Back to GetFilings.com
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
COMMISSION NO. 0-22915
Carrizo Oil & Gas, Inc.
(Exact name of registrant as specified in its charter)
TEXAS 76-0415919
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
14701 ST. MARY'S LANE, SUITE 800 77079
Houston, Texas (Zip Code)
(Principal executive offices)
Registrant's telephone number, including area code: (281) 496-1352
Securities Registered Pursuant to Section 12(g) of the Act:
COMMON STOCK, $.01 PAR VALUE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
[ ]
Indicate by check mark whether the registrant is an accelerated filer.
YES [ ] NO [X]
At June 30, 2003, the aggregate market value of the registrant's Common
Stock held by non-affiliates of the registrant was approximately $27.8 million
based on the closing price of such stock on such date of $6.10.
At March 15, 2004, the number of shares outstanding of the registrant's
Common Stock was 18,401,053.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 2004
Annual Meeting of Shareholders are incorporated by reference in Part III of this
Form 10-K. Such definitive proxy statement will be filed with the Securities and
Exchange Commission not later than 120 days subsequent to December 31, 2003.
================================================================================
TABLE OF CONTENTS
PART I...................................................................... 2
Item 1. and Item 2. Business and Properties............................... 2
Item 3. Legal Proceedings................................................. 23
Item 4. Submission of Matters to a Vote of Security Holders............... 23
Executive Officers of the Registrant...................................... 23
PART II..................................................................... 24
Item 5. Market for Registrant's Common Stock, Related Shareholder
Matters and Issuer Purchases of Equity Securities...................... 24
Item 6. Selected Financial Data........................................... 25
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................. 26
Item 7A. Qualitative and Quantitative Disclosures About Market Risk....... 48
Item 8. Financial Statements and Supplementary Data....................... 48
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure............................................... 48
Item 9A. Controls and Procedures.......................................... 48
PART III.................................................................... 49
Item 10. Directors and Executive Officers of the Registrant............... 49
Item 11. Executive Compensation........................s.................. 49
Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Shareholder Matters......................................... 49
Item 13. Certain Relationships and Related Transactions................... 49
Item 14. Principal Accountant Fees and Services........................... 49
PART IV..................................................................... 49
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.. 49
PART I
ITEM 1. AND ITEM 2. BUSINESS AND PROPERTIES
GENERAL
Carrizo Oil & Gas, Inc. ("Carrizo," the "Company" or "We") is 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 traditionally grown our production through our 3-D
seismic-driven exploratory drilling program. Our compound production growth rate
for the period December 31, 1999 through December 31, 2003 on an annualized
basis was 15%. From our inception through December 31, 2003, we participated in
the drilling of 295 wells (89.9 net) with a success rate of approximately 68% 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, 2003 were
an estimated 70.4 Bcfe with a PV-10 Value of $116.0 million. During 2003, we
added 15.1 Bcfe to proved reserves and produced a record 7.5 Bcfe. We have
historically financed the majority of our drilling activity through internal
cash flow generated primarily from oil and natural gas production sales revenue.
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.
Historically, we either (1) sought to acquire seismic permits from landowners
that included options to lease the acreage prior to conducting proprietary
surveys or (2) participated in 3-D group shoots in which we typically sought to
obtain leases or farm-ins rather than lease options. 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
from libraries of seismic companies.
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. Analyzing and
reprocessing 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 December 31, 2003, we had 98,557 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.
Most of our drilling targets prior to 2000 were shallow (from 4,000 to
7,000 feet), normally pressured reservoirs that generally involved moderate cost
(typically $0.3 million to $0.4 million per completed well) and risk. Since
then, the depth of many of the wells that we have drilled, as well as our
current drilling prospects, are deeper, over-pressured targets with greater
economic potential but generally higher cost (typically $1.0 million to $4.0
million per completed well) and risk. We seek to sell a portion of these deeper
prospects to reduce our exploration risk and financial exposure while retaining
significant upside potential. More recently, we have begun to retain larger
percentages of, and increased our exposure to, higher cost, higher potential
wells. We expect to use a portion of the proceeds from our recently completed
offering to increase our percentage of and exposure to these wells.
We operate the majority of our projects through the exploratory phase.
As of December 31, 2003, we operated 94 producing oil and gas wells, which
accounted for 55% of the onshore Gulf Coast producing wells in which we had an
interest.
During 2001, through our wholly-owned subsidiary, CCBM, Inc. ("CCBM"),
we acquired 50% of the working interests held by Rocky Mountain Gas, Inc.
("RMG") in approximately 107,000 net mineral acres prospective for coalbed
methane located in the Powder River Basin in Wyoming and Montana. Subsequently,
we participated in the acquisition and/or drilling of 77 gross wells (21 net)
before jointly contributing with RMG a majority of our coalbed methane property
interests and operations into a newly, formed company, Pinnacle Gas Resources,
Inc. ("Pinnacle"). In exchange for the assets contributed, CCBM and RMG each
received a 37.5% common stock ownership in Pinnacle and options to purchase
additional common stock, or on a fully diluted basis, CCBM and RMG
2
each received a 26.9% interest in Pinnacle. Simultaneously with the contribution
of these assets, Credit Suisse First Boston Private Equity entities (the "CSFB
Parties") contributed $17.6 million cash along with a future cash commitment to
Pinnacle in exchange for common stock, warrants and preferred stock equal to a
46.2% interest on a fully diluted basis. In February 2004, the CSFB Parties
contributed additional funds of $11.8 million into Pinnacle to continue funding
the 2004 development program which will increase their ownership to 66.7% on a
fully diluted basis should we and RMG each elect not to exercise our available
options. The business operations and development program of Pinnacle does not
require us to provide any further capital infusion, unless we determine to
exercise our options. See "The Pinnacle Transaction" for more information on
this transaction.
In addition to our interest in Pinnacle, CCBM retained interests in
approximately 145,000 gross acres in the Castle Rock coalbed methane project
area in Montana and the Oyster Ridge project area in Wyoming.
In mid-2003, we became active in the Barnett Shale play located in
Tarrant and Parker counties in Northeast Texas. The Barnett Shale is a blanket
marine shale formation that is natural gas bearing at depths ranging from 6,000
to 8,500 feet and is ubiquitous across the Fort Worth Basin. Though this area
has been well known for natural gas production for many years, improvements in
fracture techniques in recent years have dramatically changed the economics of
producing this reservoir. The reserve profile from productive wells drilled in
the Barnett Shale region is noteably longer-lived compared to the typical
reserve profile from wells drilled in our onshore Gulf Coast core area.
Accordingly, we believe that developing producing reserves in the
Barnett Shale play will have the potential to lengthen our overall average
reserve life and, on balance, add a long-lived cash flow stream to fund our
future capital exploration and development program. In our Barnett Shale play to
date, including our $8.2 million acquisition in February 2004 (see the "Barnett
Shale Trend" below for more information on this transaction), and drilling
participations, we have acquired approximately 7,500 net acres and drilled 14
gross (7 net) wells. As of March 2004, our current net production and proved
reserves in the Barnett Shale trend are estimated at 2.0 Mmcfe/d and 11.3 Bcfe,
respectively.
Certain terms used herein relating to the oil and natural gas industry
are defined in "Glossary of Certain Industry Terms" below.
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 73% over the last three years.
We are drilling or plan to drill approximately 35 wells (14.3
net) in the onshore Gulf Coast area during 2004. We have
budgeted approximately $40 to $45 million for capital
expenditures in 2004, $39.8 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 December 31, 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.
3
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.
EXPLORATION APPROACH
Our exploration strategy has generally been to accumulate large amounts
of 3-D seismic data along primarily prolific, producing trends of the onshore
Gulf Coast, after obtaining options to lease areas covered by the data. We then
use 3-D seismic data to identify or evaluate prospects before drilling the
prospects that fit our risk/reward criteria. We typically seek to explore in
locations within our core areas of expertise that we believes have (1) numerous
accumulations of normally pressured reserves at shallow depths and in geologic
traps that are difficult to define without the interpretation of 3-D seismic
data and (2) the potential for large accumulations of deeper, over-pressured
reserves.
As a result of the increased availability of economic onshore 3-D
seismic surveys and the improvement and increased affordability of data
interpretation technologies, we have relied almost exclusively on the
interpretation of 3-D seismic data in our exploration strategy. We generally do
not invest any substantial portion of the costs for an exploration well without
first interpreting 3-D seismic data. The principal advantage of 3-D seismic data
over traditional 2-D seismic analysis is that it affords the geoscientist the
ability to interpret a three dimensional cube of data as compared to
interpreting between widely separated two dimensional vertical profiles.
Consequently, the geoscientist is able to more fully and accurately evaluate
prospective areas, improving the probability of drilling commercially successful
wells in both exploratory and development drilling.
Historically, we sought to obtain large volumes of 3-D seismic data by
participating in large seismic data acquisition programs either alone or
pursuant to joint venture arrangements with other energy companies, or through
"group shoots" in which we shared the costs and results of seismic surveys. By
participating in joint ventures and group shoots, we were able to share the
up-front costs of seismic data acquisition and interpretation, thereby enabling
us to participate in a larger number of projects and diversify exploration costs
and risks. Most of our operations are conducted through joint operations with
industry participants.
We have also participated in 3-D data licensing swaps, whereby we
transfer license rights to certain proprietary 3-D data we own in exchange for
license rights to other 3-D data within our core areas, thus allowing us to
obtain access to additional 3-D data within our Gulf Coast Core Areas at either
minimal or no out-of-pocket cash cost. Since 2001, we also have made significant
purchases of 3-D data from the libraries of seismic companies at favorable
pricing.
In more recent years, we have focused less on conducting proprietary
3-D surveys and have focused instead on (1) the continual interpretation and
evaluation of our existing 3-D seismic database and the drilling of identified
prospects on such acreage and (2) the acquisition of existing non-proprietary
3-D data at reduced prices, in many cases contiguous to or near existing project
areas where we have extensive knowledge and subsequent acquisition of related
acreage as we deem to be prospective based upon our interpretation of such 3-D
data.
In late 2002, we acquired (or obtained the right to acquire) an
additional 2,750 square miles of 3-D seismic data in our Gulf Coast Core Areas.
These new data are primarily either recently merged and reprocessed data sets or
former proprietary data sets newly released to industry. Specific operating
areas to which new data were added as a result of the late 2002 data acquisition
include (1) 450 square miles of newly reprocessed 3-D data to the Matagorda
project area, (2) 167 square miles of newly released 3-D data to the Liberty
Project area, (3) 239 square miles to the Wilcox project area and (4) 826 square
miles of newly reprocessed 3-D data to the South Louisiana project area. These
data acquisitions consist of existing nonproprietary data sets obtained from
seismic companies at what we believe to be attractive pricing.
4
We maintain a flexible and diversified approach to project identification by
focusing on the estimated financial results of a project area rather than
limiting our focus to any one method or source for obtaining leads for new
project areas. Our current project areas result from leads developed primarily
by our internal staff. Additionally, we monitor competitor activity and review
outside prospect generation by small, independent "prospect generators," or our
joint venture partners. We compliment our exploratory drilling portfolio through
the use of these outside sources of project generation and typically retain
operation rights. Specific drill-sites are typically chosen by our own
geoscientists.
OPERATING APPROACH
Our management team has extensive experience in the development and
management of exploration projects along the Texas and Louisiana Gulf Coast. We
believe that the experience of our management in the development, processing and
analysis of 3-D projects and data in the Gulf Coast Core Areas is a core
competency to our continued success.
We generally seek to obtain lease operator status and control over
field operations, and in particular seek to control decisions regarding 3-D
survey design parameters and drilling and completion methods. As of December 31,
2003, we operated 94 producing oil and natural gas wells.
We emphasize preplanning in project development to lower capital and
operational costs and to efficiently integrate potential well locations into the
existing and planned infrastructure, including gathering systems and other
surface facilities. In constructing surface facilities, we seek to use reliable,
high quality, used equipment in place of new equipment to achieve cost savings.
We also seek to minimize cycle time from drilling to hook-up of wells, thereby
accelerating cash flow and improving ultimate project economics.
We seek to use advanced production techniques to exploit and expand our
reserve base. Following the discovery of proved reserves, we typically continue
to evaluate our producing properties through the use of 3-D seismic data to
locate undrained fault blocks and identify new drilling prospects and performs
further reserve analysis and geological field studies using computer aided
exploration techniques. We have integrated our 3-D seismic data with reservoir
characterization and management systems through the use of geophysical
workstations which are compatible with industry standard reservoir simulation
programs.
SIGNIFICANT PROJECT AREAS
This section is an explanation and detail of some of the relevant
project groupings from our overall inventory of productive wells, seismic data
and prospects. 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:
5
3-D PROJECT SU MMARY CHART
AS OF DECEMBER 31, 2003
PRODUCTIVE 3-D NET
WELLS SEISMIC OPTIONS/ DRILLING CAPITAL EXPENDITURES
-------------- DATA LEASED -----------------------------
GROSS NET (SQ. MILES) ACRES 2003 BUDGETED 2004
----- --- ----------- ----- ---- -------------
Onshore Gulf Coast:
Wilcox................. 29 8.5 1,858 18,326 $5.5 $7.0
Frio/Vicksburg......... 139 43.6 2,129 8,922 6.6 11.6
Southeast Texas....... 11 3.8 834 4,052 4.5 9.8
South Louisiana...... 7 1.3 1,864 2,896 5.6 8.9
East Texas............... 45 5.9 472 2,816 -- 1.5
Rocky Mountain........ -- -- 473 27,140 0.8 --
Barnett Shale............ 2 .6 -- 4,028 1.6 1.0(1)
North Sea................ -- -- 153 209,613 -- --
Other Areas.............. -- -- 980 -- -- --
--- ---- ----- ------- ------ ------
Total.................. 233 63.7 8,763 277,793 $ 24.6 $ 39.8
=== ==== ===== ======= ====== ======
- ------------------------
(1) We expect to obtain a mezzanine project facility to finance a majority
of our exploration and development program in the Barnett Shale play in 2004.
Accordingly, our 2004 capital spending program in the Barnett Shale trend could
increase significantly. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources."
ONSHORE GULF COAST AREA
For purposes of presentation, 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.
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. We have budgeted
approximately $40 to $45 million to drill approximately 35 wells (14.3 net) and
to purchase and reprocess 3-D seismic surveys during 2004.
TEXAS - WILCOX AREAS
We have licenses for approximately 1,800 square miles of 3-D seismic
data and 18,326 acres of leasehold in the Wilcox trend in Texas. From January 1,
2000 through December 31, 2003, we drilled and completed 32 wells (9.2 net) on
40 attempts in this area. We incurred capital expenditures of $5.5 million and
drilled eight wells (2.3 net) in the Texas Wilcox area in 2003 and expect to
devote approximately $7.0 million to drill eight wells (3.8 net) in this area in
2004. As of March 1, 2004, 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 5,400 net acres of leasehold. From
January 1, 2000 through December 31, 2003, we 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 risk. We have a significant acreage position to
either explore ourselves or sell to third parties while retaining a promoted
interest.
TEXAS FRIO/VICKSBURG/YEGUA AREAS
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
6
Yegua formations. We have licenses for a total of over 2,100 miles of 3-D
seismic data and 8,922 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.
As of March 1, 2004, 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 drilled and
completed 38 wells (10.0 net) in 45 attempts in this trend. We incurred capital
expenditures of $6.6 million and drilled 16 wells (3.4 net) in the Frio/
Vicksburg trend area in 2003 and expect to devote approximately $11.6 million to
drill 14 wells (5.4 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 December 31, 2003 of 11.3
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 second 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 AREAS
The Southeast Texas area contains similar objective levels found in the
Frio/Vicksburg/Yegua 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 834 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.
As of March 1, 2004, 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
incurred capital expenditures of $4.5 million and drilled five wells (1.3 net)
in the Southeast Texas area in 2003 and expect to devote approximately $9.8
million and drilled nine wells (3.6 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 2004.
Cedar Point
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.
7
Liberty
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.
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 approximately 2,700 net 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 incurred
capital expenditures of $5.6 million and drilled three wells (0.7 net) in the
South Louisiana area in 2003 and expect to devote approximately $8.9 million to
drill five wells (2.5 net) in this area in 2004.
LaRose
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
In December 2003, we announced the discovery of Shadyside #1 well in
this area, which logged over 77 feet of apparent net pay. The well commenced
production during March 2004 and was producing 12,900 Mcf of natural gas and 245
barrels of oil (13,890 Mcfe) per day on March 25, 2004. 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
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 4,000 net
acres and have participated in the drilling of six wells (2.6
net) as of December 31, 2003. Since that time, we have drilled
another eight wells (4.0 net) and, through an $8.2 million
acquisition (see "Barnett Shale Trend" below) along with an
acreage leasing program, have increased our holdings in the
trend by 5,800 gross acres (3,500 net) and 21 gross wells (6.7
net);
- 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 obtain a mezzanine project facility to finance a
majority of (1) the $8.2 acquisition in the Barnett Shale trend in February 2004
and (2) our exploration and development program in the Barnett Shale play in
2004 and 2005. With the mezzanine facility, our 2004 capital spending program in
the Barnett Shale trend could be $20 to $30 million. For the remainder of
8
our other areas of interest, we expect to spend less than $2.5 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.
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 lease.
We expect to invest $1.5 million to drill eight (6.9 net) wells in this
region in 2004.
