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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.
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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
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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
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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.
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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.
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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
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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).
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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 i