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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, 2004
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.)
1000 LOUISIANA STREET, SUITE 1500 77002
Houston, Texas (Zip Code)
(Principal executive offices)
Registrant's telephone number, including area code: (713) 328-1000
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 [X] NO [ ]
At June 30, 2004, the aggregate market value of the registrant's Common
Stock held by non-affiliates of the registrant was approximately $159.4 million
based on the closing price of such stock on such date of $10.21.
At January 31, 2005, the number of shares outstanding of the registrant's
Common Stock was 22,456,007.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 2005 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, 2004.
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TABLE OF CONTENTS
PART I.................................................................... 2
Item 1. and Item 2. Business and Properties............................ 2
Item 3. Legal Proceedings.............................................. 24
Item 4. Submission of Matters to a Vote of Security Holders............ 24
Executive Officers of the Registrant................................... 24
PART II................................................................... 25
Item 5. Market for Registrant's Common Stock, Related Shareholder
Matters and Issuer Purchases of Equity Securities................... 25
Item 6. Selected Financial Data........................................ 26
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................... 28
Item 7A. Qualitative and Quantitative Disclosures About Market Risk.... 51
Item 8. Financial Statements and Supplementary Data.................... 52
Item 9. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure............................................ 52
Item 9A. Controls and Procedures....................................... 52
Item 9B. Other Information............................................. 52
PART III.................................................................. 52
Item 10. Directors and Executive Officers of the Registrant............ 52
Item 11. Executive Compensation........................................ 52
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Shareholder Matters.......................... 53
Item 13. Certain Relationships and Related Transactions................ 53
Item 14. Principal Accountant Fees and Services........................ 53
PART IV................................................................... 53
Item 15. Exhibits and Financial Statement Schedules.................... 53
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 area
in Texas and Louisiana, primarily in the Miocene, Wilcox, Frio and Vicksburg
trends, and, since mid-2003, in the Barnett Shale area in North Texas. Our other
interests include properties in East Texas, and a coalbed methane investment in
the Rocky Mountains. 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, 2004 on an annualized basis was 14%. From
our inception through December 31, 2004, we participated in the drilling of 373
wells (119.7 net) with a success rate of approximately 70% in our onshore Gulf
Coast area and 100% in the Barnett Shale area in North Texas. Exploratory wells
accounted for 86% of the total wells we drilled. Our total proved reserves as of
December 31, 2004 were an estimated 109.3 Bcfe with a PV-10 Value of $208.6
million. During 2004, we added a record 47.3 Bcfe to proved reserves and
produced a record 8.3 Bcfe. We have traditionally 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 9,200 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
area by approximately 84% to over 7,500 square miles, in large part by taking
advantage of very favorable pricing available for nonproprietary data from
libraries of seismic companies. Since 2003, we have also grown our 3-D seismic
holdings in the Barnett Shale area to over 123 square miles.
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, Ocean Energy, ARCO, Conoco, Burlington Resources, Vastar, 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 in the Gulf Coast area. As of December 31,
2004, we had 159,496 gross acres in Texas and Louisiana under lease or lease
option (all references to acres under lease in this Form 10-K also include lease
option acres unless otherwise indicated), including 109,129 net acres in our
onshore Gulf Coast area, predominantly all covered by 3-D seismic data, and
44,835 gross acres in our Barnett Shale area. On this leased acreage, we have
identified: (1) over 155 potential exploratory drilling locations in our onshore
Gulf Coast area, including over 78 additional extension opportunities, depending
on the success of our initial drilling activities on those locations and (2)
over 200 potential exploratory and development horizontal drilling locations in
the Barnett Shale area. The vast majority of our 3-D seismic data covers
productive geological trends in our onshore Gulf Coast area, where we have made
223 completions as a result of our utilization and evaluation of this data.
In our onshore Gulf Coast area, 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 used a portion of the $23.3 million of
net proceeds from our February 2004 public offering to increase our percentage
of and exposure to these wells.
In mid-2003, we became active in the Barnett Shale area in North Texas
(primarily in the Tarrant, Parker, Denton, Johnson, Hill and Erath counties).
Improvements in fracture techniques in recent years have dramatically changed
the economics of producing reserves in the Barnett Shale, which is now
considered one of the most active natural gas plays in North America. The
reserve profile
2
from the typical productive wells we drill in the Barnett Shale area is noteably
longer-lived compared to the typical reserve profile from our wells drilled in
our onshore Gulf Coast area.
We are drilling both vertical and horizontal wells in the Barnett Shale
area. Typical costs to drill and complete are $550,000 for vertical wells and
$1.5 to $2.5 million for horizontal wells. Our Barnett wells generally have
target depths of 6,000 to 8,000 feet. During 2004, we held an average 40
percent, usually non-operated, working interest participation in the Barnett
wells drilled. For wells drilled in 2005, we plan to retain larger working
interests, generally ranging between 50 and 100 percent, and to operate a
majority of the wells drilled.
Accordingly, we believe that continued development of 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 help fund our
future capital exploration and development program. In our Barnett Shale area
through December 31, 2004, we had acquired approximately 30,717 net acres,
drilled 33 gross (13.7 net) wells and increased our total proved reserves in the
Barnett Shale area to 31.7 Bcfe. As of March 1, 2005, our current net production
in the Barnett Shale area was estimated at 4.0 MMcfe/d and we had increased our
leasehold and option position to over 35,000 net acres.
As of December 31, 2004, we operated 92 producing oil and gas wells, which
accounted for 50% of the onshore Gulf Coast area 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 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 increased their ownership to 66.7% on a fully
diluted basis should we and RMG each elect not to exercise our available
options. See "The Pinnacle Transaction" for more information on this
transaction.
Historically, the business operations and development program of Pinnacle
has not required us to provide any further capital infusion. In March 2005,
Pinnacle acquired additional undeveloped acreage with an undisclosed company
which would also significantly increase Pinnacle's development program budget in
2005. Accordingly, CCBM and the other Pinnacle shareholders have the option to
participate in the equity contribution into Pinnacle needed to finance the
acquisition and the related development program in 2005. Should we elect to
maintain our proportionate ownership interest in Pinnacle, we estimate that we
would be required to contribute $2.5 million. If CCBM opts not to contribute any
or all of its share of the equity contribution, its fully diluted ownership in
Pinnacle would be reduced. CCBM plans to contribute $2.5 million in April 2005,
its share of the equity capital needed to close the acquisition and fund part of
the additional development program. There can be no assurance regarding CCBM's
level of participation in future equity contributions needed, if any. On March
29, 2005, we elected to participate and contribute $2.5 million to Pinnacle in
exchange for warrants and preferred stock.
In addition to our interest in Pinnacle, CCBM has maintained interests in
approximately 162,489 gross acres at the end of 2004 in the Castle Rock coalbed
methane project area in Montana and the Oyster Ridge project area in Wyoming.
During 2004, we opted to exercise our right to cancel one-half of the remaining
note payable to RMG, or approximately $300,000, in exchange for assigning
one-half of our mineral interest in the Oyster Ridge leases to RMG.
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:
3
- 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 area of 84% over the
last three years and a 100% drilling success rate in our Barnett Shale
area since inception in 2003. During 2005, we are drilling or plan to
drill approximately 34 wells (14.4 net) in the onshore Gulf Coast area
and 37 wells (24.0 net) in the Barnett Shale area. We have planned
approximately $85.0 to $90.0 million for capital expenditures in 2005,
$70.0 million of which we expect to use for drilling activities in the
onshore Gulf Coast and Barnett Shale areas.
- Focus on Prolific and Industry-Proven Trends. We focus our activities
both in the prolific onshore Gulf Cost area where our management, our
technical staff and our field operations teams have significant prior
experience and in the industry-proven Barnett Shale trend in which our
wells have generally longer-lived reserves. Although we have broadened
our areas of operations to include the Rocky Mountains and the U.K.