Camp Hill Project. 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,
2003, the project produced an average of 52 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, 2003 averaged $20.80 per barrel ($3.47 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,
2003) than West Texas intermediate crude due to its suitability as a lube oil
feedstock. As of December 31, 2003, we had 8.3 MMBbls of proved oil reserves in
this project, with 990 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 71% of our proved reserves and account for 50% of our present value
of net future revenues from proved reserves as of December 31, 2003. 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 March 2004 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 the
well was originally drilled, the operator perforated the objective interval and
tested gas but in uneconomic volumes. This well was drilled before newer
fracturing technologies were developed that could have increased flow rates and
during a period when gas prices were significantly lower. Assuming 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. In 2003, we acquired leases on approximately 4,100 net acres and
invested $0.9 million to drill six wells (2.6 net), two of which were completed
and producing and four of which were awaiting pipeline hookup at year end. Net
production from the two online wells (0.6 net) was a combined 380 Mcfe per day
at year end.
During 2004, we have drilled eight additional wells (4.0 net) and
acquired an additional 2,100 net acres. Seven out of our 14 gross wells were
on-line producing approximately 700 Mcfe net per day in March 2004. The
remaining seven wells are awaiting completion and pipeline hookup. We received
permits for the first proposed well, a horizontal well, for which we will act as
operator, and expect to commence drilling in the second quarter of 2004. We are
continuing to expand our leasehold acquisition in this trend.
In February 2004 we purchased specified wells and leases in the Barnett
Shale trend in Denton County, Texas from a private company for $8.2 million.
These non-operated properties have an average 39 percent working interest. The
acquisition includes 21 existing gross wells (6.7 net) and interests in
approximately 1,500 net acres, which we expect to provide another 27 gross
drillsites. Current net production from the acquired properties is approximately
1.4 MMcfe/d and net proved reserves are internally estimated at 9.7 Bcfe.
WYOMING/MONTANA COALBED METHANE PROJECT AREA
Rocky Mountain Region
9
As discussed below under "--Pinnacle Transaction," in the second
quarter of 2003, we contributed to Pinnacle our Powder River Basin properties in
the Clearmont, Kirby, Arvada and Bobcat project areas located in Wyoming and
Montana. We also own direct interests in approximately 145,000 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 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.
By 2003 year end, Pinnacle had completed the acquisition and/or
drilling of 201 wells (or approximately 96 net). All of the wells encountered
coal accumulations and are apparent successes 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.
In February 2004, the CSFB Parties contributed additional funds of
$11.8 million into Pinnacle to continue funding the 2004 development program
which will increase their ownership to 66.7% on a fully diluted basis should we
and RMG each elect not to exercise our available options. The business
operations and development program of Pinnacle does not require us to provide
any further capital infusion, unless we determine to exercise our options. See
"-The Pinnacle Transaction" below for more information on this transaction.
Of the approximate 319,000 gross and 90,000 net mineral acres held by
us and Pinnacle, respectively, as of December 31, 2003, approximately 193,000
and 21,000 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.
OTHER PROJECT AREAS
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
209,613 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 will ultimately 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 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.
Although we have identified or budgeted for numerous drilling
prospects, we may not be able to lease or drill those prospects
10
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. Our final determination of whether
to drill any scheduled or budgeted wells will be dependent on a number of
factors, including (1) the results of our exploration efforts and the
acquisition, review and analysis of the seismic data; (2) the availability of
sufficient capital resources to us and the other participants for the drilling
of the prospects; (3) the approval of the prospects by the other participants
after additional data has been compiled; (4) 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 (5)
the availability of leases and permits on reasonable terms for the prospects.
There can be no assurance that these projects can be successfully developed or
that any identified drillsites or budgeted wells discussed will, if drilled,
encounter reservoirs of commercially productive oil or natural gas. We may seek
to sell or reduce all or a portion of our interest in a project area or with
respect to prospects or wells within a project area.
Our success will be materially dependent upon the success of our
exploratory drilling program, which is an activity that involves numerous risks.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations--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."
OIL AND NATURAL GAS RESERVES
The following table sets forth our estimated net proved oil and natural
gas reserves and the PV-10 Value of such reserves as of December 31, 2003. The
reserve data and the present value as of December 31, 2003 were prepared by
Ryder Scott Company and Fairchild & Wells, Inc., Independent Petroleum
Engineers. For further information concerning Ryder Scott's and Fairchild's
estimate of our proved reserves at December 31, 2003, see the reserve reports
included as exhibits to this Annual Report on Form 10-K. 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 oil and natural gas reserves owned by us. For further
information concerning the present value of future net revenue from these proved
reserves, see Note 15 of Notes to Consolidated Financial Statements.
PROVED RESERVES
-------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- --------
(DOLLARS IN THOUSANDS)
Oil and condensate (MBbls) 1,395 7,319 8,714
Natural gas (MMcf) 17,098 971 18,069
Total proved reserves (MMcfe) 25,466 44,887 70,353
PV-10 Value(1) $ 81,567 $ 34,408 $115,975
- ------------------------
(1) The PV-10 Value as of December 31, 2003 is pre-tax and was determined
by using the December 31, 2003 sales prices, which averaged $30.29 per
Bbl of oil, $6.19 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 Securities
and Exchange Commission (the "Commission"). The reserve data set forth in this
Annual Report on Form 10-K represent only estimates. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Risk
Factors--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."
Our future oil and natural gas production is highly dependent upon our
level of success in finding or acquiring additional reserves. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Risk
Factors--We depend on successful exploration, development and acquisitions to
maintain reserves and revenue in the future." Also, the failure of an operator
of our wells to adequately perform operations, or such operator's breach of the
applicable agreements, could adversely impact us. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Risk Factors--We
cannot control the activities on properties we do not operate and are unable to
ensure their proper operation and profitability."
VOLUMES, PRICES AND OIL & NATURAL GAS OPERATING EXPENSE
11
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 oil and natural gas 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,
---------------------------------
2001 2002 2003
--------- --------- ---------
Production volumes
Oil (MBbls) 160 401 450
Natural gas (MMcf) 4,432 4,801 4,763
Natural gas equivalent (MMcfe) 5,390 7,207 7,463
Average sales prices
Oil (per Bbl) $ 24.28 $ 24.94 $ 28.90
Natural gas (per Mcf) 5.04 3.50 5.35
Natural gas equivalent (per Mcfe) 4.87 3.72 5.16
Average costs (per Mcfe)
Camp Hill operating expenses $ 2.14 $ 2.50 $ 3.45
Other operating expenses 0.43 0.44 0.58
Total operating expenses(1) 0.77 0.68 0.90
- ------------------------
(1) Includes direct lifting costs (labor, repairs and maintenance,
materials and supplies), workover costs and the administrative costs of
production offices, insurance and property and severance taxes.
FINDING AND DEVELOPMENT COSTS
The table below reconciles our 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 $3.2 million, $3.1 million and $2.9 million for the years ended
December 31, 2001, 2002 and 2003, respectively. We have also included
capitalized overhead in our finding cost of $1.0 million, $1.0 million and $1.4
million for the years ended December 31, 2001, 2002 and 2003, respectively. We
have also included non-cash asset retirement obligations of $0.7 million for the
year ended December 31, 2003.
12
Year Ended December 31,
-------------------------------------
2001 2002 2003
-------- -------- ---------
(In thousands)
Acquisition costs:
Unproved properties contributed to Pinnacle $ 5,239 $ 1,323 $ -
Other unproved properties 7,368 5,079 7,280
Proved properties 800 660 -
Exploration 18,356 14,194 23,745
Development 3,065 2,351 112
Asset retirement obligation - - 744
-------- -------- ---------
Total costs incurred $ 34,828 $ 23,607 $ 31,881
======== ======== =========
Less unproved properties contributed to Pinnacle $ 5,239 $ 1,323 $ -
-------- -------- ---------
Adjusted costs $ 29,589 $ 22,284 $ 31,881
======== ======== =========
Total proved reserves added 15,018 11,761 15,138
-------- -------- ---------
Average all-sources finding cost (per Mcfe) (1) $ 1.97 $ 1.89 $ 2.11
======== ======== =========
- ------------------------
(1) 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.
For the three year period ended December 31, 2003, our total adjusted
costs for development, exploration and acquisition activities was approximately
$83.8 million. Total exploration, development and acquisition activities for the
three year period ended December 31, 2003 have added approximately 41.9 Bcfe of
net proved reserves at an all-sources finding cost of $2.00 per Mcfe.
Our finding and development costs have historically fluctuated on a
year-to-year basis. Finding and development costs, as measured annually, may not
be indicative of our ability to economically replace oil and natural gas
reserves because the recognition of costs may not necessarily coincide with the
addition of proved reserves.
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,
---------------------------------
2001 2002 2003
-------- -------- --------
(IN THOUSANDS)
Acquisition costs
Unproved prospects $ 12,607 $ 6,402 $ 7,280
Proved properties 800 660 -
Exploration 18,356 14,194 23,745
Development 3,065 2,351 112
Asset retirement obligation - - 744
-------- -------- --------
Total costs incurred(1) $ 34,828 $ 23,607 $ 31,881
======== ======== ========
- ------------------------
(1) Excludes capitalized interest on unproved properties of $3.2 million,
$3.1 million and $2.9 million for the years ended December 31, 2001,
2002, and 2003, respectively, and includes capitalized overhead of $1.0
million, $1.0 million and $1.4 million for the years ended December 31,
2001, 2002 and 2003, respectively. The table also includes non-cash
asset retirement obligations of
13
$0.7 million for the year ended December 31, 2003.
.
DRILLING ACTIVITY
The following table sets forth our drilling activity for the years
ended December 31, 2001, 2002 and 2003. 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, 2003 has resulted in a commercial success rate of
approximately 71%.
YEAR ENDED DECEMBER 31,
----------------------------------------------
2001 2002 2003
------------ ------------- ------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Exploratory Wells
Productive 18 5.9 16 5.6 33 9.2
Nonproductive 5 1.4 3 1.1 5 0.8
-- --- -- --- -- ----
Total 23 7.3 19 6.7 38 10.0
== === == === == ====
Development Wells
Productive 2 0.3 1 0.4 1 0.2
Nonproductive - - - - - -
-- --- -- --- -- ----
Total 2 0.3 1 0.4 1 0.2
= === = === = ===
At December 31, 2002 and 2003, we had ownership in 11 and 12 gross (2.7
and 3.2 net) wells, respectively, with dual completion in single bore holes. The
above table excludes 77 gross (29 net) wells drilled or acquired by CCBM through
2003, a majority of which were contributed to Pinnacle during 2003. The wells
contributed to Pinnacle are in various stages of development and/or stages of
production. See "Wyoming/Montana Coalbed Methane Project Area" below.
PRODUCTIVE WELLS
The following table sets forth the number of productive oil and natural
gas wells in which we owned an interest as of December 31, 2003. This table
excludes all wells drilled or acquired by CCBM through 2003, a majority of which
were contributed to Pinnacle in that year.
COMPANY
OPERATED OTHER TOTAL
------------ -------------- -------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Oil 53 48 10 3 63 51
Natural gas 41 20 68 18 109 38
-- -- -- -- --- --
Total 94 68 78 21 172 89
== == == == === ==
ACREAGE DATA
The following table sets forth certain information regarding our
developed and undeveloped lease acreage as of December 31, 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
oil or natural gas in commercial quantities is being produced from a well on
such leases.
DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL
----------------- ------------------- -----------------
GROSS NET GROSS NET GROSS NET
------ ------- -------- -------- ------- -------
North Sea - - 209,613 209,613 209,613 209,613
Louisiana 1,545 526 4,550 2,370 6,095 2,896
Texas 39,940 14,696 45,100 20,114 85,040 34,810
Montana/Wyoming - - 145,376 16,710 145,376 16,710
------ ------ ------- ------- ------- -------
Total 41,485 15,222 404,639 248,807 446,124 264,029
====== ====== ======= ======= ======= =======
14
The table does not include 7,422 gross and 3,334 net acres that we had
a right to acquire in Texas, pursuant to various seismic and lease option
agreements at December 31, 2003. Under the terms of our option 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 10,430 net acres in Wyoming that CCBM has the right to earn
pursuant to certain 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 "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Risk Factors--Natural gas and oil prices are highly
volatile, and lower prices will negatively affect our financial results,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Risk Factors--We are subject to various governmental regulations
and environmental risks" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations - 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," "Qualitative and
Quantitative Disclosures About Market Risk--Derivative Instruments and Hedging
Activities," and "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Risk Factors--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 benefiting to the fullest extent
possible from increases in prices for natural gas and oil."
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.
15
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 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.
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 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
16
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 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. The failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal
penalties, imposition of investigatory or remedial obligations or the issuance
of injunctions prohibiting or limiting the extent of our 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.
17
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 "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Risk Factors--We are subject to various governmental
regulations and environmental risks."
CERCLA, also known as the "Superfund" law, and analogous state laws
impose liability, without regard to fault or the legality of the original
conduct, on 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.
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. 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 or seek coverage under an EPA general permit. 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
18
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.
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 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.
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.
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.
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."
CUSTOMERS
We sold oil and natural gas production representing more than 10% of
our oil and natural gas revenues for the year ended December 31, 2003 to WMJ
Investments Corp. (16%), Cokinos Natural Gas Company (15%) and Gulfmark Energy,
Inc. (14%); for the year ended December 31, 2002 to Cokinos Natural Gas Company
(12%) and Discovery Producer Services, LLC (10%); and for the year ended
December 31, 2001 to Cokinos Natural Gas Company (17%). Because alternate
purchasers of oil and natural gas are readily available, we believe that the
loss of any of our purchasers would not have a material adverse effect on our
financial results.
EMPLOYEES
At December 31, 2003, we had 38 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,
19
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.
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.
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 each received 37.5% of the common stock of Pinnacle and options
to purchase additional Pinnacle common stock, or on a fully diluted basis, we
each received an ownership interest in Pinnacle of 26.9%. We retained our
interests in approximately 145,000 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 currently have greater than 50%
of the voting power of the Pinnacle capital stock through their ownership of
Pinnacle common and preferred stock.
In February 2004, the CSFB parties contributed additional funds of
$11.8 million to continue funding the 2004 development program of Pinnacle.
Assuming that we and RMG exercise our Pinnacle options, the CSFB parties'
ownership interest in Pinnacle would be 54.6%, and we and RMG each would own
22.7%, on a fully diluted basis. On the other hand, assuming we and RMG each
elect not to exercise our Pinnacle options, our interest, on a fully diluted
basis, would each decline to 16.7%, and, concurrently, CSFB parties' ownership
interest would increase to 66.7%. Our options are exercisable as long as we own
Pinnacle common stock, but the exercise price increases by 10% every year.
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 $14.5 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 December 31, 2003, Pinnacle
owned interests in approximately 131,000 gross acres in the Powder River Basin.
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as
used herein. All volumes of natural gas referred to herein 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.
After payout. With respect to an oil or gas interest in a property,
refers to the time period after which the costs to drill and equip a well have
been recovered.
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.
Bcf. Billion cubic feet.
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.
20
Before payout. With respect to an oil or gas interest in a property,
refers to the time period before which the costs to drill and equip a well have
been recovered.
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 oil or natural gas or, in the case of a dry hole, the reporting of
abandonment to the appropriate agency.
Developed acreage. The number of acres which 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 oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.
Farm-in or farm-out. An agreement where under the owner of a working
interest in an oil and natural gas lease assigns the working interest or a
portion thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to earn
its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out."
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 are capitalized by us 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.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
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 and natural
gas liquids as compared to natural gas. Prices have historically often been
higher or substantially higher for oil than natural gas on an energy equivalent
basis, although
21
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.
Normally pressured reservoirs. Reservoirs with a formation-fluid
pressure equivalent to 0.465 psi per foot of depth from the surface. For
example, if the formation pressure is 4,650 psi at 10,000 feet, then the
pressure is considered to be normal.
Over-pressured reservoirs. Reservoirs subject to abnormally high
pressure as a result of certain types of subsurface formations.
Petrophysical study. Study of rock and fluid properties based on well
log and core analysis.
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 developed nonproducing reserves. Proved developed reserves
expected to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.
Proved developed reserves. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage 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
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, future
income tax expense and depreciation, depletion and amortization, and discounted
using an annual discount rate of 10%.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
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 oil or natural gas production free of costs of
production.
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.
22
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.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are 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 our financial position or results
of operations.
In July 2001, we were notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as our Neblett lease in Starr County, Texas. The Neblett lease is part of a unit
in N. La Copita Prospect in which we own 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 filed a counterclaim against GMT
and all the non-operators, including us, to establish the validity of their
lease, remove cloud on title, quiet title to the property, and for conversion,
trespass and punitive damages. We, along with GMT and other partners, reached a
final settlement with ExxonMobil on February 11, 2003. Under the terms of the
settlement, we recovered the balance of our 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 our
reported proved reserves as of December 31, 2001 and 2002.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General
Instruction G(3) to Form 10-K, the following information is included in Part I
of this Form 10-K.
The following table sets forth certain information with respect to our
executive officers.
NAME AGE POSITION
- --------------------------- ---- ---------------------------------------
S.P. Johnson IV............ 48 President, Chief Executive Officer and
Director
Paul F. Boling............. 50 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.......... 43 Vice President of Operations
Set forth below is a description of the backgrounds of each of our
executive officers.
