II-1
- specify certain time periods by which certain payments or determinations
must be made and actions must be taken; and
- establish certain presumptions in favor of an indemnitee.
The benefits of certain of these provisions are available to an indemnitee only
if there has been a change in control (as defined).
In addition, we may purchase directors' and officers' liability insurance
policies for our directors and officers in the future. The bylaws and these
agreements with directors and officers provide for indemnification for amounts:
- in respect of the deductibles for such insurance policies;
- that exceed the liability limits of such insurance policies; and
- that are available, were available or become available to us but that our
officers or directors determine is inadvisable for us to purchase, given
the cost involved.
Such indemnification may be made even though our directors and officers would
not otherwise be entitled to indemnification under other provisions of the
bylaws or these agreements.
This discussion of Article 2.02-1 of the Texas Business Corporation Act and of
our bylaws is not intended to be exhaustive and is qualified in its entirety by
reference to the statute and our bylaws. We also refer you to the form of the
Underwriting Agreement, filed as Exhibit 1.1 to this registration statement,
which contains provisions for indemnification of us, our directors, our officers
and any controlling persons by the underwriters against certain liabilities for
information furnished by the underwriters.
ITEM 16. EXHIBITS.
The exhibits listed in the accompanying Index to Exhibits are filed or
incorporated by reference as part of this registration statement.
ITEM 17. UNDERTAKINGS.
(H) REQUEST FOR ACCELERATION OF EFFECTIVE DATE
Insofar as indemnification for liabilities arising under the Securities Act of
1933 may be permitted to our directors, officers and controlling persons
pursuant to the foregoing provisions, or otherwise, we have been advised that in
the opinion of the Securities and Exchange Commission, such indemnification is
against public policy as expressed in the Act and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities (other
than the payment by us for expenses incurred or paid by a director, officer or
controlling person of us in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, we will, unless in the opinion
of its counsel the matter has been settled by controlling precedent, submit to a
court of appropriate jurisdiction the question whether such indemnification by
it is against public policy as expressed in the Act and will be governed by the
final adjudication of such issue.
(I) REGISTRATION STATEMENT PERMITTED BY RULE 430A UNDER THE SECURITIES ACT OF
1933
The undersigned Registrant hereby undertakes that:
For the purposes of determining liability under the Securities Act of 1933, the
information omitted from the form of prospectus filed as part of this
registration statement in reliance upon Rule 430A and contained in a form of
prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or Rule
497(h) under the Securities Act shall be deemed to be a part of this
registration statement as of the time it was declared effective.
For the purposes of determining any liability under the Securities Act of 1933,
each post-effective amendment that contains a form of prospectus shall be deemed
to be a new registration statement relating to the securities offered therein,
and the offering of such securities at that time shall be deemed to be the
initial bona fide offering thereof.
II-2
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
certifies that it has reasonable grounds to believe that it meets all of the
requirements for filing on Form S-2 and has duly caused this Registration
Statement to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Houston, Texas on January 15, 2004.
CARRIZO OIL & GAS, INC.
By: /s/ S.P. JOHNSON IV
------------------------------------
S.P. Johnson IV
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 1
to the Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ S.P. JOHNSON IV President, Chief Executive January 15, 2004
-------------------------------------- Officer and Director (Principal
S.P. Johnson IV Executive Officer)
/s/ PAUL F. BOLING Chief Financial Officer, Vice January 15, 2004
-------------------------------------- President, Secretary and
Paul F. Boling Treasurer (Principal Financial
and
Accounting Officer)
* Chairman January 15, 2004
--------------------------------------
Steven A. Webster
* Director January 15, 2004
--------------------------------------
Christopher C. Behrens
* Director January 15, 2004
--------------------------------------
Douglas A. P. Hamilton
* Director January 15, 2004
--------------------------------------
Paul B. Loyd, Jr.
* Director January 15, 2004
--------------------------------------
Bryan R. Martin
* Director January 15, 2004
--------------------------------------
F. Gardner Parker
* Director January 15, 2004
--------------------------------------
Frank A. Wojtek
*By: /s/ PAUL F. BOLING
------------------------------
Paul F. Boling
Attorney-in-fact
II-3
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
**1.1 -- Form of Underwriting Agreement
2.1 -- Combination Agreement by and among Carrizo Oil & Gas, Inc.
(the "Company"), Carrizo Production, Inc., Encinitas
Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd.,
Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV,
Douglas A.P. Hamilton and Frank A. Wojtek dated as of June
6, 1997 (incorporated by reference to Exhibit 2.1 to the
Company's Registration Statement on Form S-1 (Registration
No. 333-29187)).
4.1 -- Credit Agreement dated as of May 24, 2002 by and among the
Company, CCBM, Inc. and Hibernia National Bank (incorporated
by reference to Exhibit 4.1 to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 2002).