North Sea, we plan to focus a majority of our near-term capital
expenditures in the onshore Gulf Coast area, where we believe our
accumulated data and knowledge base provide a competitive advantage,
and in the Barnett Shale area where we have acquired a significant
acreage position and accumulated a large drillsite inventory.
- 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 trend of the onshore Gulf Coast area and
industry-proven trend of the Barnett Shale area. In 2004, we added
approximately [463] 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 in both the onshore Gulf Coast and Barnett
Shale areas. As of December 31, 2004, we had accumulated licenses for
approximately 9,200 square miles of 3-D seismic data and identified
over 355 drilling locations and extension opportunities (comprised of
155 locations in the onshore Gulf Coast area, and approximately 200
locations in the Barnett Shale area) including 277 locations currently
under lease or in the process of being leased (comprised of 77
locations in the onshore Gulf Coast area and 200 locations in the
Barnett Shale area).
- Maintain a Balanced Exploration Drilling Portfolio. We seek to balance
our drilling program between projects with relatively lower risk and
moderate potential and drilling prospects that have relatively higher
risk and substantial potential. We believe we have furthered this
strategy through the expansion of the Barnett Shale operations in
which our wells generally have longer-lived reserves and generally
lower risk/lower reward than our average onshore Gulf Coast area
wells. We will continue to expand our exploratory drilling portfolio,
including lease 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
reservoir engineers, who have an average of over 20 years of
experience. This level of expertise and experience gives us an
in-house ability to apply advanced technologies to our drilling and
production activities, including our extensive experience in
fracturing and horizontal drilling technologies. Our technical staff
is granted stock options and participates in an incentive bonus pool
based on production resulting from our exploratory successes.
EXPLORATION APPROACH
In the onshore Gulf Coast area, our exploration strategy has generally been
to accumulate large amounts of 3-D seismic data along primarily prolific,
producing trends after obtaining options to lease areas covered by the data. In
the case of our Barnett Shale area, our exploration strategy has been to
accumulate significant leasehold positions in the proximity of known or emerging
pipeline infrastructures, followed by the acquisition and processing of 3-D
seismic data. We 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 areas of expertise that we believe have (1)
longer-lived, reserve-proven trends, such as the Barnett Shale trend, (2)
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 or (3) the potential for large accumulations of deeper,
over-pressured reserves.
4
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 drilling 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.
Even in the relatively lower-risk, reserve-proven trends, such as the
Barnett Shale trend, 3-D seismic data interpretation is instrumental in our
exploration approach, significantly reducing geologic risk and allowing
optimized reserve development.
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 areas, thus allowing us to obtain access to
additional 3-D data within our onshore Gulf Coast area 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 onshore Gulf Coast area. This data
was 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.
In late 2004, we entered into a 3-D seismic data acquisition program, which
includes a joint venture partner that shares in a portion of the costs and
results of the seismic shoot, covering an approximate 95 square mile area in our
onshore Gulf Coast area located in Liberty County, Texas. This seismic survey
project and the related processed data are expected to be completed in the
second quarter of 2005. We also entered into a 3-D seismic data acquisition
program in late 2004 to complete seismic shoots over significant acreage
positions in our Barnett Shale area, covering an estimated 195 square miles by
year-end 2005.
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 complement 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 onshore Gulf Coast area is a core
competency to our continued success. Additionally, we believe that the
experience we have gained in the Barnett Shale area, along with our extensive
experience in fracturing and horizontal drilling technologies, will play a
significant part in our future success.
5
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, 2004,
we operated 92 producing oil and natural gas wells. Although we initially did
not act as operator for most of our projects in the Barnett Shale area, we now
generally seek to control operations for most new exploration and development in
that area, taking advantage of our technical staff experience in horizontal
drilling and hydraulic fracturing.
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 perform
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 area
extending from South Louisiana to South Texas and the Barnett Shale trend in
North Texas. Our other areas of interest are in East Texas, the Rocky Mountains
and the U.K. North Sea. The table below highlights our main areas of activity:
3-D PROJECT SUMMARY CHART
AS OF DECEMBER 31, 2004
PRODUCTIVE 3-D NET
WELLS SEISMIC OPTIONS/ DRILLING CAPITAL EXPENDITURES
------------- DATA LEASED -----------------------------
GROSS NET (SQ. MILES) ACRES 2004 2005 PLAN
----- ----- ----------- -------- ----- ---------
Onshore Gulf Coast:
Wilcox ............ 28 8.2 2,066 17,966 $ 9.2 $ 4.9
Frio/Vicksburg .... 91 27.5 2,166 7,750 8.7 6.3
Southeast Texas ... 11 4.4 881 17,275 7.0 4.8
South Louisiana ... 10 3.0 1,887 4,752 8.9 17.4
Barnett Shale ........ 38 13.8 123 30,717 15.1 35.0
East Texas ........... 45 43.9 503 1,449 1.7 1.6
Rocky Mountain ....... -- -- 473 16,709 0.6 --
North Sea ............ -- -- 153 209,613 -- --
Other Areas .......... -- -- 1005 7,151 -- --
--- ----- ----- ------- ----- -----
Total ............. 223 100.8 9,257 313,382 $51.2 $70.0
=== ===== ===== ======= ===== =====
- ----------
(1) We expect to seek additional financing to partially fund our exploration
and development program in 2005. Accordingly, our 2005 capital spending
program could decrease significantly if we do not obtain such financing.
--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 area into
four main producing areas: Wilcox, Frio/Vicksburg, Southeast Texas and South
Louisiana. Our onshore Gulf Coast area generally contains geologically complex
natural gas objectives well-suited for drilling using 3-D seismic evaluation.
6
In our onshore Gulf Coast area, we have identified over 155 exploratory
drilling opportunities on acreage we have under lease or have an option to
lease, including over 78 additional extension opportunities, depending on the
success of our initial drilling activities on those locations. We plan to spend
approximately $35.0 million on drilling expenditures in 2005, comprised of
approximately 34 wells (14.4 net). We also plan to spend $5 million to purchase
and reprocess 3-D seismic surveys during 2005.
TEXAS - WILCOX AREAS
We have licenses for approximately 2,066 square miles of 3-D seismic data
and 17,966 net acres of leasehold in the Wilcox trend in Texas. From January 1,
2001 through December 31, 2004, we drilled and completed 33 wells (10.9 net) on
39 attempts in this area. We incurred capital expenditures of $9.2 million and
drilled 11 wells (4.6 net) in the Texas Wilcox area in 2004 and expect to devote
approximately $4.9 million to drill nine wells (3.5 net) in this area in 2005.
As of March 1, 2005, we have identified over 25 exploratory drilling locations,
with an additional 37 potential extension opportunities, in the Wilcox trend
over which we have licenses for 3-D seismic data and leased acreage.
Approximately 12 of the 25 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.
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 Yegua formations. We have licenses for a total of
over 2,166 miles of 3-D seismic data and 7,750 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, 2005, we have identified over 21 exploratory drilling
locations with an additional 19 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 14 of the 21 exploratory locations we have identified are
relatively lower risk and generally shallower with the remaining seven being
relatively higher risk and deeper with greater upside potential.
From January 1, 2001 through December 31, 2004, we drilled and completed 41
wells (9.3 net) in 46 attempts in this trend. We incurred capital expenditures
of $8.7 million and drilled 16 wells (4.5 net) in the Frio/Vicksburg trend area
in 2004 and expect to devote approximately $6.3 million to drill nine wells (2.7
net) in this area in 2005.
Providence Field. We have licenses for over 540 square miles of 3-D data in
and surrounding the Providence Field we discovered in 2001. Since the discovery
well commenced production in January 2002, six wells have been drilled and
successfully completed. Four of the wells had average production rates ranging
from 14,339 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, 2004 of 18.0
Bcfe. We have working interests ranging from 35% to 45% in the leases in this
field and operate four of the six wells.