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
23
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 various managerial and technical positions, last serving as Senior Vice
President of Engineering and Operations. Mr. Fisher holds a B.S. degree in
Petroleum Engineering from Texas A&M University.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK, RELATED SHAREHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
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............................... $ 6.00 $ 4.10
Second Quarter.............................. 5.75 4.26
Third Quarter............................... 4.70 3.60
Fourth Quarter.............................. 5.73 3.90
2003:
First Quarter............................... 5.90 4.50
Second Quarter.............................. 6.88 4.25
Third Quarter............................... 7.44 5.00
Fourth Quarter.............................. 7.94 6.30
The closing market price of our common stock on March 25, 2004 was
$6.55 per share. As of March 25, 2004, there were an estimated 65 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."
In February 2004 in connection with our public offering, Mellon
Ventures, L.P. exercised all of its warrants to purchase 168,422 shares of our
common stock issued in 2002 and 61,199 of its warrants to purchase shares issued
in 1999 on a cashless "net exercise" basis. This transaction was exempt from the
registration requirements of the Securities Act of 1933, as amended, by virtue
of Section 4(2) as a transaction not involving any public offering and by virtue
of Section 3(a)(9).
24
ITEM 6. SELECTED FINANCIAL DATA
Our financial information set forth below for each of the five years
ended December 31, 2003, has been derived from our audited consolidated
financial statements. The information should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and our consolidated financial statements and related notes included
in Item 8. Financial Statements and Supplementary Data.
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------
1999 2000 2001 2002 2003
--------- ------------ ---------- ---------- --------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenues $ 10,204 $ 26,834 $ 26,226 $ 26,802 $ 38,508
Costs and expenses:
Oil and natural gas operating expenses 3,036 4,941 4,138 4,908 6,724
Depreciation, depletion and
amortization 4,301 7,170 6,492 10,575 11,868
Write-down of oil and gas properties - - - - -
General and administrative 2,195 3,143 3,333 4,133 5,639
Accretion expense related to asset retirement - - - - 41
Stock option compensation expense (income) - 652 (558) (85) 313
--------- ------------ ---------- ---------- --------------
Total costs and expenses 9,532 15,906 13,405 19,531 24,585
--------- ------------ ---------- ---------- --------------
Operating income 672 10,928 12,821 7,271 13,923
Equity in Pinnacle Gas Resources, Inc. - - - - (830)
Interest expense (income) (net of amounts
capitalized and interest income) 13 579 269 54 (18)
Other income and expenses, net - 1,482 1,777 274 28
--------- ------------ ---------- ---------- --------------
Income before income taxes 685 12,989 14,867 7,599 13,103
Income tax expense (benefit) (1,057) 1,004 5,336 2,809 5,063
--------- ------------ ---------- ---------- --------------
Net income before cumulative effect of change
in accounting principle 1,742 11,985 9,531 4,790 8,040
Dividends and accretion of discount on preferred stock - - - - 741
--------- ------------ ---------- ---------- --------------
Net income available to common shareholders
before cumulative effect of change
in accounting principle 1,742 11,985 9,531 4,790 7,299
Cumulative effect of change in accounting principle (78) - - - 128
--------- ------------ ---------- ---------- --------------
Net income available to common shareholders (1) $ 1,664 $ 11,985 $ 9,531 $ 4,790 $ 7,171
========= ============ ========== ========== ==============
Basic earnings per share(1) $ 2.00 $ 0.85 $ 0.68 $ 0.30 $ 0.50
========= ============ ========== ========== ==============
Diluted earnings per share(1) $ 2.00 $ 0.74 $ 0.57 $ 0.26 $ 0.43
========= ============ ========== ========== ==============
Basic weighted average shares outstanding 10,544 14,028 14,059 14,158 14,312
Diluted weighted average shares outstanding 10,546 16,256 16,731 16,148 16,744
STATEMENTS OF CASH FLOW DATA:
Net cash provided by operating activities $ 2,200 $ 17,133 $ 23,951 $ 19,925 $ 35,059
Net cash used in investing activities (14,179) (16,438) (31,224) (24,100) (31,101)
Net cash provided by (used in) financing activities 21,457 (3,823) 2,292 5,682 (5,379)
OTHER OPERATING DATA:
Capital expenditures $ 10,286 $ 19,746 $ 38,264 $ 26,707 $ 33,358
Debt repayments (2) 8,174 3,923 5,479 8,745 5,951
25
AS OF DECEMBER 31,
-----------------------------------------------------------
1999 2000 2001 2002 2003
--------- --------- --------- --------- ---------
BALANCE SHEET DATA:
Working capital (deficit) $ 8,338 $ 6,433 $ (582) $ (1,442) $ (11,817)
Property and equipment, net 64,337 72,129 104,132 120,526 135,273
Total assets 83,666 93,000 117,392 135,388 156,803
Long-term debt, including current
maturities 37,170 34,556 38,188 39,495 36,253
Mandatorily redeemable preferred stock - - - -
Convertible participating preferred stock - - - 6,373 7,114
Equity 40,853 52,939 63,204 66,816 76,072
- ------------------------
(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.
(2) Debt repayments include amounts refinanced.
Forward Looking Statements. The statements contained in all parts of
this document, (including any portion attached hereto) including, but not
limited to, those relating to our schedule, targets, estimates or results of
future drilling, including the number, timing and results of wells, budgeted
wells, increases in wells, the timing and risk involved in drilling follow-up
wells, expected working or net revenue interests, planned expenditures,
prospects budgeted and other future capital expenditures, risk profile of oil
and gas exploration, acquisition of 3-D seismic data (including number, timing
and size of projects), planned evaluation of prospects, probability of prospects
having oil and natural gas, expected production or reserves, increases in
reserves, acreage, working capital requirements, hedging activities, the ability
of expected sources of liquidity to implement our business strategy, future
hiring, future exploration activity, production rates, potential drilling
locations targeting coal seams, the outcome of legal challenges to new coalbed
methane drilling permits in Montana, a mezzanine project facility to finance
a majority of the February 2004 acquisition costs in the Barnett Shale trend
and the exploration and development expenditures in that trend, all and any
other statements regarding future operations, financial results, business plans
and cash needs and other statements that are not historical facts are forward
looking statements. When used in this document, the words "anticipate,"
"budgeted," "targeted," "potential," "estimate," "expect," "may," "project,"
"believe" and similar expressions are intended to be among the statements that
identify forward looking statements. Such statements involve risks and
uncertainties, including, but not limited to, those relating to our dependence
on our exploratory drilling activities, the volatility of oil and natural gas
prices, the need to replace reserves depleted by production, operating risks of
oil and natural gas operations, our dependence on our key personnel, factors
that affect our ability to manage our growth and achieve our business strategy,
risks relating to our limited operating history, technological changes, our
significant capital requirements, the potential impact of government
regulations, adverse regulatory determinations, including those related to
coalbed methane drilling in Montana, litigation, competition, the uncertainty of
reserve information and future net revenue estimates, property acquisition
risks, industry partner issues, availability of equipment, weather and other
factors detailed herein and in our other filings with the Securities and
Exchange Commission. Some of the factors that could cause actual results to
differ from those expressed or implied in forward-looking statements are
described under "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Risk Factors" and in other sections of this report.
Should one or more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual outcomes may vary materially from
those indicated. All subsequent written and oral forward-looking statements
attributable to us or persons acting on our behalf are expressly qualified in
their entirety by reference to these risks and uncertainties. You should not
place undue reliance on forward-looking statements. Each forward-looking
statement speaks only as of the date of the particular statement.
ITEM 7. 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 Form 10-K.
GENERAL OVERVIEW
For the year ended December 31, 2003, we achieved record annual
drilling success rates, levels of production, natural gas and oil revenues and
our proved oil and gas reserves at the end of 2003 also reached a record level.
26
Due to our drilling success, we produced a record 7.5 Bcfe in 2003
compared to 7.2 Bcfe in 2002. At the end of 2003, we also reached a record
estimated proved reserves level of 70.4 Bcfe with our 15.1 Bcfe net additions
for the year, replacing 196% of our 2003 production.
In 2003, we drilled 39 wells (10.2 net), including 33 wells in the
onshore Gulf Coast and six wells in the Barnett Shale play, with a success rate
of 90% compared to a success rate of 85% in 2002, in which we drilled 20 wells
(7.1 net), in the onshore Gulf Coast. Between January 1, 2001 and December 31,
2003, 95% of our wells drilled were exploratory and 5% were developmental. In
2003, 97% of these wells were exploratory and 3% were developmental.
In 2003, our natural gas and oil revenues reached a record level at
$38.5 million, and our net income available to common shareholders was $7.2
million, or $0.50 and $0.43 per basic and fully diluted share, respectively. In
2002, our natural gas and oil revenues were $26.8 million, and our net income
available to common shareholders was $4.8 million, or $0.30 and $0.26 per basic
and fully diluted share, respectively. These increases in natural gas and oil
revenues and net income were attributable in part to the record levels of
production discussed above and to higher 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 53% higher and our realized oil price was 16% higher in
2003 than 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.
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 $33.4 million in 2003.
At December 31, 2003, our debt-to-total book capitalization ratio was
30.4%, a 16.7% improvement from the 36.5% ratio 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. The debt
reductions are 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.
Secondary Common Stock Offering
In the first quarter of 2004, we completed the public offering of
6,485,000 shares of our common stock at $7.00 per share. The offering included
3,655,500 newly issued shares offered by us and 2,829,500 shares offered by
certain existing stockholders. We expect to use our estimated net proceeds of
$23.5 million from this offering to accelerate our drilling program and to
retain larger interests in portions of our drilling prospects that we otherwise
would sell down or for which we would seek joint partners and for general
corporate purposes. In the meantime, we used a portion of the net proceeds to
repay the $7 million outstanding principal
27
amount under our revolving credit facility. We did not receive any proceeds from
the shares offered by the selling stockholders.
Barnett Shale Acquisition
On February 27, 2004, we closed a transaction with a private company to
acquire working interests and acreage in certain oil and gas wells located in
the Newark East Field in Denton County, Texas in the Barnett Shale trend. This
acquisition, with a purchase price of $8.2 million, includes non-operated
working interests in properties ranging from 12.5% to 45% over 3,800 gross
acres, or an average working interest of 39%. The acquisition includes 21
existing gross wells (6.7 net) and interests in approximately 1,500 net acres,
which we expect to provide another 31 gross drill sites: 13 of which will target
proved undeveloped reserves and 18 of which will be exploratory. Current net
production from the acquired properties in March 2004 was approximately 1.4
Mmcfe/d and net proved reserves are internally estimated at 9.7 Bcfe.
Initially, we financed the acquisition with our available cash on hand.
In the near term, we expect to establish a new project financing facility to
refinance a majority of the acquisition and to fund a majority of our 2004 and
2005 capital expenditure program for the Barnett Shale play.
.
RESULTS OF OPERATIONS
Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002
Oil and natural gas revenues for 2003 increased 44% to $38.5 million
from $26.8 million in 2002. Production volumes for natural gas in 2003 decreased
1% to 4,763 MMcf from 4,801 MMcf in 2002. Realized average natural gas prices
increased 53% to $5.35 per Mcf in 2003 from $3.50 per Mcf in 2002. Production
volumes for oil in 2003 increased 12% to 450 MBbls from 401 MBbls in 2002. The
increase in oil production was due primarily to the commencement of production
at the Pauline Huebner A-382 #1, Beach House #1 Hankamer and Espree #1. Natural
gas production was virtually unchanged compared to 2002 or declined less than
1%. Oil and natural gas revenues include the impact of hedging activities as
discussed below under "Volatility of Oil and Gas Prices."
Average oil prices increased 16% to $28.90 per bbl in 2003 from $24.94
per bbl in 2002.
The following table summarizes production volumes, average sales prices
and operating revenues for our oil and natural gas operations for the years
ended December 31, 2002 and 2003:
2003 PERIOD
COMPARED TO 2002 PERIOD
DECEMBER 31, ------------------------------
----------------------- INCREASE % INCREASE
2002 2003 (DECREASE) (DECREASE)
-------- -------- ---------- ----------
Production volumes-
Oil and condensate (Mbbls) 401 450 49 12%
Natural gas (MMcf) 4,801 4,763 (38) (1%)
Average sales prices-(1)
Oil and condensate (per Bbl) $ 24.94 $ 28.90 $ 3.96 16%
Natural gas (per Mcf) 3.50 5.35 1.85 53%
Operating revenues (In thousands) -
Oil and condensate $ 10,001 $ 13,014 $ 3,013 30%
Natural gas 16,801 25,494 8,693 52%
-------- -------- --------
Total $ 26,802 $ 38,508 $ 11,706 44%
======== ======== ========
- ------------------------
(1) Including the impact of hedging.
Oil and natural gas operating expenses for 2003 increased 37% to $6.7
million from $4.9 million in 2002. Oil and natural gas operating expenses
increased primarily due to higher severance taxes of $0.9 million on higher
commodity prices, higher lifting costs of $0.9 million attributable to the
increased number of producing wells and in part due to higher ad valorem taxes.
Operating expenses per equivalent unit in 2003 increased to $0.90 per Mcfe from
$0.68 per Mcfe in 2002. The per unit cost increased primarily as a result of the
higher costs noted above.
28
Depreciation, depletion and amortization ("DD&A") expense for 2003
increased 12% to $11.9 million from $10.6 million in 2002. This increase was
primarily due to the increased land, seismic and drilling costs added to the
proved property cost base.
General and administrative ("G&A") expense for 2003 increased 37% to
$5.6 million from $4.1 million for 2002. The increase in G&A was due primarily
to higher incentive compensation of $0.6 million, executive severance of $0.3
million, increased legal and professional fees attributable to special projects
and rising insurance costs of $0.1 million.
We recorded a $0.8 million aftertax charge, or $0.05 per fully diluted
share, on our minority interest in Pinnacle. Of this charge, $0.2 million, or
$0.01 per fully diluted share, relates to a valuation allowance for federal
income taxes. It is likely that Pinnacle will continue to record a valuation
allowance on the deferred federal tax benefit generated from the operating
losses incurred during the early development stages of Pinnacle's coalbed
methane project. Concurrently, we will record valuation allowances relative to
our share of Pinnacle's financial results.
Income taxes increased to $5.1 million in 2003 from $2.8 million in
2002 due to the increase in pre-tax income.
Dividends and accretion of discount on preferred stock increased to
$0.7 million in 2003 from $0.6 million in 2002 as a result of the declaration of
dividends on preferred stock in 2003.
Net income for 2003 increased to $8.0 million from $4.8 million in 2002
primarily as a result of the factors described above.
Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001
Oil and natural gas 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. 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. The
increase in oil production was due primarily to the commencement of production
at the Delta Farms #1, Riverdale #2, Staubach #1 and Burkhart #1R wells offset
by the natural decline in production of other older wells. The increase in
natural gas production was due primarily to the commencement of production at
the Delta Farms #1, Riverdale #2, Staubach #1, Burkhart #1R and Pauline Huebner
A-382 #1 wells offset by the natural decline in production at other wells,
primarily from the initial Matagorda County Project wells. Oil and natural gas
revenues include the impact of hedging activities as discussed below under
"Volatility of Oil and Gas Prices."
Average oil prices increased 3% to $24.94 per bbl in 2002 from $24.28
per bbl in 2001.
The following table summarizes production volumes, average sales prices
and operating revenues for our oil and natural gas operations for the years
ended December 31, 2001 and 2002:
2002
DECEMBER 31, COMPARED TO 2001
---------------------- INCREASE % INCREASE
2001 2002 (DECREASE) (DECREASE)
--------- --------- ---------- -----------
Production volumes-
Oil and condensate (Mbbls) 160 401 241 151%
Natural gas (MMcf) 4,432 4,801 369 8%
Average sales prices-(1)
Oil and condensate (per Bbl) $ 24.28 $ 24.94 $ 0.66 3%
Natural gas (per Mcf) 5.04 3.50 (1.54) (31%)
Operating revenues (In thousands) -
Oil and condensate $ 3,877 $ 10,001 $ 6,124 158%
Natural gas 22,349 16,801 (5,548) (25%)
--------- --------- ---------
Total $ 26,226 $ 26,802 $ 576 2%
========= ========= =========
- ------------------------
(1) Including the impact of hedging.
29
Oil and natural gas operating expenses for 2002 increased 19% to $4.9
million from $4.1 million in 2001. Oil and natural gas operating expenses
increased primarily as a result of the addition of new oil and gas 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
decline.
DD&A expense for 2002 increased 63% to $10.6 million from $6.5 million
in 2001. This increase was primarily due 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 was due primarily to the addition of contract
staff to handle increased drilling and production activities and higher
insurance costs.
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.
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 the 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.
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 liquidity position has been enhanced by our receipt of
approximately $23.5 million in net proceeds from the completion of our 2004
public offering as described in " -- General Overview -- Secondary Common Stock
Offering." Our other 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 $24.0 million, $19.9
million and $35.1 million for 2001, 2002 and 2003, respectively. The decrease in
cash flows provided by operating activities in 2002 as compared to 2001 was due
primarily to the one-time gains on the sale of an investment in MPC in 2001.
This increase in cash flows provided by operations in 2003 as compared to 2002
was due primarily to higher commodity prices and higher trade payables in 2003.