4.2 -- Revolving Note by and between the Company and Hibernia
National Bank dated May 24, 2002 (incorporated by reference
to Exhibit 4.2 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2002).
4.3 -- Commercial Guarantee by and between CCBM, Inc. and Hibernia
National Bank dated May 24, 2002 (incorporated by reference
to Exhibit 4.3 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2002).
4.4 -- Stock Pledge and Security Agreement by and between the
Company and Hibernia National Bank dated May 24, 2002
(incorporated by reference to Exhibit 4.4 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30,
2002).
4.5 -- First Amendment to Credit Agreement dated July 9, 2002 to
the Credit Agreement by and between the Company and Hibernia
National Bank dated May 24, 2002 (incorporated by reference
to Exhibit 4.5 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2002).
4.6 -- Amended and Restated Credit Agreement dated as of December
12, 2002 by and among the Company, CCBM, Inc. and Hibernia
National Bank (incorporated by reference to Exhibit 4.6 to
the Company's 10-K for the year ended December 31, 2002).
4.7 -- Letter Agreement Regarding Participation in the Company's
2001 Seismic and Acreage Program, dated May 1, 2001
(incorporated by reference to Exhibit 4.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30,
2001).
4.8 -- Amendment No. 1 to the Letter Agreement Regarding
Participation in the Company's 2001 Seismic and Acreage
Program, dated June 1, 2001 (incorporated by reference to
Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q
for the quarter ended June 30, 2001).
4.9 -- Promissory Note payable to Rocky Mountain Gas, Inc. by CCBM,
Inc. (incorporated by reference to Exhibit 4.3 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2001).
4.10 -- Form of Certificate representing Common Stock (incorporated
by reference to Exhibit No. 4.1 to the Company's
Registration Statement on Form S-1 (Registration No.
333-29187)).
4.11 -- The Company is a party to several debt instruments under
which the total amount of securities authorized does not
exceed 10% of the total assets of the Company and its
subsidiaries on a consolidated basis. Pursuant to paragraph
4(iii)(A) of Item 601(b) of Regulation S-K, the Company
agrees to furnish a copy of such instruments to the
Commission upon request.
**5.1 -- Opinion of Baker Botts L.L.P.
10.1 -- Amended and Restated Incentive Plan of the Company effective
as of February 17, 2000 (incorporated by reference to
Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q
for the quarter ended June 30, 2000).
10.2 -- Amendment No. 1 to the Amended and Restated Incentive Plan
of the Company (incorporated by reference to Exhibit 10.1 to
the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2002).
II-4
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.3 -- Amendment to the Amended and Restated Incentive Plan of the
Company (incorporated by reference to Exhibit 10.3 to the
Company's Report on Form 10-K for the year ended December
31, 2002).
10.4 -- Employment Agreement between the Company and S.P. Johnson IV
(incorporated by reference to Exhibit 10.2 to the Company's
Registration Statement on Form S-1 (Registration No.
333-29187)).
10.5 -- Employment Agreement between the Company and Frank A. Wojtek
(incorporated by reference to Exhibit 10.3 to the Company's
Registration Statement on Form S-1 (Registration No.
333-29187)).
10.6 -- Employment Agreement between the Company and Kendall A.
Trahan (incorporated by reference to Exhibit 10.4 to the
Company's Registration Statement on Form S-1 (Registration
No. 333-29187)).
10.7 -- Employment Agreement between the Company and Jeremy T.
Greene (incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2002).
*10.8 -- Employment Agreement between the Company and J. Bradley
Fisher.
*10.9 -- Employment Agreement between the Company and Paul F. Boling.
10.10 -- Form of Amendment to Executive Officer Employment Agreement
(incorporated by reference to Exhibit 99.3 to the Company's
Current Report on Form 8-K dated January 8, 1998).
10.11 -- Form of Amendment to Executive Officer Employment Agreement
(incorporated by reference to Exhibit 99.7 to the Company's
Current Report on Form 8-K dated December 15, 1999).
10.12 -- Form of Amendment to Executive Officer Employment Agreement
(incorporated by reference to Exhibit 99.7 to the Company's
Current Report on Form 8-K dated February 20, 2002).
10.13 -- Indemnification Agreement between the Company and each of
its directors and executive officers (incorporated by
reference to Exhibit 10.6 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1998).
10.14 -- Form of Amendment to Director Indemnification Agreement
(incorporated by reference to Exhibit 99.8 to the Company's
Current Report on Form 8-K dated December 15, 1999).
10.15 -- Form of Amendment to Director Indemnification Agreement
(incorporated by reference to Exhibit 99.8 to the Company's
Current Report on Form 8-K dated February 20, 2002).
10.16 -- S Corporation Tax Allocation, Payment and Indemnification
Agreement among the Company and Messrs. Loyd, Webster,
Johnson, Hamilton and Wojtek (incorporated by reference to
Exhibit 10.8 to the Company's Registration Statement on Form
S-1 (Registration No. 333-29187)).