Encinitas Field. This field, the site of our first 3-D seismic survey in
1995, has 32 wells currently producing. Since 1996, we have participated in the
drilling of 29 wells (5.4 net) in this area, 27 (4.9 net) of which were
successfully completed. During 2004, we participated in the drilling of five
wells, all of which were successfully completed. We expect to drill four wells
(1.1 net) in 2005, with an additional eight well locations to be drilled
thereafter. We expect to 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 881 square miles of 3-D data over our
Southeast Texas project area which is focused primarily on the Frio, Yegua, Cook
Mountain and Vicksburg formations.
As of March 1, 2005, we have identified over 22 exploratory drilling
locations with an additional 12 potential extension locations in the Southeast
Texas area over which we have licenses for 3-D seismic data. Approximately 18 of
the 22 exploratory
7
locations we have identified are relatively lower risk and generally shallower
with the remaining four being relatively higher risk and deeper with greater
upside potential.
From January 1, 2001 to December 31, 2004, we participated in the drilling
and completion of 13 wells (4.5 net) in 17 attempts in this area. We incurred
capital expenditures of $7.0 million and drilled six wells (2.4 net) in the
Southeast Texas area in 2004 and expect to devote approximately $4.8 million and
drill five wells (1.7 net) in this area in 2005. 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 2005.
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 now covers significant areas of Liberty and Hardin
Counties, Texas. Since January 1, 2001, we have been successful on nine of 12
wells drilled. In 2002, we completed one well that produced an average of 9,787
Mcfe per day during the first 90 full days of production. We operate this well
and own a 40% working interest. In 2003, we had another drilling success in this
area with a well producing an average of 13,030 Mcfe per day during the first 90
full days of production. We operate this well and own a 46.3% working interest.
SOUTH LOUISIANA AREA
The South Louisiana area primarily contains objectives in the Middle and
Lower Miocene intervals. We have acquired licenses for approximately 1,887
square miles of 3-D data and approximately 4,752 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 nine exploratory drilling locations with
an additional ten potential extension locations in the South Louisiana area over
which we have licenses for 3-D seismic data. Four of the nine exploratory
locations we have identified are relatively lower risk and generally shallower
with the other five being relatively higher risk and deeper with greater upside
potential. From January 1, 2001 to December 31, 2004, we drilled and completed
nine wells (2.5 net) on 14 attempts in this area. We incurred capital
expenditures of $8.9 million and drilled four wells (1.7 net) in the South
Louisiana area in 2004 and expect to devote approximately $17.8 million to drill
ten wells (6.0 net) in this area in 2005.
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 one
additional well (0.2 net) in the general area during 2005.
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 in
2003.
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 included 21 existing gross wells (6.7 net) and interests in
approximately 1,500 net acres, which we expect to provide another 31 gross drill
sites.
During 2004, we drilled 33 additional wells (13.7 net) and acquired an
additional 26,617 net acres, increasing our acreage at the end of 2004 to 30,717
net acres (primarily in Tarrant, Parker, Denton, Johnson, Hill and Erath
counties). 17 out of those gross wells were on-line producing at year-end and
the remaining 16 wells are awaiting completion and pipeline hookup. 28 of the
drilled wells in 2004 were non-operated, with relatively low working interests.
In the second half of 2004, we initiated our operated drilling program and we
anticipate the majority of our activity going forward will focus on company
operated acreage.
We are continuing to expand our leasehold acquisition in this trend.
Production at the end of 2004 and at March 1, 2005 was approximately 2,800
Mcfe/d and 3,500 Mcfe/d, respectively. Net proved reserves have grown from 1.6
Bcfe in December 31, 2003 to 31.7 Bcfe at December 31, 2004.
8
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 500 square miles of
3-D seismic data in the East Texas area and 1,449 net acres under lease.
We expect to invest $1.6 million to drill nine (7.7 net) wells in this
region in 2005.
Camp Hill Project. We own interests in approximately 600 gross acres in the
Camp Hill field in Anderson County, Texas. We currently operate all of these
leases. During the year ended December 31, 2004, the project produced an average
of 56 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, 2004
averaged $19.87 per barrel ($3.31 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, 2004) than West Texas intermediate
crude due to its suitability as a lube oil feedstock. As of December 31, 2004,
we had 8.6 MMBbls of proved oil reserves in this project, with 969 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 (1) pursuing shorter-term exploration projects with
potentially higher rates of return, (2) adding to our lease position in this
field and (3) further evaluating additional economic enhancements for this
field's development. "See 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." The proved undeveloped reserves at the Camp Hill Field
constitute 41.8% of our proved reserves and account for 27.7% of our present
value of net future revenues from proved reserves as of December 31, 2004. 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 are
currently drilling with one rig and plan to spend approximately $0.6 million
drilling eight gross (7.2 net) wells in 2005. The planned Camp Hill development
expenditures represent a relatively small portion of the Company's total capital
expenditures budgeted in 2005. We continue to invest the majority of our 2005
budgeted capital expenditures in our Barnett Shale and onshore Gulf Coast areas
where the rates of return are traditionally higher. This is due in large measure
to significantly higher lifting costs associated with Camp Hill oil production.
We have an average working interest of approximately 90% in this field and an
approximate net revenue interest of 73%.
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 predecessor owner/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. Although
this attempted completion flowed gas at uneconomic rates, we expect to drill
another exploratory well in 2005 in a better structural position. We believe
there are over ten potential extension development locations on our acreage that
may be prospective.
WYOMING/MONTANA COALBED METHANE PROJECT AREA
Rocky Mountain Region
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. At the end of 2004, we also own direct interests in approximately
162,489 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.
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. See "-The Pinnacle
Transaction" for more information on this transaction.
By 2004 year end, Pinnacle had completed the acquisition and/or drilling of
486 wells (or approximately 276 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.
9
See "Regulation - Coalbed Methane Proceedings in Montana" for a description
of certain regulatory proceedings affecting coalbed methane drilling in Montana.
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 for 2005 are
$0.2 million, largely for data processing.
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 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, 2004. The
reserve data and the present value as of December 31, 2004 were prepared by
Ryder Scott Company, DeGolyer and MacNaughton and Fairchild & Wells, Inc.,
Independent Petroleum Engineers. For further information concerning Ryder
Scott's, DeGolyer and MacNaughton's and Fairchild's estimate of our proved
reserves at December 31, 2004, 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.
10
PROVED RESERVES
----------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- --------
(DOLLARS IN THOUSANDS)
Oil and condensate (MBbls) 1,459 7,658 9,117
Natural gas (MMcf) 28,066 26,555 54,621
Total proved reserves (MMcfe) 36,823 72,505 109,328
PV-10 Value(1)(2) $116,413 $92,197 $208,610
- ----------
(1) The PV-10 Value as of December 31, 2004 is pre-tax and was determined by
using the December 31, 2004 sales prices, which averaged $41.18 per Bbl of
oil, $5.68 per Mcf of natural gas. This measure is common in our industry
and is a market indicator of performance.
(2) Future income taxes and present value discounted (10%) future income taxes
were $108.3 and $58.9 million, respectively. Accordingly, the after-tax
PV-10 Value of Total Proved Reserves (or "Standardized Measure of
Discounted Future Net Cash Flows") is $149.7 million.
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."