Estimated maturities of long-term debt, including our seismic
obligation, are $2.1 million in 2004, $7.1 million in 2005 and the remainder in
2007. The following table sets forth estimates of our contractual obligations as
of December 31, 2003:
30
PAYMENTS DUE BY YEAR
-------------------------------------------------
(IN THOUSANDS)
2005 TO
TOTAL 2004 2006 2007
---------- ---------- ---------- ----------
Long-Term Debt $ 35,150 $ 1,037 $ 7,122 $ 26,991
Seismic Obligation 1,103 1,103 -- --
Operating Leases 263 263 -- --
---------- ---------- ---------- ----------
Total Contractual
Cash Obligations $ 36,516 $ 2,403 $ 7,122 $ 26,991
========== ========== ========== ==========
We have budgeted capital expenditures in 2004 of approximately $45.0
million, of which $39.8 million is expected to be used for drilling activities
in our project areas and the balance is expected to be used to fund 3-D seismic
surveys, land acquisitions and capitalized interest and overhead costs. We have
budgeted to drill approximately 35 gross wells (14.3 net) in the Gulf Coast
region and 13 gross wells (9.4 net) in our East Texas area and Barnett Shale
trend in 2004. We expect to obtain a mezzanine project facility to finance a
majority our acquisition, exploration and development program in the Barnett
Shale trend in 2004. Assuming we are successful in obtaining this facility, our
capital expenditures in the trend could be between $20 and $30 million in 2004.
The actual number of wells drilled and capital expended is dependent upon
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. Oil and gas capital
expenditures were $38.2 million, $26.7 million and $33.4 million for 2001, 2002
and 2003, respectively. Our drilling efforts resulted in the successful
completion of 20 gross wells (5.9 net) in 2001, 17 gross wells (6.0 net) in 2002
and 35 gross wells (9.4 net) in 2003 in the Gulf Coast region. Of the 77 gross
wells (29.0 net) drilled or acquired by CCBM, a majority have been contributed
to Pinnacle.
CCBM spent $4.6 million for drilling costs through December 2003, 50%
of which would be spent pursuant to an obligation to fund $2.5 million of
drilling costs on behalf of RMG. Through December 31, 2003, CCBM has satisfied
$2.3 million of its drilling obligations on behalf of RMG. Pinnacle has reported
that it drilled 124 gross wells during the second half of 2003 and completed
just under half of them by year-end 2003. Pinnacle reportedly added
approximately 10.0 Bcf of net proved reserves through development drilling
through December 31, 2003. Its gross operated production has increased by
approximately 70% since its inception (to approximately 8.2 MMcf/d), and its
total well count stands at 369 gross operated wells, according to Pinnacle.
FINANCING ARRANGEMENTS
Hibernia Credit Facility
On May 24, 2002, we entered into a credit agreement with Hibernia
National Bank (the "Hibernia Facility") which matures on January 31, 2005, and
repaid our 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 our assets and is guaranteed by our
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 January 31, 2004 was $16.0
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.
On December 12, 2002, we 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 and 2003 was
$15.5 million and $19.0 million, respectively, of which $8.5 and $7.0 million,
respectively, were drawn as of such dates. 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. We used proceeds from our
offering in February 2004 to repay the outstanding balance under the Hibernia
Facility. As of March 29, 2004, no amounts were drawn under the Hibernia
Facility.
31
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 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.
For each tranche of principal borrowed under the revolving line of
credit, the interest rate will be, at our 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.
We are 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 our common or preferred stock,
speculative commodity transactions, and other matters.
At December 31, 2002 and 2003, amounts outstanding under the Hibernia
Facility totaled $8.5 million and $7.0 million, respectively, with an additional
$4.3 million and $12.0 million, respectively, available for future borrowings.
At December 31, 2002 and 2003, one letter of credit was issued and outstanding
under the Hibernia Facility in the amount of $0.2 million.
Rocky Mountain Gas Note
In June 2001, 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, 2002 and 2003, the outstanding principal balance of
this note was $5.3 million and $0.9 million, respectively. In connection our
investment in Pinnacle, we 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.
Capital Leases
In December 2001, we 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, we 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, we 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,
we 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. We have 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 years ended December 31, 2002 and
2003 amounted to $28,000 and $48,000, respectively, and accumulated DD&A on the
leased equipment at December 31, 2002 and 2003 amounted to $28,000 and $78,000,
respectively.
Senior Subordinated Notes and Related Securities
In December 1999, we consummated the sale of $22.0 million principal
amount of 9% Senior Subordinated Notes due 2007 (the
32
"Subordinated Notes") and $8.0 million of common stock and Warrants. We 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 our 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), L.P.), 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. We may, until
December 2004, elect, and historically have elected, to increase the amount of
the Subordinated Notes for 60% of the interest which would otherwise be payable
in cash. As a result, our cash obligation on the Subordinated Notes will
increase significantly after December 2004. As of December 31, 2002 and 2003,
the outstanding balance of the Subordinated Notes had been increased by $3.9
million and $5.3 million, respectively, for such interest paid in kind.
Concurrently with the sale of the Subordinated Notes, we sold to the same
purchasers 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 of our
common stock at an exercise price of $2.20 per share. For accounting purposes,
the warrants were valued at $0.25 each. In the first quarter of 2004, Mellon
Ventures exercised 69,199 of its 1999 warrants on a cashless basis and received
49,135 shares which it sold in the 2004 public offering.
We are 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 our capital expenditures to an amount equal to our
EBITDA for the immediately prior fiscal year (unless approved by our Board of
Directors and a J.P. Morgan Partners (23A SBIC), L.P. appointed director).
Series B Preferred Stock
In February 2002, we consummated the sale of 60,000 shares of Series B
Preferred Stock and 2002 Warrants to purchase 252,632 shares of common stock for
an aggregate purchase price of $6.0 million. We sold $4.0 million and $2.0
million of Series B Preferred Stock and 168,422 and 84,210 warrants to Mellon
Ventures, Inc. 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 adjustment for transactions including issuance of common
stock or securities convertible into or exercisable for common stock at less
than the conversion price, and is initially convertible into 1,052,632 shares of
common stock. The approximately $5.8 million net proceeds of this financing were
used to fund our ongoing exploration and development program and general
corporate purposes. In the first quarter of 2004, Mellon Ventures exercised all
168,411 of its 2002 warrants on a cashless basis and received 36,570 shares
which it sold in the 2004 public offering.
Dividends on the Series B Preferred Stock will be 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 2003 the outstanding balance of the Series B Preferred
Stock had been increased by $0.5 million (5,294 shares) and $1.2 million (11,987
shares), respectively, for dividends paid in kind. 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 such share of Series B
Preferred Stock is convertible on the record date for such 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 (which includes the common stock) (as defined in the
Statement of Resolutions for the Series B Preferred 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 our 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
33
- - 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 certain events constituting a "Change of
Control" (as defined in the Statement of Resolutions), we are required to make
an offer to each holder of Series B Preferred Stock to repurchase all of such
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.
The 2002 Warrants have a five-year term and 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 2002 Warrants are valued at $0.06 per 2002 Warrant.
Each of our series of warrants may be exercised on a cashless basis at
the option of the holder.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board (FASB) issued
SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143
requires that an asset retirement obligation (ARO) associated with the
retirement of a tangible long-lived asset be recognized as a liability in the
period in which a legal obligation is incurred and becomes determinable, with an
offsetting increase in the carrying amount of the associated asset. The cost of
the tangible asset, including the initially recognized ARO, is depleted such
that the cost of the ARO is recognized over the useful life of the asset. The
ARO is recorded at fair value, and accretion expense will be recognized over
time as the discounted liability is accreted to its expected settlement value.
The fair value of the ARO is measured using expected future cash outflows
discounted at our credit-adjusted risk-free interest rate.
We adopted SFAS No. 143 on January 1, 2003, which resulted in an
increase to net oil and gas properties of $0.4 million and additional
liabilities related to asset retirement obligations of $0.6 million. These
amounts reflect our ARO had the provisions of SFAS No. 143 been applied since
inception and resulted in a non-cash cumulative effect decrease to earnings of
$0.1 million ($0.2 million pretax). In accordance with the provisions of SFAS
No. 143, we record an abandonment liability associated with our oil and gas
wells when those assets are placed in service, rather than our past practice of
accruing the expected undiscounted abandonment costs on a unit-of-production
basis over the productive life of the associated full cost pool. Under SFAS No.
143, depletion expense is reduced since a discounted ARO is depleted in the
property balance rather than the undiscounted value previously depleted under
the old rules. The lower depletion expense under SFAS No. 143 is offset,
however, by accretion expense, which is recognized over time as the discounted
liability is accreted to our expected settlement value.
Inherent in the fair value calculation of ARO are numerous assumptions
and judgments including the ultimate settlement amounts, inflation factors,
credit adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the fair value of the existing ARO
liability, a corresponding adjustment is made to the oil and gas property
balance.
The following table is a reconciliation of the asset retirement
obligation liability since adoption (in thousands):
Asset retirement obligation upon adoption on January 1, 2003 $ 597
Liabilities incurred 91
Liabilities settled -
Accretion expense 42
Revisions in estimated liabilities 153
---------
Asset retirement obligation at December 31, 2003 $ 883
=========
The pro forma asset retirement obligation would have been approximately
$0.3 million at January 1, 2001 had we adopted the provisions of SFAS 143 on
January 1, 2001. The following table shows the pro forma effect of the
implementation on our Income Attributable to Common Stock and Net Income per
Common Share had SFAS No. 143 been adopted by us on January 1, 2001.
34
FOR THE YEAR ENDED
DECEMBER 31,
---------------------------
2002 2001
------- -------
(In thousands, except
per share data)
Net income available to common shareholders $ 4,202 $ 9,531
Effect on Net Income had SFAS No. 143 been applied (37) (24)
------- -------
Income Attributable to Common Stock $ 4,165 $ 9,507
======= =======
Basic Net Income per Common Share:
Net Income $ 0.30 $ 0.68
Effect on Net Income had SFAS No. 143 been applied - -
------- -------
Net Income $ 0.30 $ 0.68
======= =======
Diluted Net Income per Common Share:
Net Income $ 0.26 $ 0.57
Effect on Net Income had SFAS No. 143 been applied $ - $ -
------- -------
Net Income $ 0.26 $ 0.57
======= =======
The Financial Accounting Standards Board ("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.
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 (which owns an interest in Pinnacle), 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
December 31, 2003 in accordance with the full cost method of accounting.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." SFAS
No. 150 establishes standards on how companies classify and measure certain
financial instruments
35
with characteristics of both liabilities and equity. The statement requires that
we classify as liabilities the fair value of all mandatorily redeemable
financial instruments that had previously been recorded as equity or elsewhere
in our consolidated financial statements. This statement is effective for
financial instruments entered into or modified after May 31, 2003, and otherwise
effective for all existing financial instruments, except for minority interests
in limited-life entities, beginning in the third quarter of 2003. This statement
did not affect our financial statements.
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 our
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.
Oil and Natural Gas 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 $1.0 million, $1.0
million and $1.4 million in 2001, 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 and, where significant, dismantlement, restoration and
abandonment costs, net of estimated salvage values. The depletion rate per Mcfe
for 2001, 2002 and 2003 was $1.15, $1.41 and $1.55, 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 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.
In mid-March 2004, during the year-end close of our 2003 financial
statements, it was determined that there was a computational error in the
ceiling test calculation which overstated the tax basis used in the computation
to derive our after-tax present value (discounted at 10%) of future net revenues
from proved reserves. We further determined that this tax basis error was also
present in each of our previous ceiling test computations dating back to 1997.
This error only affected our after-tax computation, used in the ceiling test
calculation and the unaudited supplemental oil and gas disclosure, and did not
impact our: (1) pre-tax valuation of the present value (discounted at 10%) of
future net revenues from proved reserves, (2) our proved reserve volumes, (3)
our EBITDA or our future cash flows from operations, (4) our net deferred tax
liability, (5) our estimated tax basis in oil and gas properties, or (6) our
estimated tax net operating losses.
After discovering this computational error, the ceiling tests for all
quarters since 1997 were recomputed and it was determined that no write-down of
our oil and gas assets was necessary in any of the years from 1997 to 2003.
However, based upon the oil and natural gas prices in effect on December 31,
2001, March 31, 2003 and September 30, 2003, the unamortized cost of oil and
natural gas properties exceeded the cost center ceiling. As permitted by full
cost accounting rules, improvements in pricing and/or the addition of
36
proved reserves subsequent to those dates sufficiently increased the present
value of our oil and natural gas assets and removed the necessity to record a
write-down in these periods. Using the prices in effect and estimated proved
reserves on December 31, 2001, March 31, 2003 and September 30, 2003, the
after-tax write-down would have been approximately $6.3 million, $1.0 million,
and $6.3 million, respectively, had we not taken into account these subsequent
improvements. These improvements at September 30, 2003 included estimated proved
reserves attributable to our Shady Side #1 well. Because of the volatility of
oil and gas prices, no assurance can be given that we will not experience a
write-down in future periods.
In connection with our year-end 2003 ceiling test computation, a price
sensitivity study also indicated that a 20 percent increase in commodity prices
at December 31, 2003 would have increased the pre-tax present value of future
net revenues ("NPV") by approximately $28.1 million. Conversely, a 20 percent
decrease in commodity prices at December 31, 2003 would have reduced our NPV by
approximately $27.8 million. This would have caused our unamortized cost of
proved oil and gas properties to exceed the cost pool ceiling, resulting in an
after-tax write-down of approximately $7.7 million. The aforementioned price
sensitivity and NPV is as of December 31, 2003 and, accordingly, does not
include any potential changes in reserves due to first quarter 2004 performance,
such as commodity prices, reserve revisions and drilling results.
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 44.9 Bcfe of proved undeveloped reserves,
representing 64% of our total proved reserves at December 31, 2003. 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
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.
37
As of December 31, 2003 and December 31, 2002 we had leasehold costs
incurred of approximately $5.5 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.
Oil and Natural Gas Reserve Estimates
The reserve data included in this document are estimates prepared by
Ryder Scott Company and Fairchild & 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 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 based the 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 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. SFAS No. 133 was effective for us
beginning January 1, 2001 and was adopted by us 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.
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 oil and
natural gas revenues when the forecasted transaction occurs. All of our
derivative instruments at December 31, 2001, 2002 and 2003 were designated and
effective as cash flow hedges except for certain options described under
"Qualitative and Quantitative Disclosures About Market Risk -- Derivative
Instruments and Hedging Activities" and in Note 13.
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 our 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.
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
38
derivatives that are used in hedging transactions are highly effective in
offsetting changes in cash flows of hedged transactions.
Our Board of Directors sets all of our 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 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 yearend 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.
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.
VOLATILITY OF OIL AND NATURAL GAS PRICES
Our revenues, future rate of growth, results of operations, financial
condition and ability to borrow funds or obtain additional capital, as well as
the carrying value of our properties, are substantially dependent upon
prevailing prices of oil and natural gas. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Risk Factors --
Natural gas and oil prices are highly volatile, and lower prices will negatively
affect our financial results."
We periodically review the carrying value of our oil and natural gas
properties under the full cost accounting rules of the Commission. See " --
Critical Accounting Policies and Estimates -- Oil and Natural Gas Properties"
and " -- Risk Factors -- We may record ceiling limitation write-downs that would
reduce our shareholders' equity."
Total oil purchased and sold under swaps and collars during 2001, 2002
and 2003 were 18,000 Bbls, 131,300 Bbls and 193,600 Bbls, respectively. Total
natural gas purchased and sold under swaps and collars in 2001, 2002 and 2003
were 3,087,000 MMBtu, 2,314,000 MMBtu and 2,739,000 MMBtu respectively. The net
gains and (losses) realized by us under such hedging arrangements were $2.0
million, $(0.9 million) and $(1.8 million) for 2001, 2002 and 2003,
respectively, and are included in oil and natural gas revenues.
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.
As of December 31, 2003, $0.2 million, net of tax of $0.1 million,
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 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
39
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
2003, a $0.10 change in the price per Mcf of gas sold would have changed revenue
by $133,000. A $0.70 change in the price per barrel of oil would have changed
revenue by $62,000.
The table below summarizes our total natural gas production volumes
subject to derivative transactions during 2003 and the weighted average NYMEX
reference price for those volumes.
NATURAL GAS SWAPS NATURAL GAS CAPS
- ----------------------------- -----------------------------
Volumes (MMBtu) 549,000 Volumes (MMBtu) 2,190,000
Average price ($/MMBtu) $ 4.70 Average price ($/MMBtu)
Floor $ 3.40
Ceiling $ 5.25
The table below summarizes our total crude oil production volumes
subject to derivative transactions during 2003 and the weighted average NYMEX
reference price for those volumes.
CRUDE OIL SWAPS CRUDE OIL CAPS
- --------------------- -----------------------
Volumes (Bbls) 121,600 Volumes (Bbls) 72,000
Average price ($/Bbls) $ 27.77 Average price ($/Bbls) $ 23.50
Floor $ 26.50
Ceiling
At December 31, 2002 and 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
DECEMBER 31, 2002
- --------------------------------------------------------------------------------------
CONTRACT VOLUMES
-------------------
AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
- ------------------- ------ ------- ----------- ----------- -------------
First Quarter 2004 27,000 $ 30.36
First Quarter 2004 180,000 6.67
First Quarter 2004 546,000 $ 4.10 $ 7.00
Second Quarter 2004 18,300 30.38
Second Quarter 2004 546,000 4.00 5.60
Third Quarter 2004 552,000 4.00 5.60
Fourth Quarter 2004 369,000 4.00 5.80
In addition to the hedge positions above, during the second quarter of
2003, we 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. We
40
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. These options were classified as derivatives. As of December 31,
2003, these options have expired and a charge of $119,000 has been included in
other income and expense for the year ended December 31, 2003.