10.17 -- S Corporation Tax Allocation, Payment and Indemnification
Agreement among Carrizo Production, Inc. and Messrs. Loyd,
Webster, Johnson, Hamilton and Wojtek (incorporated by
reference to Exhibit 10.9 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).
10.18 -- Amended Enron Warrant Certificates (incorporated by
reference to Exhibit 4.1 to the Company's Current Report on
Form 8-K dated December 15, 1999).
10.19 -- Securities Purchase Agreement dated December 15, 1999 among
the Company, CB Capital Investors, L.P., Mellon Ventures,
L.P. and Messrs. Loyd, Hamilton and Webster (incorporated by
reference to Exhibit 99.1 to the Company's Current Report on
Form 8-K dated December 15, 1999).
10.20 -- Shareholders Agreement dated December 15, 1999 among the
Company, CB Capital Investors, L.P., Mellon Ventures, L.P.,
Messrs. Loyd, Hamilton, Webster, Johnson and Wojtek and
DAPHAM Partnership, L.P. (incorporated by reference to
Exhibit 99.2 to the Company's Current Report on Form 8-K
dated December 15, 1999).
II-5
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.21 -- Warrant Agreement dated December 15, 1999 among the Company,
CB Capital Investors, L.P., Mellon Ventures, L.P. and
Messrs. Loyd, Hamilton and Webster (incorporated by
reference to Exhibit 99.3 to the Company's Current Report on
Form 8-K dated December 15, 1999).
10.22 -- Registration Rights Agreement dated December 15, 1999 among
the Company, CB Capital Investors, L.P. and Mellon Ventures,
L.P. (incorporated by reference to Exhibit 99.4 to the
Company's Current Report on Form 8- K dated December 15,
1999).
10.23 -- Amended and Restated Registration Rights Agreement dated
December 15, 1999 among the Company, Messrs. Loyd, Hamilton,
Webster, Johnson and Wojtek and DAPHAM Partnership, L.P.
(incorporated by reference to Exhibit 99.5 to the Company's
Current Report on Form 8-K dated December 15, 1999).
10.24 -- Compliance Sideletter dated December 15, 1999 among the
Company, CB Capital Investors, L.P. and Mellon Ventures,
L.P. (incorporated by reference to Exhibit 99.6 to the
Company's Current Report on Form 8-K dated December 15,
1999).
10.25 -- Purchase and Sale Agreement by and between Rocky Mountain
Gas, Inc. and CCBM, Inc., dated June 29, 2001 (incorporated
by reference to Exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 2001).
10.26 -- Securities Purchase Agreement dated February 20, 2002 among
the Company, Mellon Ventures, L.P. and Steven A. Webster
(incorporated by reference to Exhibit 99.1 to the Company's
Current Report on Form 8-K dated February 20, 2002).
10.27 -- Shareholders' Agreement dated February 20, 2002 among the
Company, Mellon Ventures, L.P. Messrs. Loyd, Hamilton,
Webster, Johnson and Wojtek and DAPHAM Partnership, L.P.
(incorporated by reference to Exhibit 99.3 to the Company's
Current Report on Form 8-K dated February 20, 2002).
10.28 -- Warrant Agreement dated February 20, 2002 among the Company,
Mellon Ventures, L.P. and Mr. Webster (including Warrant
Certificate) (incorporated by reference to Exhibit 99.4 to
the Company's Current Report on Form 8-K dated February 20,
2002).
10.29 -- Registration Rights Agreement dated February 20, 2002 among
the Company, Mellon Ventures, L.P. and Mr. Webster
(incorporated by reference to Exhibit 99.5 to the Company's
Current Report on Form 8-K dated February 20, 2002).
10.30 -- Compliance Sideletter dated February 20, 2002 between the
Company and Mellon Ventures, L.P. (incorporated by reference
to Exhibit 99.6 to the Company's Current Report on Form 8-K
dated February 20, 2002).
10.31 -- Contribution and Subscription Agreement dated June 23, 2003
by and among Pinnacle Gas Resources, Inc., CCBM, Inc., Rocky
Mountain Gas, Inc. and the CSFB Parties listed therein
(incorporated by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30,
2003).
10.32 -- Transition Services Agreement dated June 23, 2003 by and
between the Company and Pinnacle Gas Resources, Inc.
(incorporated by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30,
2003).
***23.1 -- Consent of Ernst & Young LLP.
*23.2 -- Consent of Ryder Scott Company Petroleum Engineers.
*23.3 -- Consent of Fairchild and Wells, Inc.
**23.4 -- Consent of Baker Botts L.L.P. (included in Exhibit 5.1).
*24.1 -- Power of Attorney.
---------------
* Previously filed.
** To be filed by amendment.
*** Filed herewith.
II-6