OIL AND NATURAL GAS RESERVE REPLACEMENT
Finding and developing sufficient amounts of natural gas and crude oil
reserves at economical costs are critical to our long-term success. Given the
inherent decline of hydrocarbon reserves resulting from the production of those
reserves, it is important for an exploration and production company to
demonstrate a long-term trend of more than offsetting produced volumes with new
reserves that will provide for future production. Management uses the reserve
replacement ratio, as defined below, as an indicator of our ability to replenish
annual production volumes and grow our reserves, thereby providing some
information on the sources of future production. We believe reserve replacement
information is frequently used by analysts, investors and others in the industry
to evaluate the performance of companies like ours. The reserve replacement
ratio is calculated by dividing the sum of reserve additions from all sources
(revisions, extensions, discoveries, and other additions and acquisitions) by
the actual production for the corresponding period. The values for these reserve
additions are derived directly from the proved reserves table above. We do not
use unproved reserve quantities in calculating our reserve replacement ratio. It
should be noted that the reserve replacement ratio is a statistical indicator
that has limitations. As an annual measure, the ratio is limited because it
typically varies widely based on the extent and timing of new discoveries and
property acquisitions. Its predictive and comparative value is also limited for
the same reasons. In addition, since the ratio does not take into consideration
the cost of timing of future production of new reserves, it cannot be used as a
measure of value creation. The ratio does not distinguish between changes in
reserve quantities that are producing and those that will require additional
time and funding to begin producing In that regard, it might be noted that
percentage of reserves that were producing varied from 13.6% in 2002, to 11.2%
in 2003 to 17.2% in 2004. Set forth below is our reserve replacement ratio for
the year ended December 31, 2004, 2003 and 2002.
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2002 2003 2004
---- ---- ----
Reserve Replacement Ratio 163% 203% 568%
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.
YEAR ENDED DECEMBER 31,
------------------------
2002 2003 2004
------ ------ ------
Production volumes
Oil (MBbls) 401 450 309
Natural gas (MMcf) 4,801 4,763 6,462
Natural gas equivalent (MMcfe) 7,207 7,463 8,319
Average sales prices
Oil (per Bbl) $24.94 $28.90 $38.78
Natural gas (per Mcf) 3.50 5.35 6.07
Natural gas equivalent (per Mcfe) 3.72 5.16 6.18
Average costs (per Mcfe)
Camp Hill operating expenses $ 2.50 $ 3.45 $ 3.31
Other operating expenses 0.44 0.58 0.59
Total operating expenses(1) 0.68 0.90 1.01
- ----------
(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 $3.1 million, $2.9 million and $2.9 million for the years ended
December 31, 2002, 2003 and 2004, respectively. We have also included
capitalized overhead in our finding cost of $1.0 million, $1.4 million and $1.7
million for the years ended December 31, 2002, 2003 and 2004, respectively. We
have also included non-cash asset retirement obligations of $0.7 and $0.5
million for the years ended December 31, 2003 and 2004, respectively.
12
YEAR ENDED DECEMBER 31,
---------------------------
2002 2003 2004
------- ------- -------
(IN THOUSANDS)
Acquisition costs:
Unproved properties contributed to Pinnacle $ 1,323 $ -- $ --
Other unproved properties 5,079 7,280 21,831
Proved properties 660 -- 8,357
Exploration 14,194 23,745 39,181
Development 2,351 112 12,697
Asset retirement obligation -- 744 529
------- ------- -------
Total costs incurred $23,607 $31,881 $82,595
======= ======= =======
Less unproved properties contributed to Pinnacle 1,323 -- --
------- ------- -------
Adjusted costs $22,284 $31,881 $82,595
======= ======= =======
Total proved reserves added 11,761 15,138 47,294
------- ------- -------
Average all-sources finding cost (per Mcfe) (1) $ 1.89 $ 2.11 $ 1.75
======= ======= =======
- ----------
(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, 2004, our total adjusted costs
for development, exploration and acquisition activities was approximately $136.8
million. Total exploration, development and acquisition activities for the three
year period ended December 31, 2004 have added approximately 74.2 Bcfe of net
proved reserves at an all-sources finding cost of $1.84 per Mcfe.
Our finding and development cost computation excludes net
additions/reductions to total future development costs with respect to proved
undeveloped properties necessary to convert those properties into proved
developed properties of ($0.8), $0.7 and $39.8 million at December 31, 2002,
2003 and 2004, respectively, and includes total additions to proved undeveloped
reserves of 3.7, 2.9 and 27.6 Bcfe for the years ended December 31, 2002, 2003
and 2004, respectively. Accordingly, had we included future development costs in
our computations, the average all-sources finding costs would have been $1.82,
$2.15 and $2.59 for the years ended December 31, 2002, 2003 and 2004,
respectively.
Our all-source finding cost measure is a measure with limitations.
Consistent with industry practice, our finding and development costs have
historically fluctuated on a year-to-year basis based on a number of factors
including the extent and timing of new discoveries and property acquisitions.
Due to the timing of proved reserve additions and timing of the related costs
incurred to find and develop our reserves, our all-sources finding cost measure
often includes quantities of reserves for which a majority of the costs of
development have not yet been incurred. Conversely, the measure also often
includes costs to develop proved reserves that had been added in earlier years.
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. Our all-sources finding costs may also be calculated differently than
the comparable measure for other oil and gas companies.
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.
13
YEAR ENDED DECEMBER 31,
---------------------------
2002 2003 2004
------- ------- -------
(IN THOUSANDS)
Acquisition costs
Unproved prospects $ 6,402 $ 7,280 $21,831
Proved properties 660 -- 8,357
Exploration 14,194 23,745 39,181
Development 2,351 112 12,697
Asset retirement obligation -- 744 529
------- ------- -------
Total costs incurred(1) $23,607 $31,881 $82,595
======= ======= =======
- ----------
(1) Excludes capitalized interest on unproved properties of $3.1 million, $2.9
million and $2.9 million for the years ended December 31, 2002, 2003, and
2004, respectively, and includes capitalized overhead of $1.0 million, $1.4
million and $1.7 million for the years ended December 31, 2002, 2003 and
2004 respectively. The table also includes non-cash asset retirement
obligations of $0.7 and $0.5 million, respectively, for the year ended
December 31, 2003 and 2004, respectively.
DRILLING ACTIVITY
The following table sets forth our drilling activity for the years ended
December 31, 2002, 2003 and 2004. 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, 2004 has resulted in a commercial success rate of
approximately 73%.
YEAR ENDED DECEMBER 31,
------------------------------------------
2002 2003 2004
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
Exploratory Wells
Productive 16 5.6 33 9.2 39 14.9
Nonproductive 3 1.1 5 0.8 6 3.7
--- --- --- ---- --- ----
Total 19 6.7 38 10.0 45 18.6
=== === === ==== === ====
Development Wells
Productive 1 0.4 1 0.2 26 8.7
Nonproductive -- -- -- -- -- --
--- --- --- ---- --- ----
Total 1 0.4 1 0.2 26 8.7
=== === === ==== === ====
At December 31, 2003 and 2004, we had ownership in 12 and 11 gross (3.2 and
2.7 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 table
also excludes 12 gross (2.3 net) wells drilled by CCBM during 2004. The wells
contributed to Pinnacle are in various stages of development and/or stages of
production. See "Wyoming/Montana Coalbed Methane Project Area" above.
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, 2004. This table excludes
all wells drilled or acquired by CCBM through 2003, a majority of which were
contributed to Pinnacle in that year.
14
COMPANY
OPERATED OTHER TOTAL
------------ ------------ -------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- -----
Oil 53 36.6 10 3.7 63 40.3
Natural gas 39 19.8 143 42.3 182 62.1
--- ---- --- ---- --- -----
Total 92 56.4 153 46.0 245 102.4
=== ==== === ==== === =====
ACREAGE DATA
The following table sets forth certain information regarding our developed
and undeveloped lease acreage as of December 31, 2004. Developed acres refers to
acreage on which wells have been drilled or completed to a point that would
permit production of oil and gas in commercial quantities. Undeveloped acreage
refers to acreage on which wells have not been drilled or completed to a point
that would permit production of oil and gas in commercial quantities whether or
not the acreage contains proved reserves.
DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL
----------------- ------------------- -----------------
GROSS NET GROSS NET GROSS NET
------ ------ ------- ------- ------- -------
North Sea -- -- 209,613 209,613 209,613 209,613
Louisiana 3,027 986 4,845 3,766 7,872 4,752
Texas 36,656 12,674 112,881 51,489 149,537 64,163
Montana/Wyoming -- -- 138,705 10,763 138,705 10,763
Other -- -- 7,618 1,143 7,618 1,143
------ ------ ------- ------- ------- -------
Total 39,683 13,660 473,662 276,774 513,345 290,434
====== ====== ======= ======= ======= =======
The table does not include 32,809 gross and 17,002 net acres under lease
option that we had a right to acquire in Texas, pursuant to various seismic and
lease option agreements at December 31, 2004. 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 23,784 gross and 5,946 net acres under lease option 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 area and the Barnett
Shale area. 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.