Since year-end 2003, we entered into costless collar arrangements
covering 1,641,000 MMBtu of natural gas for April 2004 through March 2005
production comprised as follows: 455,000 MMbtu in the second quarter 2004 with
average floor and ceiling prices of $5.00 and $6.17, respectively; 276,000 MMbtu
in the third quarter 2004 with average floor and ceiling prices of $4.57 and
$7.00, respectively; 465,000 MMbtu in the fourth quarter 2004 with average floor
and ceiling prices of. $4.73 and $7.00, respectively; and 450,000 MMbtu in the
first quarter 2005 with average floor and ceiling prices of $4.64 and $8.00,
respectively. We also entered into swap arrangements covering 18,300 Bbls of
crude oil for June 2004 and July 2004 production at an average fixed price of
$33.63.
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.
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 Form 10-K.
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;
41
- 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.
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 Form 10-K 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 in or filed as an exhibit
to this Form 10-K 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, 2003, approximately 64% 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, 2003 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 in this Form 10-K are not
necessarily the same as the current market value of our estimated natural gas
and oil reserves. As required by the Commission, 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:
42
- 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.
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.
43
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 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 coalbed methane drilling permits, the issuance of which has
been challenged in pending litigation. 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;
44
- fires;
- geologic formations with abnormal pressures;
- pipeline ruptures or spills;
- releases of toxic gases; and
- other environmental hazards and risks.
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
45
material adverse effect on our financial condition and future results of
operations.
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, Kendall 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
BENEFITING 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 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
46
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.
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
47
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.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY RISK. Our major market risk exposure is the commodity pricing
applicable to our oil and natural gas 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. The effects of such
pricing volatility have been discussed above, and such volatility is expected to
continue. A 10% fluctuation in the price received for oil and gas production
would have an approximate $3.9 million impact on our annual revenues and
operating income.
To mitigate some of this risk, we engage periodically in certain
limited hedging activities but only to the extent of buying protection price
floors. Costs and any benefits derived from these price floors are accordingly
recorded as a reduction or increase, as applicable, in oil and gas sales revenue
and were not significant for any year presented. The costs to purchase put
options are amortized over the option period. We do not hold or issue derivative
instruments for trading purposes. Income and (losses) realized by us related to
these instruments were $2.0 million, $(0.9 million) and $(1.8 million) or $0.63,
$(0.12) and $(0.46) per MMBtu for the years ended December 31, 2001, 2002, and
2003, respectively.
INTEREST RATE RISK. Our exposure to changes in interest rates results
from our floating rate debt. In regards to our Hibernia Facility, the result of
a 10% fluctuation in short-term interest rates would have impacted 2003 cash
flow by approximately $25,000.
FINANCIAL INSTRUMENTS & DEBT MATURITIES. Our financial instruments
consist of cash and cash equivalents, accounts receivable, accounts payable,
bank borrowing, 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 December 31, 2003 and 2002, and were
determined based upon interest rates currently available to us for borrowings
with similar terms. Maturities of the debt are $1.0 million in 2004, $7.1
million in 2005 and the balance in 2007.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The response to this item is included elsewhere in this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out
an evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that except as provided below our
disclosure controls and procedures were effective as of December 31, 2003 to
provide reasonable assurance that information required to be disclosed in our
reports filed or submitted under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the Securities and
Exchange Commission's rules and forms.
In performing its audit of our Consolidated Financial Statements for
the year ended December 31, 2003, our independent auditors, Ernst & Young LLP
(Ernst & Young), noted certain matters involving our internal controls that it
considered to be a reportable condition under the standards established by the
American Institute of Certified Public Accountants. A reportable condition
involves matters relating to significant deficiencies in the design or operation
of internal controls that, in Ernst & Young's judgment, could
48
adversely affect our ability to record, process, summarize and report financial
data consistent with the assertions of management on the financial statements.
The reportable conditions noted related to (1) the presence of underlying errors
in the tax basis utilized in our full cost ceiling test computations and certain
disclosures and the lack of underlying detailed tax basis documentation which
adversely impacted our ability to evaluate the appropriateness of the tax basis
(see "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Critical Accounting Policies and Estimates -- Oil and Natural Gas
Properties") and (2) the sufficiency of review applied to the financial
statement close process and account reconciliation. The reportable conditions
noted were not considered by Ernst & Young to be a material weakness under the
applicable auditing standards and had no material affect on our financial
statements. Management has discussed the reportable conditions with the Audit
Committee and is implementing procedures and controls to address the identified
deficiencies and enhance the reliability of our internal control procedures.
There has been no change in our internal controls over financial
reporting that occurred during the three months ended December 31, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated by reference to
information under the caption "Proposal 1-Election of Directors" and to the
information under the caption "Section 16(a) Reporting Delinquencies" in our
definitive Proxy Statement (the "2004 Proxy Statement") for our 2004 annual
meeting of shareholders. The 2004 Proxy Statement will be filed with the
Securities and Exchange Commission (the "Commission") not later than 120 days
subsequent to December 31, 2003.
Pursuant to Item 401(b) of Regulation S-K, the information required by
this item with respect to our executive officers is set forth in Part I of this
report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by
reference to the 2004 Proxy Statement, which will be filed with the Commission
not later than 120 days subsequent to December 31, 2003.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED SHAREHOLDER MATTERS
Information required by this item is incorporated herein by reference
to the 2004 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2003.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is incorporated herein by
reference to the 2004 Proxy Statement, which will be filed with the Commission
not later than 120 days subsequent to December 31, 2003.
ITEM 14A. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The information required by this item is incorporated by reference to
the 2004 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 2003.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) FINANCIAL STATEMENTS
The response to this item is submitted in a separate section of this
report.
(a)(2) FINANCIAL STATEMENT SCHEDULES
All schedules and other statements for which provision is made in the
applicable regulations of the Commission have been omitted because they are not
required under the relevant instructions or are inapplicable.
49
(a)(3) EXHIBITS
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------------ --------------------------------------------------------------
1.1 -- Underwriting Agreement, dated February 5, 2004, by and
among Carrizo Oil & Gas, Inc., and CIBC World Markets
Corp., First Albany Capital, Inc., Hibernia
Southcoast Capital, Inc., and Johnson Rice & Company,
L.L.C., as representatives of the several
underwriters named in Schedule I to the Underwriting
Agreement, and the selling shareholders listed on
Schedule II to the Underwriting Agreement.
+2.1 -- Combination Agreement by and among 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, 1998
(Incorporated herein by reference to Exhibit 2.1 to
the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+3.1 -- Amended and Restated Articles of Incorporation of the
Company (Incorporated herein by reference to Exhibit
3.1 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1998).
+3.2 -- Amended and Restated Bylaws of the Company, as amended by
Amendment No. 1 (Incorporated herein by reference to
Exhibit 3.2 to the Company's Registration Statement
on Form 8-A (Registration No. 000-22915), Amendment
No. 2 (Incorporated herein by reference to Exhibit
3.2 to the Company's Current Report on Form 8-K dated
December 15, 1999) and Amendment No. 3 (Incorporated
herein by reference to Exhibit 3.1 to the Company's
Current Report on Form 8-K dated February 20, 2002).
+3.3 -- Statement of Resolution dated February 20, 2002
establishing the Series B Convertible Participating
Preferred Stock providing for the designations,
preferences, limitations and relative rights, voting,
redemption and other rights thereof (Incorporated
herein by reference to Exhibit 99.2 to the Company's
Current Report on Form 8-K dated February 20, 2002).
+4.1 -- Revolving Note by and between Carrizo Oil & Gas, Inc. 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).
+4.2 -- 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).
+4.3 -- Stock Pledge and Security Agreement by and between Carrizo
Oil & Gas, Inc. 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).
+4.4 -- Amended and Restated Credit Agreement dated as of December
12, 2002 by and between Carrizo Oil & Gas, Inc.,
CCBM, Inc. and Hibernia National Bank (Incorporated
herein by reference to Exhibit 4.6 to the Company's
Annual Report on Form 10-K for the year ended
December 31, 2002).
+4.5 -- Letter Agreement Regarding Participation in the Company's
2001 Seismic and Acreage Program, dated May 1, 2001
(Incorporated herein by reference to Exhibit 4.1 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2001).
+4.6 -- Amendment No. 1 to the Letter Agreement Regarding
Participation in the Company's 2001 Seismic and
Acreage Program, dated June 1, 2001 (Incorporated
herein by reference to Exhibit 4.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended
June 30, 2001).
+4.7 -- Promissory Note payable to Rocky Mountain Gas, Inc. by
CCBM, Inc. (Incorporated herein by reference to
Exhibit 4.3 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2001).
+10.1 -- Amended and Restated Incentive Plan of the Company
effective as of February 17, 2000 (Incorporated
herein 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 herein by reference to
Exhibit 10.1 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2002).
+10.3 -- Amendment No. 2 to the Amended and Restated Incentive Plan
of the Company (Incorporated herein by reference to
Exhibit 10.3 to the Company's Annual Report on Form
10-K for the year ended December 31, 2002).
+10.4 -- Amendment No. 3 to the Amended and Restated Incentive Plan
of the Company (Incorporated herein by reference to
Appendix A to the Company's Proxy Statement dated
April 21, 2003).
+10.5 -- Employment Agreement between the Company and S.P. Johnson
IV (Incorporated herein by reference to Exhibit 10.2
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 herein by reference to Exhibit
10.4 to the Company's Registration Statement on Form
S-1 (Registration No. 333-29187)).
50
+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 (Incorporated herein by reference to Exhibit
10.8 to the Company's Registration Statement on Form
S-2 (Registration No. 333-111475)).
+10.9 -- Employment Agreement between the Company and Paul F. Boling
(Incorporated herein by reference to Exhibit 10.9 to
the Company's Registration Statement on Form S-2
(Registration No. 333-111475)).
+10.10 -- Indemnification Agreement between the Company and each of
its directors and executive officers (Incorporated
herein by reference to Exhibit 10.6 to the Company's
Annual Report on Form 10-K for the year ended
December 31, 1998).
+10.11 -- S Corporation Tax Allocation, Payment and Indemnification
Agreement among the Company and Messrs. Loyd,
Webster, Johnson, Hamilton and Wojtek (Incorporated
herein by reference to Exhibit 10.8 to the Company's
Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.12 -- S Corporation Tax Allocation, Payment and Indemnification
Agreement among Carrizo Production, Inc. and Messrs.
Loyd, Webster, Johnson, Hamilton and Wojtek
(Incorporated herein by reference to Exhibit 10.9 to
the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+10.13 -- Form of Amendment to Executive Officer Employment
Agreement. (Incorporated herein by reference to
Exhibit 99.3 to the Company's Current Report on Form
8-K dated January 8, 1998).
+10.14 -- Amended Enron Warrant Certificates (Incorporated herein by
reference to Exhibit 4.1 to the Company's Current
Report on Form 8-K dated December 15, 1999).
+10.15 -- Securities Purchase Agreement dated December 15, 1999 among
the Company, CB Capital Investors, L.P., Mellon
Ventures, L.P., Paul B. Loyd Jr., Douglas A. P.
Hamilton and Steven A. Webster (Incorporated herein
by reference to Exhibit 99.1 to the Company's Current
Report on Form 8-K dated December 15, 1999).
+10.16 -- Shareholders Agreement dated December 15, 1999 among the
Company, CB Capital Investors, L.P., Mellon Ventures,
L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton,
Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek
and DAPHAM Partnership, L.P. (Incorporated herein by
reference to Exhibit 99.2 to the Company's Current
Report on Form 8-K dated December 15, 1999).
+10.17 -- Warrant Agreement dated December 15, 1999 among the
Company, CB Capital Investors, L.P., Mellon Ventures,
L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton and
Steven A. Webster (Incorporated herein by reference
to Exhibit 99.3 to the Company's Current Report on
Form 8-K dated December 15, 1999).
+10.18 -- Registration Rights Agreement dated December 15, 1999 among
the Company, CB Capital Investors, L.P. and Mellon
Ventures, L.P. (Incorporated herein by reference to
Exhibit 99.4 to the Company's Current Report on Form
8- K dated December 15, 1999).
+10.19 -- Amended and Restated Registration Rights Agreement
dated December 15, 1999 among the Company, Paul B.
Loyd Jr., Douglas A. P. Hamilton, Steven A. Webster,
S.P. Johnson IV, Frank A. Wojtek and DAPHAM
Partnership, L.P. (Incorporated herein by reference
to Exhibit 99.5 to the Company's Current Report on
Form 8-K dated December 15, 1999).
+10.20 -- Compliance Sideletter dated December 15, 1999 among the
Company, CB Capital Investors, L.P. and Mellon
Ventures, L.P. (Incorporated herein by reference to
Exhibit 99.6 to the Company's Current Report on Form
8-K dated December 15, 1999).
+10.21 -- Form of Amendment to Executive Officer Employment Agreement
(Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated
December 15, 1999).
+10.22 -- Form of Amendment to Director Indemnification Agreement
(Incorporated herein by reference to Exhibit 99.8 to
the Company's Current Report on Form 8-K dated
December 15, 1999).
+10.23 -- Purchase and Sale Agreement by and between Rocky Mountain
Gas, Inc. and CCBM, Inc., dated June 29, 2001
(Incorporated herein by reference to Exhibit 10.1 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2001).
+10.24 -- Securities Purchase Agreement dated February 20, 2002 among
the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit
99.1 to the Company's Current Report on Form 8-K
dated February 20, 2002).
+10.25 -- Shareholders' Agreement dated February 20, 2002 among the
Company, Mellon Ventures, L.P., Paul B. Loyd, Jr.,
Douglas A.P. Hamilton, Steven A. Webster, S.P.
Johnson IV, Frank A. Wojtek and DAPHAM Partnership,
L.P. (Incorporated herein by reference to Exhibit
99.3 to the Company's Current Report on Form 8-K
dated February 20, 2002).
+10.26 -- Warrant Agreement dated February 20, 2002 among the
Company, Mellon Ventures, L.P. and Steven A. Webster
(including Warrant Certificate) (Incorporated herein
by reference to Exhibit 99.4 to the Company's Current
Report on Form 8-K dated February 20, 2002).
+10.27 -- Registration Rights Agreement dated February 20, 2002 among
the Company, Mellon Ventures, L.P. and Steven A.
Webster (Incorporated herein by reference to Exhibit
99.5 to the Company's Current Report on Form 8-K
dated February 20, 2002).
51
+10.28 -- Compliance Sideletter dated February 20, 2002 between the
Company and Mellon Ventures, L.P. (Incorporated
herein by reference to Exhibit 99.6 to the Company's
Current Report on Form 8-K dated February 20, 2002).
+10.29 -- Form of Amendment to Executive Officer Employment Agreement
(Incorporated herein by reference to Exhibit 99.7 to
the Company's Current Report on Form 8-K dated
February 20, 2002).
+10.30 -- Form of Amendment to Director Indemnification Agreement
(Incorporated herein by reference to Exhibit 99.8 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 herein 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 herein by reference to Exhibit 10.2 to
the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2003).
21.1 -- Subsidiaries of the Company.
23.1 -- Consent of Ernst & Young LLP.
23.2 -- Consent of Ryder Scott Company Petroleum Engineers.
23.3 -- Consent of Fairchild & Wells, Inc.
23.4 -- Notice Regarding Consent of Arthur Andersen LLP.
31.1 -- CEO Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 -- CFO Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 -- CEO Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 -- CFO Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers as of December 31, 2003.
99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of
December 31, 2003.
- ----------
+ Incorporated by reference as indicated.
52
CARRIZO OIL & GAS, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Carrizo Oil & Gas, Inc. --
Reports of Independent Auditors and Independent Public Accountants F-2
Consolidated Balance Sheets, December 31, 2002 and 2003 F-4
Consolidated Statements of Operations for the Years Ended December
31, 2001, 2002 and 2003 F-5
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 2001, 2002 and 2003 F-6
Consolidated Statements of Cash Flows for the Years Ended December
31, 2001, 2002 and 2003 F-8
Notes to Consolidated Financial Statements F-9
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, 2003 and 2002, and the related consolidated
statements of operations, shareholders' equity and cash flows for each of the
two years in the period ended December 31, 2003. 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 year 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 2.
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 financial statements referred to above present
fairly, in all material respects, the consolidated financial position of the
Company at December 31, 2003 and 2002, and the consolidated results of its
operations and its cash flows for the two years then ended, in conformity with
accounting principles generally accepted in the United States.
As described in Note 2, the Company revised the reported amount of the
after-tax write-down that would have been taken as of December 31, 2001 using
prices in effect at that date. We audited the adjustments describe in Note 2
that were applied to revise the reported amount of the full cost ceiling test
write-down had the Company not utilized the improvements in pricing subsequent
to December 31, 2001 and/or the addition of proved oil and natural gas reserves
on existing properties subsequent to the end of the period but prior to issuance
of financial statements. Our procedures included (a) agreeing the revised tax
basis in the full cost ceiling test computation to the Company's underlying
records obtained from management, and (b) testing the mathematical accuracy of
the revisions to the full cost ceiling computation. 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.