15
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.
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;
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- 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 (including Louisiana) allow the forced pooling or
integration of tracts to facilitate exploration while other states (including
Texas) rely primarily or exclusively on voluntary pooling of lands and leases.
In areas where pooling is primarily or exclusively 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 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
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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. The next review
is scheduled in July 2005. Another FERC proceeding, that may impact oil pipeline
transportation costs, relates to an ongoing proceeding to determine whether and
to what extent oil pipelines should be permitted to include in their
transportation rates an allowance for income taxes attributable to non-corporate
partnership interests. 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.
We generate waste 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 waste. Furthermore,
certain waste generated by our natural gas and oil operations that are currently
exempt from treatment as "hazardous waste" may in the future be designated as
"hazardous waste" 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 waste may have been disposed of or
released on or under the properties we own or lease or on or under locations
where such waste 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 waste was not under our control. These
properties and the waste 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 waste. Under these laws, we could be required to remove or remediate
previously disposed waste (including waste 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.
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Our operations may be subject to the Clean Air Act ("CAA") and comparable
state and local requirements. In 1990 Congress adopted amendments to the CAA
containing provisions that have resulted in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. The EPA and states have developed and continue to develop
regulations to implement these requirements. We may be required to incur certain
capital expenditures in the next several years for air pollution control
equipment in connection with maintaining or obtaining operating permits and
approvals addressing other air emission-related issues. However, we do not
believe our operations will be materially adversely affected by any such
requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as us, to prepare and implement spill
prevention, control, countermeasure ("SPCC") and response plans relating to the
possible discharge of oil into surface waters. 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 methane drilling
permits and the continued viability of existing permits in Montana have been
challenged in lawsuits filed in state and federal court.
Coalbed Methane Proceedings in Montana
The issuance of new coalbed methane drilling permits in Montana was halted
temporarily pending the Federal Bureau of Land Management's ("BLM") 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. Environmental
groups initiated six lawsuits, challenging these program approvals. On February
22, 2005, the Federal District Court for the District of Montana issued an
opinion in Northern Plains Resource Council v. BLM and a companion case vacating
BLM's approval of the state plan and remanding the plan to BLM for further
consideration. The Court left open the issue of what, if any, injunctive relief
should be granted in light of this ruling. Although this decision could result
in a suspension of the state's authority to issue new drilling permits or could
effect the continued viability of existing permits in Montana, we believe that
the decisions by the Federal Bureau of Land Management and the State of Montana
ultimately will be upheld on appeal and/or BLM's reconsideration will address
the Court's concerns and new coalbed methane development will continue to be
authorized in Montana. There can be no assurance that any new permits will be
obtained in a given time period or at all.
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.
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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, 2004 to Cokinos
Natural Gas Company (17%), Texon L.P. (13%) and WMJ Investments Corp. (12%); for
the year ended December 31, 2003 to WMJ Investments Corp. (16%), Cokinos Natural
Gas Company (15%) and Gulfmark Energy, Inc. (14%); and for the year ended
December 31, 2002 to Cokinos Natural Gas Company (12%) and Discovery Producer
Services, LLC (10%). Because alternate purchasers of oil and natural gas are
readily available, 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, 2004, 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, 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
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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%. At the end of 2004, we retained our interests in
approximately 139,000 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. During 2004, we opted to exercise our right to cancel one-half of a
remaining note payable to RMG, or approximately $300,000 in exchange for
assigning one-half of our interest in the Oyster Ridge project area to RMG.
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. Our Chairman, Steven A. Webster, is also
Chairman of Global Energy Partners, Ltd., an affiliate of CSFB.
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 15% 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. 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. At the end of
2004 Pinnacle's production was approximately 13 MMcfe/d gross (5.6 MMcfe/d net).
In June 2004, Pinnacle fulfilled, $14.5 million funding commitment for 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, 2004, Pinnacle owned interests in approximately 170,000 gross
acres (79,000 net) in the Powder River Basin.
Historically, the business operations and development program of Pinnacle
has not required us to provide any further capital infusion. In March 2005,
Pinnacle acquired additional undeveloped acreage with an undisclosed company
which would also significantly increase Pinnacle's development program budget in
2005. Accordingly, CCBM and the other Pinnacle shareholders have the option to
participate in the equity contribution into Pinnacle needed to finance the
acquisition and the related development program in 2005. Should we elect to
maintain our proportionate ownership interest in Pinnacle, we estimate that we
would be required to contribute $2.5 million. If CCBM opts not to contribute any
or all of its share of the equity contribution, its fully diluted ownership in
Pinnacle would be reduced. CCBM plans to contribute $2.5 million in April 2005,
its share of the equity capital needed to close the acquisition and fund part of
the additional development program. There can be no assurance regarding CCBM's
level of participation in future equity contributions needed, if any. On March
29, 2005, we elected to participate and contribute $2.5 million to Pinnacle in
exchange for warrants and preferred stock.
AVAILABLE INFORMATION
Our website address is www.carrizo.cc. We make our website content
available for informational purposes only. It should not be relied upon for
investment purposes, nor is it incorporated by reference in this Form 10-K. We
make available on this website, through a direct link to Securities and Exchange
Commission's website at www.sec.gov, free of charge, our annual reports on Form
10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments
to those reports as soon as reasonably practicable after we electronically file
those materials.
You may also find information related to our corporate governance, board
committees and company code of ethics at our website. Among the information you
can find there is the following:
- Audit Committee Charter;
- Compensation Committee Charter;
- Nominating Committee Charter;
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- Code of Ethics and Business Conduct; and
- Compliance Employee Report Line.
We intend to satisfy the requirement under Item 5.05 of Form 8-K to
disclose any amendments to our Code of Ethics and any waiver from a provision of
our Code of Ethics by posting such information in our Corporate Governance
section of our website at www.carrizo.cc.
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.
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.
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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 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
23
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.
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.
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..... 49 President, Chief Executive Officer and Director
Paul F. Boling...... 51 Chief Financial Officer, Vice President, Secretary
and Treasurer
24
Gregory E. Evans.... 55 Vice President of Exploration
J. Bradley Fisher... 44 Vice President and Chief Operating Officer(1)
Kendall A. Trahan... 54 Vice President of Land
- -----------------
(1) Mr. Fisher became our Chief Operating Officer on March 29, 2005.
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 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.
Gregory E. Evans has served as Vice President of Exploration since March
2005. Prior to joining us, Mr. Evans was Vice President North America Onshore
Exploration for Ocean Energy from 2001 to 2003. Prior to that time, he spent
19 years at Burlington Resources where he served as Chief Geophysicist North
America during 1999 to 2000, Gulf of Mexico Deep Water Exploration Manager
during 1998 to 1999 and Geoscience Manager for the Western Gulf of Mexico Shelf
during 1996 to 1998. Between 1982 to 1996, Mr. Evans held various other
technical and managerial positions with Burlington Resources, including Division
Exploration Manager of both the Rocky Mountain Region as well as the Gulf Coast
area. Mr. Evans received a B. S. in Geophysical Engineering from the Colorado
School of Mines receiving the Cecil H. Green award for outstanding geophysical
student.
J. Bradley Fisher has served as Vice President and Chief Operating Officer
since March 2005. Prior to that time, he 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.
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.
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, trades on the Nasdaq National
Market 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
------ -----
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
2004:
25
First Quarter .............................................. 8.10 6.55
Second Quarter ............................................. 10.75 7.28
Third Quarter .............................................. 10.57 7.80
Fourth Quarter ............................................. 11.57 9.20
The closing market price of our common stock on March 1, 2005 was 14.92 per
share. As of March 1, 2005, there were an estimated 36 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
facility and the terms of our senior subordinated notes and senior subordinated
secured notes restrict our ability to pay dividends. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
On March 22, 2005, Steven A. Webster exercised in full his warrant (the
"Warrant") to purchase 84,211 shares of our common stock at a price of $5.94
per share. As a result of the cashless exercise of the Warrant, Mr. Webster
received 54,669 shares of common stock upon exercise. The Warrant was initially
issued by the Company in February 2002. In issuing the shares of common stock
underlying the Warrant, the Company relied on the exemption from registration
provided by Section 4(2) of the Securities Act of 1933, as amended, for
transactions not involving a public offering.
ITEM 6. SELECTED FINANCIAL DATA
Our financial information set forth below for each of the five years ended
December 31, 2004, has been derived from our audited consolidated financial
statements. The information should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
our consolidated financial statements and related notes included in Item 8.
Financial Statements and Supplementary Data.
26
Year Ended December 31,
----------------------------------------------------
2000 2001 2002 2003 2004
-------- -------- -------- -------- --------
(In thousands, except per share data)
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenues $ 26,834 $ 26,226 $ 26,802 $ 38,508 $ 51,374
Costs and expenses:
Oil and natural gas operating expenses 4,941 4,138 4,908 6,724 8,392
Depreciation, depletion and amortization 7,170 6,492 10,574 11,868 15,464
General and administrative 3,143 3,333 4,133 5,639 7,191
Accretion expense related to asset retirement -- -- -- 41 23
Stock option compensation expense (income) 652 (558) (84) 313 1,064
-------- -------- -------- -------- --------
Total costs and expenses 15,906 13,405 19,531 24,585 32,134
-------- -------- -------- -------- --------
Operating income 10,928 12,821 7,271 13,923 19,240
Equity in loss of Pinnacle Gas Resources, Inc. -- -- -- (830) (1,399)
Interest expense (income), net of amounts
capitalized and interest income 579 269 54 (19) (622)
Other income and expenses, net 1,482 1,777 274 29 506
-------- -------- -------- -------- --------
Income before income taxes 12,989 14,867 7,599 13,103 17,725
Income tax expense (benefit) 1,004 5,336 2,809 5,063 6,871
-------- -------- -------- -------- --------
Income before cumulative effect of change
in accounting principle 11,985 9,531 4,790 8,040 10,854
Dividends and accretion of discount on preferred stock -- -- 588 741 350
-------- -------- -------- -------- --------
Income available to common shareholders
before cumulative effect of change
in accounting principle 11,985 9,531 4,202 7,299 10,504
Cumulative effect of change in accounting principle -- -- -- (128) --
-------- -------- -------- -------- --------
Net income available to common shareholders $ 11,985 $ 9,531 $ 4,202 $ 7,171 $ 10,504
======== ======== ======== ======== ========
Basic earnings per common share $ 0.85 $ 0.68 $ 0.30 $ 0.50 $ 0.53
======== ======== ======== ======== ========
Diluted earnings per common share $ 0.74 $ 0.57 $ 0.26 $ 0.43 $ 0.48
======== ======== ======== ======== ========
Basic weighted average shares outstanding 14,028 14,059 14,158 14,312 19,958
Diluted weighted average shares outstanding 16,256 16,731 16,148 16,744 21,818
STATEMENTS OF CASH FLOW DATA:
Net cash provided by operating activities $ 15,906 $ 22,669 $ 18,572 $ 33,631 $ 32,501
Net cash used in investing activities (15,211) (29,942) (22,747) (29,673) (80,295)
Net cash provided by (used in) financing activities (3,823) 2,292 5,682 (5,379) 50,140
OTHER OPERATING DATA:
Capital expenditures $ 19,746 $ 38,264 $ 23,343 $ 31,930 $ 83,892
Debt repayments (1) 3,923 5,479 8,745 5,951 13,737
27
AS OF DECEMBER 31,
---------------------------------------------------
2000 2001 2002 2003 2004
------- -------- -------- -------- --------
BALANCE SHEET DATA:
Working capital (deficit) $ 6,433 $ (582) $ (1,442) $(11,817) $ (9,138)
Property and equipment, net 72,129 104,132 120,526 135,273 205,482
Total assets 93,000 117,392 135,388 156,803 234,035
Long-term debt, including current
maturities 34,556 38,188 39,495 36,253 62,974
Convertible participating preferred stock -- -- 6,373 7,114 --
Total equity 52,939 63,204 66,816 76,072 120,859
- ----------
(1) Debt repayments include amounts refinanced.
Forward Looking Statements. The statements contained in all parts of this
document, (including any portion attached hereto) including, but not limited to,
those relating to our schedule, targets, estimates or results of future
drilling, including the number, timing and results of wells, budgeted wells,
increases in wells, the timing and risk involved in drilling follow-up wells,
expected working or net revenue interests, planned expenditures, prospects
budgeted and other future capital expenditures, risk profile of oil and gas
exploration, acquisition of 3-D seismic data (including number, timing and size
of projects), planned evaluation of prospects, probability of prospects having
oil and natural gas, expected production or reserves, increases in reserves,
acreage, working capital requirements, hedging activities, the ability of
expected sources of liquidity to implement our business strategy, future hiring,
future exploration activity, production rates, potential drilling locations
targeting coal seams, the outcome of legal challenges to new coalbed methane
drilling permits in Montana, financing for our 2005 exploration and development
program, all and any other statements regarding future operations, financial
results, business plans and cash needs and other statements that are not
historical facts are forward looking statements. When used in this document, the
words "anticipate," "budgeted," "planned," "targeted," "potential," "estimate,"
"expect," "may," "project," "believe" and similar expressions are intended to be
among the statements that identify forward looking statements. Such statements
involve risks and uncertainties, including, but not limited to, those relating
to our dependence on our exploratory drilling activities, the volatility of oil
and natural gas prices, the need to replace reserves depleted by production,
operating risks of oil and natural gas operations, our dependence on our key
personnel, factors that affect our ability to manage our growth and achieve our
business strategy, risks relating to our limited operating history,
technological changes, our significant capital requirements, the potential
impact of government regulations, adverse regulatory determinations, including
those related to coalbed methane drilling in Montana, litigation, competition,
the uncertainty of reserve information and future net revenue estimates,
property acquisition risks, industry partner issues, availability of equipment,
weather and other factors detailed herein and in our other filings with the
Securities and Exchange Commission. Some of the factors that could cause actual
results to differ from those expressed or implied in forward-looking statements
are described under "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Risk Factors" and in other sections of this report.
Should one or more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual outcomes may vary materially from
those indicated. All subsequent written and oral forward-looking statements
attributable to us or persons acting on our behalf are expressly qualified in
their entirety by reference to these risks and uncertainties. You should not
place undue reliance on forward-looking statements. Each forward-looking
statement speaks only as of the date of the particular statement and we
undertake no duty to update any forward looking statement.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
You should read this discussion together with the consolidated financial
statements and other financial information included in this Form 10-K.
GENERAL OVERVIEW
For the year ended December 31, 2004, we achieved record annual drilling
success rates, levels of production, natural gas and oil revenues and our proved
oil and gas reserves at the end of 2004 also reached a record level.
Due to our drilling success, we produced a record 8.3 Bcfe in 2004 compared
to 7.5 Bcfe in 2003. At the end of 2004, we also reached a record estimated
proved reserves level of 109.3 Bcfe with 47.3 Bcfe of net additions for the
year, replacing 568% of our 2004 production. See "Business and Properties -
Natural Gas and Oil Reserve Replacement."
28
In 2004, we drilled 71 wells (27.3 net), including 38 wells in the onshore
Gulf Coast area and 33 wells in the Barnett Shale play, with a success rate of
92% compared to a success rate of 90% in 2003, in which we drilled 39 wells
(10.2 net), in the onshore Gulf Coast and Barnett Shale areas combined. Between
January 1, 2002 and December 31, 2004, 78% of our wells drilled were exploratory
and 22% were developmental. In 2004, 63% of these wells were exploratory and 37%
were developmental. This increase in our percentage of developmental wells
reflects our increased activity in the Barnett Shale area, which has a
relatively higher concentration of development well targets than the onshore
Gulf Coast area.