As discussed in Note 2 to the consolidated financial statements,
effective January 1, 2003, the Company changed its method of accounting for
asset retirement obligations.
ERNST & YOUNG LLP
Houston, Texas
March 25, 2004
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 2 TO CARRIZO'S CONSOLIDATED FINANCIAL STATEMENTS AS OF
DECEMBER 31, 2003, 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 THE AMOUNT OF THE AFTER-TAX WRITE-DOWN THAT WOULD
HAVE TAKEN AS OF DECEMBER 31, 2001 USING PRICES IN EFFECT AT THAT DATE. 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,
------------------------
2002 2003
---------- ----------
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 4,743 $ 3,322
Accounts receivable, trade (net of allowance for doubtful accounts of $0.5
million and none at December 31, 2002 and 2003, respectively) 8,207 8,970
Advances to operators 501 1,877
Deposits 46 56
Other current assets 605 100
---------- ----------
Total current assets 14,102 14,325
PROPERTY AND EQUIPMENT, net (full-cost method of
accounting for oil and natural gas properties) 120,526 135,273
Investment in Pinnacle Gas Resources, Inc. - 6,637
Deferred financing costs 760 479
Other assets - 89
---------- ----------
$ 135,388 $ 156,803
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 9,957 $ 19,515
Accrued liabilities 1,014 1,057
Advances for joint operations 1,550 3,430
Current maturities of long-term debt 1,609 1,037
Current maturities of seismic obligation payable 1,414 1,103
---------- ----------
Total current liabilities 15,544 26,142
LONG-TERM DEBT 37,886 34,113
SEISMIC OBLIGATION PAYABLE 1,103 -
ASSET RETIREMENT OBLIGATION - 883
DEFERRED INCOME TAXES 7,666 12,479
COMMITMENTS AND CONTINGENCIES (Note 10)
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 71,987 convertible
participating shares issued and outstanding at December 31, 2002 and 2003,
respectively) (Note 9) 6,373 7,114
SHAREHOLDERS' EQUITY:
Warrants (3,262,821 outstanding at December 31, 2002 and 2003, respectively) 780 780
Common stock, par value $.01 (40,000,000 shares authorized with 14,177,383 and
14,591,348 issued and outstanding at December 31, 2002 and 2003, respectively) 142 146
Additional paid in capital 63,224 65,103
Retained deficit 3,058 10,229
Accumulated other comprehensive income (388) (186)
---------- ----------
66,816 76,072
---------- ----------
$ 135,388 $ 156,803
========== ==========
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,
------------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands except for per share amounts)
OIL AND NATURAL GAS REVENUES $ 26,226 $ 26,802 $ 38,508
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of
depreciation shown separately below) 4,138 4,908 6,724
Depreciation, depletion and amortization 6,492 10,574 11,868
General and administrative 3,333 4,133 5,639
Accretion expenses related to asset retirement obligation - - 41
Stock option compensation (558) (84) 313
---------- ---------- ----------
Total costs and expenses 13,405 19,531 24,585
---------- ---------- ----------
OPERATING INCOME 12,821 7,271 13,923
OTHER INCOME AND EXPENSES:
Equity in loss of Pinnacle Gas Resources, Inc. - - (830)
Other income and expenses 1,777 274 29
Interest income 275 55 58
Interest expense (1,040) (846) (617)
Interest expense, related parties (2,137) (2,255) (2,379)
Capitalized interest 3,171 3,100 2,919
---------- ---------- ----------
INCOME BEFORE INCOME TAXES 14,867 7,599 13,103
INCOME TAXES 5,336 2,809 5,063
---------- ---------- ----------
NET INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 9,531 4,790 8,040
DIVIDENDS AND ACCRETION ON PREFERRED STOCK - 588 741
---------- ---------- ----------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS
BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE 9,531 4,202 7,299
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
NET OF INCOME TAXES - - 128
---------- ---------- ----------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 9,531 $ 4,202 $ 7,171
========== ========== ==========
BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.68 $ 0.30 $ 0.51
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE NET OF INCOME TAXES - - (0.01)
---------- ---------- ----------
BASIC EARNINGS PER COMMON SHARE $ 0.68 $ 0.30 $ 0.50
========== ========== ==========
DILUTED EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.57 $ 0.26 $ 0.44
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE NET OF INCOME TAXES - - (0.01)
---------- ---------- ----------
DILUTED EARNINGS PER COMMON SHARE $ 0.57 $ 0.26 $ 0.43
========== ========== ==========
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
---------------------- -----------------------
NUMBER AMOUNT SHARES AMOUNT
--------- ---------- ---------- ----------
BALANCE, January 1, 2001 3,010,189 $ 765 14,055,061 $ 141
Comprehensive income
Net income - - - -
Cummulative effect of change
in accounting principle - - - -
Reclassification adjustments for
cummulative effect of change in
accounting principle - - - -
Reclassification adjustments for
settled contracts - - - -
Net change in fair value of
hedging instruments - - - -
--------- ---------- ---------- ----------
Comprehensive income
Common stock issued - - 9,016 -
--------- ---------- ---------- ----------
BALANCE, December 31, 2001 3,010,189 765 14,064,077 141
--------- ---------- ---------- ----------
Net income - - - -
Net change in fair value of
hedging instruments - - - -
--------- ---------- ---------- ----------
Comprehensive income
Warrants issued 252,632 15 - -
Common stock issued - - 113,306 1
Dividends and accretion of
discount on preferred stock - - - -
--------- ---------- ---------- ----------
BALANCE, December 31, 2002 3,262,821 780 14,177,383 142
--------- ---------- ---------- ----------
Net income - - - -
Net change in fair value of
hedging instruments - - - -
--------- ---------- ---------- ----------
Common stock issued - - 413,965 4
Dividends and accretion of
discount on preferred stock - - - -
--------- ---------- ---------- ----------
BALANCE, December 31, 2003 3,262,821 $ 780 14,591,348 $ 146
========= ========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
ACCUMULATED
ADDITIONAL RETAINED OTHER
PAID IN COMPREHENSIVE EARNINGS COMPREHENSIVE SHAREHOLDERS'
CAPITAL INCOME (DEFICIT) INCOME (LOSS) EQUITY
------------ ------------ ------------ ------------ ------------
(Dollars in thousands)
BALANCE $ 62,708 - $ (10,675) - $ 52,939
Comprehensive income
Net income - $ 9,531 9,531 - 9,531
Cummulative effect of change
in accounting principle - (1,967) - $ (1,967) (1,967)
Reclassification adjustments for
cummulative effect of change in
accounting principle - 1,967 - 1,967 1,967
Reclassification adjustments for
settled contracts - (2,020) - (2,020) (2,020)
Net change in fair value of
hedging instruments - 2,726 - 2,726 2,726
------------ ------------ ------------ ------------ ------------
Comprehensive income $ 10,237
============
Common stock issued 28 - - 28
------------ ------------ ------------ ------------
BALANCE, December 31, 2001 62,736 (1,144) 706 63,204
------------ ------------ ------------ ------------
Net income - 4,790 4,790 - 4,790
Net change in fair value of
hedging instruments - (1,094) - (1,094) (1,094)
------------ ------------ ------------ ------------ ------------
Comprehensive income $ 3,696
============
Warrants issued - - 15
Common stock issued 488 - - 489
Dividends and accretion of
discount on preferred stock - (588) - (588)
------------ ------------ ------------ ------------
BALANCE, December 31, 2002 63,224 3,058 $ (388) 66,816
------------ ------------ ------------ ------------
Net income - $ 7,912 7,912 - 7,912
Net change in fair value of
hedging instruments - 202 - 202 202
------------ ------------ ------------ ------------ ------------
$ 8,114
============
Common stock issued 1,879 - - 1,883
Dividends and accretion of
discount on preferred stock - (741) - (741)
------------ ------------ ------------ ------------
BALANCE, December 31, 2003 $ 65,103 $ 10,229 $ (186) $ 76,072
============ ============ ============ ============
F-7
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------
2001 2002 2003
---------- ---------- ----------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income before cumulative effect of change
in accounting principle $ 9,531 $ 4,790 $ 8,040
Adjustment to reconcile net income to net
cash provided by operating activities -
Depreciation, depletion and amortization 6,492 10,574 11,868
Discount accretion 85 86 161
Ineffective derivative instruments 706 (706) 119
Interest payable in kind 1,282 1,353 1,428
Stock option compensation (benefit) (558) (84) 313
Gain on sale of Michael Petroleum Corporation (3,900) - -
Equity in loss of Pinnacle Gas Resources, Inc. - - 830
Deferred income taxes 5,204 2,645 4,883
Changes in assets and liabilities -
Accounts receivable (719) 530 (762)
Other assets 143 (59) 335
Accounts payable 6,555 643 7,803
Accrued liabilities (870) 153 41
---------- ---------- ----------
Net cash provided by operating
activities 23,951 19,925 35,059
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (38,264) (24,696) (33,358)
Proceeds from sale of Michael Petroleum Corporation 5,445 - -
Proceeds from the sale of oil and natural gas properties - 355 -
Change in capital expenditure accrual 355 (949) 1,755
Advances to operators 1,248 8 (1,377)
Advances for joint operations (8) 1,182 1,879
---------- ---------- ----------
Net cash used in investing activities (31,224) (24,100) (31,101)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from sale of common stock 27 14 691
Net proceeds from sale of preferred stock - 5,800 -
Net proceeds from debt issuance 7,744 8,613 -
Debt repayments (5,479) (8,745) (5,951)
Loss on ineffective derivatives - - (119)
---------- ---------- ----------
Net cash provided by (used in) financing activities 2,292 5,682 (5,379)
---------- ---------- ----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (4,981) 1,507 (1,421)
CASH AND CASH EQUIVALENTS, beginning of year 8,217 3,236 4,743
---------- ---------- ----------
CASH AND CASH EQUIVALENTS, end of year $ 3,236 $ 4,743 $ 3,322
========== ========== ==========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ - $ 1 $ 77
========== ========== ==========
Cash paid for income taxes $ - $ - $ -
========== ========== ==========
Common stock issued for oil and gas properties $ - $ 475 $ 1,193
========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-8
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. During 2003, the Company
obtained offshore licensees to explore in the U.K. North Sea and acquired
interests in the Barnett Shale trend located in Tarrant and Parker counties in
North Texas.
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. If 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
$1.0 million, $1.0 million and $1.4 million in 2001, 2002 and 2003,
respectively. Maintenance and repairs are expensed as incurred.
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, dismantlement, restoration and
abandonment costs, net of estimated salvage values. The depletion rate per Mcfe
for 2001, 2002 and 2003 was $1.15, $1.41 and $1.55, 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.
F-9
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. During the year-end close of 2003, a computational
error was identified in the ceiling test calculation which overstated the tax
basis used in the computation to derive the after-tax present value (discounted
at 10%) of future net revenues from proved reserves. This tax basis error was
also present in each of the previous ceiling test computations dating back to
1997. This error only affected the after-tax computation, used in the ceiling
test calculation and the unaudited supplemental oil and natural gas disclosure
and did not impact: (1) the pre-tax valuation of the present value (discounted
at 10%) of future net revenues from proved reserves, (2) the proved reserve
volumes, (3) our EBITDA or our future cash flows from operations, (4) the net
deferred tax liability, (5) the estimated tax basis in oil and natural gas
properties, or (6) the estimated tax net operating losses.
After discovering this computational error, the ceiling tests for all
quarters since 1997 were recomputed and it was determined that no write-down of
oil and natural gas assets was necessary in any of the years from 1997 to 2003.
However, based upon the oil and natural gas prices in effect on December 31,
2001, March 31, 2003 and September 30, 2003, the unamortized cost of oil and
natural gas properties exceeded the cost center ceiling. As permitted by full
cost accounting rules, improvements in pricing and/or the addition of proved
reserves subsequent to those dates sufficiently increased the present value of
the oil and natural gas assets and removed the necessity to record a write-down
in these periods. Using the prices in effect and estimated proved reserves on
December 31, 2001, March 31, 2003 and September 30, 2003, the after-tax
write-down would have been approximately $6.3 million, $1.0 million, and $6.3
million, respectively, had we not taken into account these subsequent
improvements. These improvements at September 30, 2003 included estimated proved
reserves attributable to our Shade Side #1 well. Because of the volatility of
oil and natural gas prices, no assurance can be given that we 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.
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.
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 oil and natural gas 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 oil and natural gas 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 December 31, 2003, and 2002, we had leasehold costs incurred of
approximately $5.5 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 oil and natural gas mineral rights
held under lease and other contractual rights representing the right to extract
such reserves as tangible oil and natural gas properties until further guidance
is provided.
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 & Wells, Inc., Independent Petroleum
Engineers. Reserve engineering is a
F-10
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.
The Company's full cost ceiling test also depends on the Company's
estimate of proved reserves. If these reserve estimates decline, the Company may
be subjected to a full cost ceiling write-down.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include highly liquid investments with
maturities of three months or less when purchased.
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY
The Company's investment in Pinnacle is recorded using the equity
method of accounting. Under this method, the investment is recorded at cost
initially, and the investment is adjusted for the Company's equity in the
subsidiary's profit or loss. The investment is further adjusted for additional
contributions to and distributions from the subsidiary.
The Company would also record any loss in fair value of the investment other
than a temporary decline.
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 $0.5 million are
included in other assets as of December 31, 2002 and 2003, respectively, and are
being amortized using the effective yield method over the term of the loans
(through January 31, 2005 for the 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 acquisition of
seismic data, the $0.5 million acquisition of 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. The
Statement of Cash Flows for the year ended December 31, 2003 does not include
the acquisition of $1.2 million of seismic data through the issuance of common
stock and the $0.2 million non-cash cumulative effect recorded in connection
with the implementation of SFAS No. 143, "Accounting for Asset Retirement
Obligations" (See New Accounting Pronouncements).
F-11
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 variable interest rates. The fair value of
the Subordinated Notes payable and the RMG note at December 31, 2003 was $27.3
million and $0.9 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, 2003 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.
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:
F-12
For the Year Ended December 31,
-----------------------------------
2001 2002 2003
--------- --------- ---------
(In thousands except per share amounts)
Net income available to common shareholders
before cumulative effect of change in accounting
principle as reported $ 9,531 $ 4,202 $ 7,299
Less: Total stock-based employee
compensation expense determined under
fair value method for all awards, net of
related tax effects (1,369) (872) (662)
--------- --------- ---------
Pro forma net income available to common
shareholders before cumulative effect of change
in accounting principle $ 8,162 $ 3,330 $ 6,637
========= ========= =========
Net income available to common shareholders
before cumulative effect of change in accounting
principle per common hsare, as reported:
Basic $ 0.68 $ 0.30 $ 0.51
Diluted 0.57 0.26 0.44
Pro Forma net income available to common
shareholders before cumulative effect of change
in accounting principle per common share, as if
value method had been applied to all awards:
Basic $ 0.58 $ 0.24 $ 0.46
Diluted 0.49 0.21 0.40
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. 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 December 31, 2001, 2002 and 2003 were
designated and cash flow hedges.
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. See Note 15 with
respect to the Company's positions with an affiliate of Enron Corp.
F-13
The Company typically uses fixed rate swaps and costless collars to
hedge its exposure to material changes in the price of oil and natural gas. 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 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 deferred tax assets to the amounts 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.
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, 2002 to
Cokinos Natural Gas Company (12%); for the year ended December 31, 2003 to WMJ
Investments Corp. (16%), Cokinos Natural Gas Company (15%) and Gulfmark Energy,
Inc. (14%). 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:
F-14
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------
(In thousands except share and per share amounts)
INCOME SHARES PER-SHARE AMOUNT
------------------------ -------------------------------- --------------------
2001 2002 2003 2001 2002 2003 2001 2002 2003
------- ------- ------- ---------- ---------- ---------- ------ ------ ------
Basic Earnings per Common Share
Net income available to common shareholders
before cumulative effect of change in accounting
principle $ 9,531 $ 4,202 $ 7,299 14,059,151 14,158,438 14,311,820 $ 0.68 $ 0.30 $ 0.51
====== ====== ======
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - - 2,671,850 1,990,005 2,432,476
------- ------- ------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common shareholders
plus assumed conversions before cumulative
effect of change in accounting principle $ 9,531 $ 4,202 $ 7,299 16,731,001 16,148,443 16,744,296 $ 0.57 $ 0.26 $ 0.44
======= ======= ======= ========== ========== ========== ====== ====== ======
Cumulative effect of change
in accounting principle net of income taxes $ - $ - $ (128)
Basic Earnings per Common Share
Net loss available to common shareholders - - - 14,059,151 14,158,438 14,311,820 $ 0.00 $ 0.00 $(0.01)
====== ====== ======
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - - 2,671,850 1,990,005 2,432,476
------- ------- ------- ---------- ---------- ----------
Diluted Earnings per Share
Cumulative effect of change in accounting principle
net of income taxes plus assumed conversions $ - $ - $ (128) 16,731,001 16,148,443 16,744,296 $ 0.00 $ 0.00 $(0.01)
======= ======= ======= ========== ========== ========== ====== ====== ======
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------------
(In thousands except share and per share amounts)
INCOME SHARES PER-SHARE AMOUNT
---------------------- -------------------------------- --------------------
2001 2002 2003 2001 2002 2003 2001 2002 2003
------ ------- ------- ---------- ---------- ---------- ------ ------ ------
Basic Earnings per Common Share
Net income available to common shareholders $9,531 $ 4,202 $ 7,171 14,059,151 14,158,438 14,311,820 $ 0.68 $ 0.30 $ 0.50
====== ====== ======
Dilutive effect of Stock Options, Warrants and
Preferred Stock conversions - - - 2,671,850 1,990,005 2,432,476
------ ------- ------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common shareholders
plus assumed conversions $9,531 $ 4,202 $ 7,171 16,731,001 16,148,443 16,744,296 $ 0.57 $ 0.26 $ 0.43
====== ======= ======= ========== ========== ========== ====== ====== ======
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 period. The Company had
outstanding 79,500, 172,333 and 117,000 stock options at December 31, 2001, 2002
and 2003, 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 and
1,262,930 convertible preferred shares at December 31, 2002 and 2003,
respectively, that were antidilutive and were not included in the calculation.