In 2004, our natural gas and oil revenues reached a record level at $51.4
million, and our net income available to common shareholders was $10.5 million,
or $0.53 and $0.48 per basic and fully diluted share, respectively. In 2003, our
natural gas and oil revenues were $38.5 million, and our net income available to
common shareholders was $7.2 million, or $0.50 and $0.43 per basic and fully
diluted share, respectively. These increases in natural gas and oil revenues and
net income were attributable in part to the record levels of production
discussed above and to higher commodity prices.
Our financial results are largely dependent on a number of factors,
including commodity prices. Commodity prices are outside of our control and
historically have been and are expected to remain volatile. Natural gas prices
in particular have remained volatile during the last few years. Commodity prices
are affected by changes in market demands, overall economic activity, weather,
pipeline capacity constraints, inventory storage levels, basis differentials and
other factors. As a result, we cannot accurately predict future natural gas,
natural gas liquids and crude oil prices, and therefore, cannot accurately
predict revenues. In 2004, including the effects of hedging activities, our
realized natural gas price was 14% higher and our realized oil price was 34%
higher in 2004 than in 2003.
Because natural gas and oil prices are unstable, we periodically enter into
price-risk-management transactions such as swaps, collars, futures and options
to reduce our exposure to price fluctuations associated with a portion of our
natural gas and oil production and to achieve a more predictable cash flow. The
use of these arrangements limits our ability to benefit from potential increases
in the prices of natural gas and oil. Our hedging arrangements may apply to only
a portion of our production and provide only partial protection against declines
in natural gas and oil prices.
We have continued to reinvest a substantial portion of our operating cash
flows into funding our drilling program and increasing the amount of 3-D seismic
data available to us. In 2005, we expect capital expenditures to be
approximately $85 to $90 million, as compared to $82.6 million in 2004.
At December 31, 2004, our debt-to-total book capitalization ratio was
34.3%, an increase from the 30.4% ratio at the end of 2003. This increase was
primarily the result of: (1) an increase of $11 million in the amount borrowed
under our revolving credit facility, (2) the issuance of the 10% Senior
Subordinated Secured Notes and (3) a $1.6 million net increase related to the 9%
Senior Subordinated Notes; partially offset by increases in shareholders' equity
from (1) the $23.3 million of net proceeds from the public offering in February
2004 and (2) the $7.5 million preferred stock conversion to common stock in the
second quarter 2004. The debt changes are described under "--Liquidity and
Capital Resources--Financing Arrangements."
Since our initial public offering, we have grown primarily through the
exploration of properties within our project areas although we consider
acquisitions from time to time and may in the future complete acquisitions that
we find attractive.
2004 Public Offering
In the first quarter of 2004, we completed the public offering of 6,485,000
shares of our common stock at $7.00 per share. The offering included 3,655,500
newly issued shares offered by us and 2,829,500 shares offered by certain
existing stockholders. Our net proceeds of approximately $23.3 million from this
offering were used: (1) to accelerate our drilling program, (2) to retain larger
interests in portions of our drilling prospects that we otherwise would sell
down (or for which we would seek joint partners), (3) to fund a portion of our
activities in the Barnett Shale area and (4) for general corporate purposes. We
did not receive any proceeds from the shares sold by the selling stockholders.
Barnett Shale Area
In mid-2003, we became active in the Barnett Shale play located in Tarrant
and Parker counties in Northeast Texas. Our activity accelerated as a result of
the acquisition on February 27, 2004 of working interests and acreage in certain
oil and gas wells located in the Newark East Field in Denton County, Texas in
the Barnett Shale trend for $8.2 million (the "Barnett Shale Acquisition"). This
acquisition included non-operated working interests in properties ranging from
12.5% to 45% over 3,800 gross acres, or an average working interest of 39%. The
acquisition included 21 existing gross wells (6.7 net) and interests in
approximately
29
1,500 net acres, which we expect will provide another 31 gross drill sites: five
of which were drilled in 2004, 21 of which will target proved undeveloped
reserves and five of which will be exploratory.
Initially, we financed our Barnett Shale activities with our available cash
on hand. Subsequently, we have financed a portion of our 2004 capital
expenditure program for the Barnett Shale area with funds from the October 2004
issuance of the 10% Senior Subordinated Secured Notes. We are exploring a number
of financing alternatives which may be used to partially fund our 2005 capital
expenditure program for the Barnett Shale area. We may not be able to obtain
such financing on terms that acceptable to us, or at all.
In the Barnett Shale area, we drilled six gross wells (2.1 net) in 2003 and
33 gross wells (13.7 net) in 2004, all of which were successful. We plan to
drill 37 gross wells (24.0 net) in this area in 2005, subject to obtaining
additional financing to supplement our Credit Facility, additional Senior
Secured Note financing available and achieving expected operating cash flows. At
the end of 2004 our net production had risen to approximately 2.8 MMcfe/d with
38 gross wells on line and another 22 gross wells in various stages of testing,
completion and awaiting pipeline hookup. At the end of February 2005 our
estimated net production was 3.5 MMcfe/d.
In addition to our drilling activity, we have continued to expand our
Barnett Shale acreage position, growing our net leasehold acreage from
approximately 4,100 to 30,700 to 35,000 acres, at the end of 2003, 2004 and
February 2005, respectively. Similarly, we have increased our estimated number
of developmental locations from four to 40 to 41 horizontal locations, at the
end of 2003, 2004 and February 2005, respectively and we have increased our
estimated number of exploratory drilling locations (horizontal) in the Barnett
Shale area from 21 to 152 to 179 locations, at the end of 2003, 2004 and
February 2005, respectively.
Pinnacle Gas Resources, Inc.
During the second quarter of 2001, we acquired interests in natural gas and
oil leases in Wyoming and Montana in areas prospective for coalbed methane and
subsequently began to drill wells on those leases. During the second quarter of
2003, we contributed our interests in certain of these leases to a newly formed
company, Pinnacle Gas Resources, Inc. ("Pinnacle"). In exchange for this
contribution, we received 37.5% of the common stock of Pinnacle and options to
purchase additional Pinnacle common stock. We account for our interest in
Pinnacle using the equity method. As a result, our contributed operations and
reserves are no longer directly reflected in our financial statements. In March
2004, Credit Suisse First Boston Private Equity Entities (the "CSFB Parties")
contributed additional funds of $11.8 million into Pinnacle to fund its 2004
development program, which increased the CSFB Parties' ownership to 66.7% on a
fully diluted basis assuming we and RMG each elect not to exercise our available
options.
In March 2005, Pinnacle entered into a purchase and sale agreement to
acquire additional undeveloped acreage, which would also significantly increase
its development program budget in 2005. CCBM and the other Pinnacle shareholders
have the option to participate in the equity contribution into Pinnacle needed
to finance this acquisition and its development program in 2005. Should we elect
to maintain our proportionate ownership interest in Pinnacle, we estimate that
we would be required to contribute $2.5 million. If CCBM opts not to
participate, its fully diluted ownership in Pinnacle would be reduced. CCBM
currently plans to purchase additional Pinnacle capital stock valued at $2.5
million in March 2005, its share of the first installment of the equity capital
needed to fund the acquisition and part of the additional development program.
There can be no assurance regarding CCBM's level of participation in future
equity contributions, if any.
In addition to our interest in Pinnacle, we have maintained interests in
approximately 162,489 gross acres at the end of 2004 in the Castle Rock coalbed
methane project area in Montana and the Oyster Ridge project area in Wyoming.