F-15
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.
NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board (FASB) issued
SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143
requires that an asset retirement obligation (ARO) associated with the
retirement of a tangible long-lived asset be recognized as a liability in the
period in which a legal obligation is incurred and becomes determinable, with an
offsetting increase in the carrying amount of the associated asset. The cost of
the tangible asset, including the initially recognized ARO, is depleted such
that the cost of the ARO is recognized over the useful life of the asset. The
ARO is recorded at fair value, and accretion expense will be recognized over
time as the discounted liability is accreted to its expected settlement value.
The fair value of the ARO is measured using expected future cash outflows
discounted at the company's credit-adjusted risk-free interest rate.
The Company adopted SFAS No. 143 on January 1, 2003, which resulted in an
increase to net oil and natural gas properties of $0.4 million and additional
liabilities related to asset retirement obligations of $0.6 million. These
amounts reflect the ARO of the company had the provisions of SFAS No. 143 been
applied since inception and resulted in a non-cash cumulative effect decrease to
earnings of $0.1 million ($0.2 million pretax). In accordance with the
provisions of SFAS No. 143, the Company records an abandonment liability
associated with its oil and natural gas wells when those assets are placed in
service, rather than its past practice of accruing the expected undiscounted
abandonment costs on a unit-of-production basis over the productive life of the
associated full cost pool. Under SFAS No. 143, depletion expense is reduced
since a discounted ARO is depleted in the property balance rather than the
undiscounted value previously depleted under the old rules. The lower depletion
expense under SFAS No. 143 is offset, however, by accretion expense, which is
recognized over time as the discounted liability is accreted to its expected
settlement value.
Inherent in the fair value calculation of ARO are numerous assumptions
and judgments including the ultimate settlement amounts, inflation factors,
credit adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the fair value of the existing ARO
liability, a corresponding adjustment is made to the oil and natural gas
property balance.
The following table is a reconciliation of the asset retirement
obligation liability since adoption (in thousands):
Asset retirement obligation upon adoption on January 1, 2003 $ 597
Liabilities incurred 91
Liabilities settled -
Accretion expense 42
Revisions in estimated liabilities 153
-----
Asset retirement obligation at December 31, 2003 $ 883
=====
The pro forma asset retirement obligation would have been approximately
$0.3 million at January 1, 2001 had the Company adopted the provisions of SFAS
143 on January 1, 2001. The following table shows the pro forma effect of the
implementation on the Company's Net Income available to Common Shareholders
before cumulative effect of change in account principle had SFAS No. 143 been
adopted by the Company on January 1, 2001.
F-16
FOR THE YEAR ENDED
DECEMBER 31,
----------------------
2001 2002
--------- ---------
(In thousands, except
per share data)
Net income available to common shareholders $ 9,531 $ 4,202
Effect on Net Income had SFAS No. 143 been applied (24) (37)
--------- ---------
Income Attributable to Common Stock before cumulative
effect of change in accounting principle $ 9,507 $ 4,165
========= =========
Basic Net Income per Common Share:
Net Income $ 0.68 $ 0.30
Effect on Net Income had SFAS No. 143 been applied - -
--------- ---------
Net Income $ 0.68 $ 0.30
========= =========
Diluted Net Income per Common Share:
Net Income $ 0.57 $ 0.26
Effect on Net Income had SFAS No. 143 been applied - -
--------- ---------
Net Income $ 0.57 $ 0.26
========= =========
In January 2003, the FASB issued Interpretation No. 46 "Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51." Interpretation No. 46 requires a company to consolidate a variable
interest entity (VIE) if the company has a variable interest (or combination of
variable interests) that is exposed to a majority of the entity's expected
losses if they occur, receive a majority of the entity's expected residual
returns if they occur, or both. In addition, more extensive disclosure
requirements apply to the primary and other significant variable interest owners
of the VIE. This interpretation applies immediately to VIEs created after
January 31, 2003, and to VIEs in which an enterprise obtains an interest after
that date. It is also generally effective for the first fiscal year or interim
period beginning after December 31, 2003, to VIEs in which a company holds a
variable interest that is acquired before February 1, 2003. This interpretation
did not affect the Company's consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." SFAS
No. 150 establishes standards on how companies classify and measure certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that the Company classify as liabilities the fair value of
all mandatorily redeemable financial instruments that had previously been
recorded as equity or elsewhere in the consolidated financial statements. This
statement is effective for financial instruments entered into or modified after
May 31, 2003, and otherwise effective for all existing financial instruments,
except for minority interests in limited-life entities, beginning in the third
quarter of 2003. This statement did not affect the Company's financial
statements.
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 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
were paid in 2003.
F-17
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 natural 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.
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, 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.
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 acreage prospective for
coalbed methane development in the Powder River Basin of Wyoming from Gastar
Exploration, Ltd. 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.
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. As of June 30, 2003, approximately $1.1 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 acreage in 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. Other than indirectly
through Pinnacle, CCBM currently has no proved reserves of, and is no longer
receiving revenue from, coalbed methane gas.
As of December 31, 2003, on a fully diluted basis, assuming that all
parties exercised their Pinnacle Warrants and Pinnacle Stock Options, the CSFB
Parties, CCBM and RMG would have ownership interests of approximately 46.2%,
26.9% and 26.9%, respectively. In March 2004, the CSFB Parties contributed
additional funds of $11.8 million into Pinnacle to continue funding the 2004
development program which will increase their ownership to 66.7% on a fully
diluted basis should CCBM and RMG each elect not to exercise their available
options. Assuming that CCBM and RMG exercise their Pinnacle Stock Options, the
CSFB parties' ownership interest in Pinnacle would be 54.6% and CCBM and RMG
each would own 22.7% on a fully diluted basis.
For accounting purposes, the transaction was 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 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-K for the year ended December 31, 2003.
F-18
5. PROPERTY AND EQUIPMENT
At December 31, 2002 and 2003, property and equipment consisted of the
following:
AS OF DECEMBER 31,
----------------------
2002 2003
--------- ---------
(IN THOUSANDS)
Proved oil and natural gas properties $ 133,032 $ 168,329
Unproved oil and natural gas properties 42,020 32,978
Other equipment 685 742
--------- ---------
Total property and equipment 175,737 202,049
Accumulated depreciation, depletion and amortization (55,211) (66,776)
--------- ---------
Property and equipment, net $ 120,526 $ 135,273
========= =========
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
$32.9 million of unproved property costs at December 31, 2003 being excluded
from the amortizable base, $5.3 million, $5.4 million and $7.2 million were
incurred in 2001, 2002 and 2003, respectively, and $15.0 million was incurred in
prior years. These costs are primarily seismic and 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.
6. 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,
------------------------
2001 2002 2003
------ ------ ------
(IN THOUSANDS)
Provision at the statutory tax rate $5,204 $2,660 $4,586
Preferred dividend on Pinnacle - - 108
Increase in valuation allowance
for equity in loss of Pinnacle - - 189
State taxes 132 149 180
------ ------ ------
Income tax provision $5,336 $2,809 $5,063
====== ====== ======
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, 2002 and 2003, the tax effects of these temporary
differences resulted principally from the following:
F-19
AS OF DECEMBER 31,
--------------------
2002 2003
-------- --------
(IN THOUSANDS)
Deferred income tax asset:
Net operating loss carryforward $ 2,529 $ 1,763
Hedge valuation 209 100
Equity on loss of Pinnacle - 189
Valuation allowance (15) (204)
-------- --------
2,723 1,848
-------- --------
Deferred income tax liabilities:
Oil and gas acquisition, exploration
and development costs deducted for
tax purposes in excess of financial
statement DD&A 6,361 9,544
Capitalized interest 3,819 4,683
-------- --------
10,180 14,227
-------- --------
Net deferred income tax liability $ 7,457 $ 12,379
======== ========
The net deferred income tax liability is classified as follows:
AS OF DECEMBER 31,
-----------------
2002 2003
-----------------
(IN THOUSANDS)
Other current assets $ 209 $ 100
Deferred income taxes 7,666 12,479
------- -------
Net deferred income tax liability $ 7,457 $12,379
======= =======
Realization of the 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 other than
the deferred tax asset attributable to Pinnacle will be fully realized. A full
valuation allowance has been established for the equity in loss of Pinnacle's
tax asset as the realization of the deferred tax asset is dependent on
generating sufficient taxable income in Pinnacle in future periods. It is more
unlikely than not that Pinnacle will realize the tax benefit. The Company has
net operating loss carryforwards totaling approximately $5.0 million, which
begin expiring in 2012 through 2021.
7. LONG-TERM DEBT
At December 31, 2002 and 2003, long-term debt consisted of the
following:
F-20
AS OF DECEMBER 31,
--------------------
2002 2003
-------- --------
(IN THOUSANDS)
Hibernia Facility $ 8,500 $ 7,000
Senior subordinated notes, related parties 25,478 26,992
Capital lease obligations 267 295
Non-recourse note payable to RMG 5,250 863
-------- --------
39,495 35,150
Less: current maturities (1,609) (1,037)
-------- --------
$ 37,886 $ 34,113
======== ========
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 and 2003 was
$13.0 million and $19.0 million, respectively. 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, 2004 is $3.0
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. 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. As
such, the total borrowing base under the Hibernia Facility as of December 31,
2002 and 2003 was $15.5 million and $19.0 million, respectively, of which $8.5
and $7.0 million, respectively, was drawn on the Hibernia Facility.
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 earnings occurring
subsequent to such quarter end, all ratios as more particularly discussed in the
credit facility. The Hibernia Facility also places restrictions on
F-21
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 2003, amounts outstanding under the Hibernia
Facility totaled $8.5 million and $7.0 million, respectively, with an additional
$6.8 million and $12.0 million, respectively, available for future borrowings.
At December 31, 2002 and 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 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. In
connection with the Company's investment in Pinnacle (see Note 4), 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 years ended December 31, 2002 and 2003 amounted to
$28,000 and $48,000, respectively, and accumulated DD&A on the leased equipment
at December 31, 2002 and 2003 amounted to $28,000 and $78,000, 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 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 JPMorgan Partners
(23A SBIC), L.P.), 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 2003, the outstanding balance of the Subordinated Notes had been
increased by $3.9 million and $5.3 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 Partners, LLC appointed director).
Estimated maturities of long-term debt are $1.0 million in 2004, $7.1
million in 2005, and the remainder in 2007.
At December 31, 2003, the Company was in compliance with all of its
debt covenants,
8. 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 an additional payment of
$0.8 million is due in April 2004.
9. CONVERTIBLE PARTICIPATING PREFERRED STOCK
F-22
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 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
Ventures, Inc. 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 2003, the outstanding balance of
the Series B Preferred Stock has been increased by $0.5 million (5,294 shares)
and $1.2 million (11,987 shares), respectively, 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.
10. 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.
At December 31, 2003, the Company was obligated under a noncancelable
operating lease for office space. Rent expense for the years ended December 31,
2001, 2002 and 2003 was $0.2 million. The Company is obligated for remaining
lease payments of $0.2 million per year through December 31, 2004.
11. SHAREHOLDERS' EQUITY
The Company issued 113,306 and 413,965 shares of common stock valued at
$0.5 million and $1.9 million for the years ended December 31, 2002 and 2003,
respectively. Of the shares issued during 2002, 106,472 were issued as partial
consideration for the acquisition of interests in certain oil and natural gas
properties and, of the shares issued during 2003, 167,964 were issued as
consideration for an acquisition of certain seismic data and working interests
in certain producing properties.
The following table summarizes information for the options outstanding
at December 31, 2003:
F-23
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------- ----------------------
WEIGHTED
NUMBER OF AVERAGE WEIGHTED NUMBER OF WEIGHTED
OPTIONS REMAINING AVERAGE OPTIONS AVERAGE
OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE
RANGE OF EXERCISE PRICES AT 12/31/03 LIFE IN YEARS PRICE AT 12/31/03 PRICE
- ------------------------ ----------- ------------- -------- ----------- --------
$1.75-2.25 580,702 6.09 $ 2.20 580,702 $ 2.20
$3.14-4.00 235,120 4.79 $ 3.56 283,120 $ 3.56
$4.01-5.00 634,667 8.13 $ 4.30 272,278 $ 4.22
$5.17-8.00 187,333 6.46 $ 6.52 136,222 $ 6.67
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.
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 2001, 2002 and 2003: risk free interest rate of 4.9%, 4.8% and
4.0% respectively, expected dividend yield of 0%, expected life of 10 years and
expected volatility of 80.7%, 77.7% and 72.2% 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
1,823,500 shares through December 31, 2003. Through December 31, 2003, 211,798
stock options had been exercised. A summary of the status of the Company's stock
options at December 31, 2001, 2002 and 2003 is presented in the table below:
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-24
2003
--------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
--------- ---------- -------------
Outstanding at beginning of year 1,630,323 $ 3.35 $1.75 - $8.00
Granted (Incentive Plan Options) 257,500 $ 4.63 $4.37 - $5.75
Exercised (Pre-IPO Options) (85,000) $ 3.60 $3.60
Exercised (Incentive Plan Options) (161,001) $ 2.39 $2.00 - $4.40
Expired (Incentive Plan Options) (4,000) $ 3.33 $2.25 - $4.40
--------- ----------
Outstanding at end of year 1,637,822 $ 3.63 $1.75 - $8.00
========= ==========
Exercisable at end of year 1,261,655 $ 3.44
========= ==========
Weighted average of fair value of
options granted during the year $ 3.65
=========
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 records 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, 2002 and 2003 amounted to $(0.6 million), $(0.1 million) and $0.3 million,
respectively.
12. RELATED-PARTY TRANSACTIONS
During the years ended December 31, 2002 and 2003, the Company incurred
drilling costs in the amount of and $2.9 million and $2.2 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. During the year ended
December 31, 2003 the Company incurred lease operating costs of $0.4 million
with Basic Services, Inc. Mr. Webster and Mr. Johnson are members of the Board
of Directors of Basic Services, Inc. It is management's opinion that the
transactions with both of these entitities were performed at prevailing market
rates.
At December 31, 2003, the Company had outstanding related party
accounts payable balances of $0.9 million. 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, 2002 and 2003, the Company
participated in the drilling of one well and no wells, respectively, that were
operated by a subsidiary of Brigham Exploration Company. During the years ended
December 31, 2002 and 2003, Brigham Exploration Company ("Brigham") participated
in the drilling of two wells and two wells, respectively, operated by the
Company. During the year ended December 31, 2003, the Company incurred $0.7
million of operating expenses with Brigham and Brigham incurred drilling and
operating expenses of $2.8 million with 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 7 and 9 for a discussion of the investment in Pinnacle,
Subordinated Notes and Series B Preferred Stock, respectively, with parties that
include members of the Company's Board of Directors or their affiliates.
F-25
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, 2002
and 2003. 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 the Pinnacle transaction.
The Company entered into a transition services agreement with Pinnacle
pursuant to which the Company provided certain accounting, treasury, tax,
insurance and financial reporting functions to Pinnacle for a monthly fee equal
to the Company's actual cost to provide such services.
13. 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 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, 2003, $0.2 million, net of tax of $0.1 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 2001, 2002
and 2003 were 18,000 Bbls, 131,300 Bbls and 193,600 Bbls, respectively. Total
natural gas purchased and sold under swaps and collars in 2001, 2002 and 2003
were 3,087,000 MMBtu, 2,314,000 MMBtu and 2,739,000 MMBtu respectively. The net
gains and (losses) realized by the Company under such hedging arrangements were
$2.0 million, $(0.9 million) and $(1.8 million) for 2001, 2002 and 2003,
respectively, and are included in oil and natural gas revenues.
At December 31, 2002 and 2003 the Company had the following outstanding
hedge positions:
F-26
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
DECEMBER 31, 2003
- ------------------------------------------------------------------------------------------------
CONTRACT VOLUMES
-------------------
AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
- -------------------------- ------ ------- ----------- ----------- -------------
First Quarter 2004 27,000 $ 30.36
First Quarter 2004 180,000 6.67
First Quarter 2004 546,000 $ 4.10 $ 7.00
Second Quarter 2004 18,300 30.38
Second Quarter 2004 546,000 4.00 5.60
Third Quarter 2004 552,000 4.00 5.60
Fourth Quarter 2004 369,000 4.00 5.80
Subsequent to December 31, 2003, the Company entered into costless
collar arrangements covering 1,641,000 MMBtu of natural gas for April 2004
through March 2005 production with an average floor price of $4.75 and an
average ceiling price of $7.04. The Company also entered into swap arrangements
covering 18,300 Bbls of crude oil for June 2004 through July 2004 production at
an average fixed price of $33.63.
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 December 31, 2003, these options have expired
and a charge of $119,000 has been included in other income and expenses for the
year ended December 31, 2003.
14. SUBSEQUENT EVENTS
SECONDARY COMMON STOCK OFFERING
In the first quarter of 2004, the Company completed the public offering
of 6,485,000 shares of our common stock at $7.00 per share. The offering
included 3,655,500 newly issued shares offered by Carrizo and 2,829,500 shares
offered by certain existing stockholders. The Company expects to use the net
proceeds from this offering to accelerate its drilling program and to retain
larger interests in portions of its drilling prospects that Carrizo otherwise
would sell down or for which Carrizo would seek joint partners and for general
corporate purposes. In the meantime, Carrizo used a portion of the net proceeds
to repay the $7 million outstanding principal amount under our revolving credit
facility. Carrizo did not receive any proceeds from the shares offered by the
selling stockholders.
BARNETT SHALE ACQUISITION
On February 27, 2004, the Company closed a transaction with a private
company to acquire working interests and acreage in
F-27
certain oil and natural gas wells located in Denton County, Texas in the Newark
East Field in the Barnett Shale trend. This acquisition, with a purchase price
of $8.2 million, includes non-operated working interests in properties ranging
from 12.5% to 45%, or an average working interest of 39 percent. The effective
date of the purchase was March 1, 2004.
Initially, we financed the acquisition with our available cash on hand.
In the near term, we expect to establish a new project financing facility to
finance the acquisition and to fund the capital expenditure program for the
Barnett Shale play.
PINNACLE GAS RESOURCES, INC.
As of December 31, 2003, 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. In March 2004, the CSFB Parties contributed
additional funds of $11.8 million into Pinnacle to continue funding the 2004
development program which will increase their ownership to 66.7% on a fully
diluted basis should CCBM and RMG each elect not to exercise their available
options. Assuming that CCBM and RMG exercise their Pinnacle Stock Options, the
CFSB parties' ownership interest in Pinnacle would be 54.6% and CCBM and RMG
each would own 22.7% on a fully diluted basis.
15. 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."
COSTS INCURRED
Costs incurred in oil and natural gas property acquisition, exploration and
development activities are summarized below:
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2001 2002 2003
-------- -------- --------
(IN THOUSANDS)
Property acquisition costs
Unproved $ 12,607 $ 6,402 $ 7,280
Proved 800 660 -
Exploration costs 18,356 14,194 23,745
Development costs 3,065 2,351 112
Asset retirement obligation - - 744
-------- -------- --------
Total costs incurred (1) $ 34,828 $ 23,607 $ 31,881
======== ======== ========
- ----------
(1) Excludes capitalized interest on unproved includes properties of $3.2
million, $3.1 million and $2.9 million for the years ended December 31,
2001, 2002 and 2003, respectively, and includes capitalized overhead of
$1.0 million, $1.0 million and $1.4 million for the years ended
December 31, 2001, 2002 and 2003, respectively. The table also includes
non-cash asset retirement obligations of $0.7 million for the year
ended December 31, 2003.
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.
F-28
Proved oil and natural gas reserve quantities at December 31, 2002 and
2003, and the related discounted future net cash flows before income taxes are
based on estimates prepared by Ryder Scott Company and Fairchild & 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,
---------------------------------------
2001 2002 2003
----- ---- ----
Proved developed and undeveloped reserves -
Beginning of year 6,397 6,857 8,381
Discoveries and extensions 600 369 231
Revisions 20 1,568 553
Sales of oil and gas properties in place - (12) (1)
Production (160) (401) (450)
----- ----- -----
End of year 6,857 8,381 8,714
===== ===== =====
Proved developed reserves at beginning of year 1,017 1,158 1,393
===== ===== =====
Proved developed reserves at end of year 1,158 1,393 1,395
===== ===== =====
MILLIONS OF CUBIC FEET
OF NATURAL GAS
AT DECEMBER 31,
----------------------------------------
2001 2002 2003
------ ------ ------
Proved developed and undeveloped reserves -
Beginning of year 10,992 17,858 12,922
Purchases of oil and gas properties in place - 585 -
Discoveries and extensions 12,560 3,280 10,305
Revisions (1,262) (3,726) 129
Sales of oil and gas properties in place - (274) (523)
Production (4,432) (4,801) (4,764)
------ ------ ------
End of year 17,858 12,922 18,069
====== ====== ======
Proved developed reserves at beginning of year 10,351 13,754 12,826
====== ====== ======
Proved developed reserves at end of year 13,754 12,826 17,098
====== ====== ======
Carrizo uses the equity method of accounting to record its minority
ownership in the operations of Pinnacle, formed in June 2003. Accordingly, the
proved reserve tables, above, do not include the Company's interest ownership,
26.9% on a fully diluted basis, in the proved reserves of Pinnacle at the end of
2003, or an estimated 4.9 Bcfe of proved reserves.
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:
F-29
YEAR ENDED DECEMBER 31,
-------------------------------------------------
2001 2002 2003
-------- -------- ---------
(IN THOUSANDS)
Future cash inflows $ 169,856 $305,087 $ 375,160
Future oil and natural gas operating expenses 78,378 142,597 167,090
Future development costs 16,083 15,259 15,943
Future income tax expenses 10,328 33,232 45,540
--------- -------- ---------
Future net cash flows 65,087 113,999 146,587
10% annual discount for estimating timing of cash flows 23,683 49,702 58,961
--------- -------- ---------
Standard measure of discounted future net cash flows $ 41,384 $ 64,297 $ 87,626
========= ======== =========
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 2001, 2002 and 2003 future cash flows
were $17.71, $29.16 and $30.29 for oil, respectively and $2.76, $4.70 and $6.19
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.
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,
------------------------------------------------
2001 2002 2003
--------- --------- ---------
(IN THOUSANDS)
Changes due to current-year operations -
Sales of oil and natural gas, net of oil
and natural gas operating expenses $ (23,622) $ (23,377) $ (34,177)
Extensions and discoveries 28,009 20,680 42,530
Purchases of oil and gas properties - 888 -
Changes due to revisions in standardized variables
Prices and operating expenses (39,919) 36,511 8,654
Income taxes 10,174 (12,748) (9,606)
Estimated future development costs 982 417 (377)
Revision of quantities (1,071) 8,818 5,374
Sales of reserves in place - (191) (836)
Accretion of discount 8,768 4,795 8,304
Production rates, timing and other (12,043) (12,880) 3,463
--------- --------- ---------
Net change (28,722) 22,913 23,329
Beginning of year 70,106 41,384 64,297
--------- --------- ---------
End of year $ 41,384 $ 64,297 $ 87,626
========= ========= =========
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, extentions 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.
F-30
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
(UNAUDITED)
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
FIRST SECOND THIRD FOURTH
---------- ---------- ---------- ----------
2003
Revenues $ 10,663 $ 8,828 $ 10,123 $ 8,893
Costs and expenses, net 7,693 6,868 8,041 7,866
---------- ---------- ---------- ----------
Net income 2,970 1,960 2,082 1,027
Dividends and accretion 181 181 190 189
---------- ---------- ---------- ----------
Net income available to common
shareholders before cumulative effect
in accounting principle $ 2,789 $ 1,779 $ 1,892 $ 838
========== ========== ========== ==========
Cumulative effect in change of
in accounting principle 128 - - -
---------- ---------- ---------- ----------
Net income available to
common shareholders $ 2,661 $ 1,779 $ 1,892 $ 838
========== ========== ========== ==========
Basic net income per share (1) $ 0.19 $ 0.13 $ 0.13 $ 0.06
========== ========== ========== ==========
Diluted net income per share (1) $ 0.16 $ 0.11 $ 0.11 $ 0.05
========== ========== ========== ==========
FIRST SECOND THIRD FOURTH
---------- ---------- ---------- ----------
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
========== ========== ========== ==========
(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-31
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CARRIZO OIL & GAS, INC.
By: /s/ PAUL F. BOLING
-------------------------------
Paul F. Boling
Chief Financial Officer, Vice President,
Secretary and Treasurer
Date: March 30, 2004.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
NAME CAPACITY DATE
- -------------------------- ------------------------------- --------------
/s/ S. P. JOHNSON IV President, Chief Executive March 30, 2004
- -------------------------- Officer and Director (Principal
S. P. Johnson IV Executive Officer)
/s/ PAUL F. BOLING Chief Financial Officer, Vice March 30, 2004
- -------------------------- President, Secretary and
Paul F. Boling Treasurer (Principal Financial
Officer and Principal
Accounting Officer)
/s/ STEVEN A. WEBSTER Chairman of the Board March 30, 2004
- --------------------------
Steven A. Webster
/s/ CHRISTOPHER C. BEHRENS Director March 30, 2004
- --------------------------
Christopher C. Behrens
/s/ BRYAN R. MARTIN Director March 30, 2004
- --------------------------
Bryan R. Martin
/s/ DOUGLAS A. P. HAMILTON Director March 30, 2004
- --------------------------
Douglas A. P. Hamilton
/s/ PAUL B. LOYD, JR. Director March 30, 2004
- --------------------------
Paul B. Loyd, Jr.
/s/ F. GARDNER PARKER Director March 30, 2004
- --------------------------
F. Gardner Parker
/s/ FRANK A. WOJTEK Director March 30, 2004
- --------------------------
Frank A. Wojtek
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- --------------------------------------------------------------------------------------------
1.1 -- Underwriting Agreement, dated February 5, 2004, by and among Carrizo Oil & Gas, Inc., and
CIBC World Markets Corp., First Albany Capital, Inc., Hibernia Southcoast Capital,
Inc., and Johnson Rice & Company, L.L.C., as representatives of the several
underwriters named in Schedule I to the Underwriting Agreement, and the selling
shareholders listed on Schedule II to the Underwriting Agreement.
+2.1 -- Combination Agreement by and among 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, 1998 (Incorporated herein by reference to Exhibit 2.1 to the Company's Registration
Statement on Form S-1 (Registration No. 333-29187)).
+3.1 -- Amended and Restated Articles of Incorporation of the Company (Incorporated herein by
reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1998).
+3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (Incorporated
herein by reference to Exhibit 3.2 to the Company's Registration Statement on Form 8-A
(Registration No. 000-22915), Amendment No. 2 (Incorporated herein by reference to
Exhibit 3.2 to the Company's Current Report on Form 8-K dated December 15, 1999) and
Amendment No. 3 (Incorporated herein by reference to Exhibit 3.1 to the Company's
Current Report on Form 8-K dated February 20, 2002).
+3.3 -- Statement of Resolution dated February 20, 2002 establishing the Series B Convertible
Participating Preferred Stock providing for the designations, preferences, limitations
and relative rights, voting, redemption and other rights thereof (Incorporated herein
by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated February
20, 2002).
+4.1 -- Revolving Note by and between Carrizo Oil & Gas, Inc. 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).
+4.2 -- 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).
+4.3 -- Stock Pledge and Security Agreement by and between Carrizo Oil & Gas, Inc. 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).
+4.4 -- Amended and Restated Credit Agreement dated as of December 12, 2002 by and between
Carrizo Oil & Gas, Inc., CCBM, Inc. and Hibernia National Bank. (Incorporated
herein by reference to Exhibit 4.6 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2002).
+4.5 -- Letter Agreement Regarding Participation in the Company's 2001 Seismic and Acreage
Program, dated May 1, 2001 (Incorporated herein by reference to Exhibit 4.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
+4.6 -- Amendment No. 1 to the Letter Agreement Regarding Participation in the Company's 2001
Seismic and Acreage Program, dated June 1, 2001 (Incorporated herein by reference to
Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 2001).
+4.7 -- Promissory Note payable to Rocky Mountain Gas, Inc. by CCBM, Inc. (Incorporated herein by
reference to Exhibit 4.3 to the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2001).
+10.1 -- Amended and Restated Incentive Plan of the Company effective as of February 17, 2000
(Incorporated herein 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
herein by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 2002).
+10.3 -- Amendment No. 2 to the Amended and Restated Incentive Plan
of the Company. (Incorporated herein by reference to Exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year ended December 31, 2002).
+10.4 -- Amendment No. 3 to the Amended and Restated Incentive Plan of the Company.
(Incorporated herein by reference to Appendix A to the Company's Proxy Statement dated
April 21, 2003).
+10.5 -- Employment Agreement between the Company and S.P. Johnson IV (Incorporated herein by
reference to Exhibit 10.2 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 herein 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 (Incorporated herein by
reference to Exhibit 10.8 to the Company's Registration Statement on Form S-2
(Registration No. 333-111475)).
+10.9 -- Employment Agreement between the Company and Paul F. Boling (Incorporated herein by
reference to Exhibit 10.9 to the Company's Registration Statement on Form S-2).
+10.10 -- Indemnification Agreement between the Company and each of its directors and executive
officers (Incorporated herein by reference to Exhibit 10.6 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998).
+10.11 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and
Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated herein by reference
to Exhibit 10.8 to the Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.12 -- S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo
Production, Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (Incorporated
herein by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1
(Registration No. 333-29187)).
+10.13 -- Form of Amendment to Executive Officer Employment Agreement. (Incorporated herein by
reference to Exhibit 99.3 to the Company's Current Report on Form 8-K dated January 8,
1998).
+10.14 -- Amended Enron Warrant Certificates (Incorporated herein by reference to Exhibit 4.1 to
the Company's Current Report on Form 8-K dated December 15, 1999).
+10.15 -- Securities Purchase Agreement dated December 15, 1999 among the Company, CB Capital
Investors, L.P., Mellon Ventures, L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton and
Steven A. Webster (Incorporated herein by reference to Exhibit 99.1 to the Company's
Current Report on Form 8-K dated December 15, 1999).
+10.16 -- Shareholders Agreement dated December 15, 1999 among the Company, CB Capital Investors,
L.P., Mellon Ventures, L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton, Steven A.
Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P. (Incorporated
herein by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K dated
December 15, 1999).
+10.17 -- Warrant Agreement dated December 15, 1999 among the Company, CB Capital Investors, L.P.,
Mellon Ventures, L.P., Paul B. Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster
(Incorporated herein by reference to Exhibit 99.3 to the Company's Current Report on
Form 8-K dated December 15, 1999).
+10.18 -- Registration Rights Agreement dated December 15, 1999 among the Company, CB Capital
Investors, L.P. and Mellon Ventures, L.P. (Incorporated herein by reference to Exhibit
99.4 to the Company's Current Report on Form 8- K dated December 15, 1999).
+10.19 -- Amended and Restated Registration Rights Agreement dated December 15, 1999 among the
Company, Paul B. Loyd Jr., Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV,
Frank A. Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference to
Exhibit 99.5 to the Company's Current Report on Form 8-K dated December 15, 1999).
+10.20 -- Compliance Sideletter dated December 15, 1999 among the Company, CB Capital Investors,
L.P. and Mellon Ventures, L.P. (Incorporated herein by reference to Exhibit 99.6 to the
Company's Current Report on Form 8-K dated December 15, 1999).
+10.21 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by
reference to Exhibit 99.7 to the Company's Current Report on Form 8-K dated December
15, 1999).
+10.22 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference
to Exhibit 99.8 to the Company's Current Report on Form 8-K dated December 15, 1999).
+10.23 -- Purchase and Sale Agreement by and between Rocky Mountain Gas, Inc. and CCBM, Inc., dated
June 29, 2001 (Incorporated herein by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
+10.24 -- Securities Purchase Agreement dated February 20, 2002 among
the Company, Mellon Ventures, L.P. and Steven A. Webster (Incorporated herein by
reference to Exhibit 99.1 to the Company's Current Report on Form 8-K dated February
20, 2002).
+10.25 -- Shareholders' Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P.,
Paul B. Loyd, Jr., Douglas A.P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A.
Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference to Exhibit 99.3
to the Company's Current Report on Form 8-K dated February 20, 2002).
+10.26 -- Warrant Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and
Steven A. Webster (including Warrant Certificate) (Incorporated herein by reference to
Exhibit 99.4 to the Company's Current Report on Form 8-K dated February 20, 2002).
+10.27 -- Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures,
L.P. and Steven A. Webster (Incorporated herein by reference to Exhibit 99.5 to the
Company's Current Report on Form 8-K dated February 20, 2002).
+10.28 -- Compliance Sideletter dated February 20, 2002 between the Company and Mellon Ventures,
L.P. (Incorporated herein by reference to Exhibit 99.6 to the Company's Current Report
on Form 8-K dated February 20, 2002).
+10.29 -- Form of Amendment to Executive Officer Employment Agreement (Incorporated herein by
reference to Exhibit 99.7 to the Company's Current Report on Form 8-K dated February
20, 2002).
+10.30 -- Form of Amendment to Director Indemnification Agreement (Incorporated herein by reference
to Exhibit 99.8 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 herein 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 herein by reference to Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2003).
21.1 -- Subsidiaries of the Company.
23.1 -- Consent of Ernst & Young LLP
23.2 -- Consent of Ryder Scott Company Petroleum Engineers.
23.3 -- Consent of Fairchild & Wells, Inc.
23.4 -- Notice Regarding Consent of Arthur Andersen LLP.
31.1 -- CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 -- CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum Engineers as of December 31,
2003.
99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of December 31, 2003.
- --------------------
+ Incorporated by reference as indicated.