During 2004, we opted to exercise our right to cancel one-half of the remaining
note payable to RMG, or approximately $300,000, in exchange for assigning
one-half of our mineral interest in the Oyster Ridge leases to RMG, leaving CCBM
with a 25% working interest in this project area. See "Business and
Properties--Pinnacle Transaction" for a description of this transaction. Our
discussion of future drilling and capital expenditures does not reflect
operations conducted through Pinnacle.
Hedging
Our financial results are largely dependent on a number of factors,
including commodity prices. Commodity prices are outside of our control and
historically have been and are expected to remain volatile. Natural gas prices
in particular have remained volatile during the last few years and more recently
oil prices have become volatile. Commodity prices are affected by changes in
market demands, overall economic activity, weather, pipeline capacity
constraints, inventory storage levels, basis differentials and other factors. As
a result, we cannot accurately predict future natural gas, natural gas liquids
and crude oil prices, and therefore, cannot
30
accurately predict revenues.
Because natural gas and oil prices are unstable, we periodically enter into
price-risk-management transactions such as swaps, collars, futures and options
to reduce our exposure to price fluctuations associated with a portion of our
natural gas and oil production and to achieve a more predictable cash flow. The
use of these arrangements limits our ability to benefit from increases in the
prices of natural gas and oil. Our hedging arrangements may apply to only a
portion of our production and provide only partial protection against declines
in natural gas and oil prices.
RESULTS OF OPERATIONS
Year Ended December 31, 2004 Compared to the Year Ended December 31, 2003
Oil and natural gas revenues for 2004 increased 33% to $51.4 million from
$38.5 million in 2003. Production volumes for natural gas in 2004 increased 36%
to 6,462 MMcf from 4,763 MMcf in 2003. Realized average natural gas prices
increased 14% to $6.09 per Mcf in 2004 from $5.35 per Mcf in 2003. Production
volumes for oil in 2004 decreased 31% to 309 MBbls from 450 MBbls in 2003. The
increase in natural gas production was primarily due to the commencement of
production from the Beach House #1 and #2, the Peal Ranch wells, the Barnett
Shale wells, the Shadyside #1 (which we later sold in February 2005), the new
Encinitas wells and the LL&E #1, partially offset by the natural decline in
production from the Hankamer #1, Espree #1, Staubach #1, Burkhart #1R, Pauline
Huebner A-382 #1, Matthes Huebner #1, Pitchfork Ranch #1 and other wells. The
decrease in oil production was due primarily to the natural decline of
production at the Staubach #1, Burkhart #1R, Pauline Huebner A-382 #1, Beach
House #1, Matthes Huebner #1, Hankamer #1 and Espree #1, partially offset by the
commencement of production from the Delta Farms #1 workover, LL&E #1 and other
wells. Oil and natural gas revenues include the impact of hedging activities as
discussed below under "Volatility of Oil and Gas Prices."
Average oil prices increased 34% to $38.78 per Bbl in 2004 from $28.90 per
Bbl in 2003.
The following table summarizes production volumes, average sales prices and
operating revenues for our oil and natural gas operations for the years ended
December 31, 2003 and 2004:
2004 PERIOD
COMPARED TO 2003 PERIOD
DECEMBER 31, -----------------------
----------------- INCREASE % INCREASE
2003 2004 (DECREASE) (DECREASE)
------- ------- ---------- ----------
Production volumes-
Oil and condensate (Mbbls) 450 309 (141) (31%)
Natural gas (MMcf) 4,763 6,462 1,699 36%
Average sales prices- (1)
Oil and condensate (per Bbl) $ 28.90 $ 38.78 $ 9.88 34%
Natural gas (per Mcf) 5.35 6.09 0.74 14%
Operating revenues (In thousands) -
Oil and condensate $13,014 $12,000 $(1,014) (8%)
Natural gas 25,494 39,374 13,880 54%
------- ------- -------
Total $38,508 $51,374 $12,866 33%
======= ======= =======
- ----------
(1) Including the impact of hedging.
Oil and natural gas operating expenses for 2004 increased 25% to $8.4
million from $6.7 million in 2003. Oil and natural gas operating expenses
increased primarily due to higher severance taxes of $0.7 million on higher
commodity prices, while higher lifting costs of $0.9 million were attributable
to the increased number of producing wells and in part due to higher ad valorem
taxes. Operating expenses per equivalent unit in 2004 increased to $1.01 per
Mcfe from $0.90 per Mcfe in 2003. The per unit cost increased primarily as a
result of the higher costs noted above.
Depreciation, depletion and amortization ("DD&A") expense for 2004
increased 30% to $15.4 million from $11.9 million in 2003. This increase was
primarily due to the increased land, seismic and drilling costs added to the
proved property cost base.
31
General and administrative ("G&A") expense for 2004 increased 28% to $7.2
million from $5.6 million for 2003. The increase in G&A was due primarily to
higher incentive compensation of $0.4 million, higher compensation costs of $0.2
million, higher professional fees of $0.7 million in connection with (1) the
2003 annual audit and Section 404 of the Sarbanes-Oxley Act compliance project
($0.5 million), and (2) discontinued refinancing projects ($0.2 million), and
due to an increase in the allowance for doubtful accounts of $0.3 million.
We recorded a $1.4 million after tax charge, or $0.06 per fully diluted
share, on our minority interest in Pinnacle. Of this charge, $0.3 million
relates to a valuation allowance for federal income taxes. It is likely that
Pinnacle will continue to record a valuation allowance on the deferred federal
tax benefit generated from the operating losses incurred during the early
development stages of Pinnacle's coalbed methane project. Concurrently, we will
record valuation allowances relative to our share of Pinnacle's financial
results.
Income taxes increased to $6.9 million in 2004 from $5.1 million in 2003
due to the increase in pre-tax income.
Dividends and accretion of discount on preferred stock decreased to $0.4
million in 2004 from $0.7 million in 2003 as a result of the conversion of all
of the Series B Preferred Stock into common stock during the second quarter of
2004.
Net Income available to common shareholders before cumulative effect of
change in accounting principle for 2004 increased to $10.5 million from $7.3
million in 2003 primarily as a result of the factors described above.
Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002
Oil and natural gas revenues for 2003 increased 44% to $38.5 million from
$26.8 million in 2002. Production volumes for natural gas in 2003 decreased 1%
to 4,763 MMcf from 4,801 MMcf in 2002. Realized average natural gas prices
increased 53% to $5.35 per Mcf in 2003 from $3.50 per Mcf in 2002. Production
volumes for oil in 2003 increased 12% to 450 MBbls from 401 MBbls in 2002. The
increase in oil production was due primarily to the commencement of production
at the Pauline Huebner A-382 #1, Beach House #1 Hankamer and Espree #1. Natural
gas production was virtually unchanged compared to 2002 or declined less than
1%. Oil and natural gas revenues include the impact of hedging activities as
discussed below under "Volatility of Oil and Gas Prices."
Average oil prices increased 16% to $28.90 per bbl in 2003 from $24.94 per
bbl in 2002.
The following table summarizes production volumes, average sales prices and
operating revenues for our oil and natural gas operations for the years ended
December 31, 2002 and 2003:
2003 PERIOD
COMPARED TO 2002 PERIOD
DECEMBER 31, -----------------------
----------------- INCREASE % INCREASE
2002 2003 (DECREASE) (DECREASE)
------- ------- ---------- ----------
Production volumes-
Oil and condensate (Mbbls) 401 450 49 12%
Natural gas (MMcf) 4,801 4,763 (38) (1%)
Average sales prices- (1)
Oil and condensate (per Bbl) $ 24.94 $ 28.90 $ 3.96 16%
Natural gas (per Mcf) 3.50 5.35 1.85 53%
Operating revenues (In thousands) -
Oil and condensate $10,001 $13,014 $ 3,013 30%
Natural gas 16,801 25,494 8,693 52%
------- ------- -------
Total $26,802 $38,508 $11,706 44%
======= ======= =======
- ----------
(1) Including the impact of hedging.
Oil and natural gas operating expenses for 2003 increased 37% to $6.7
million from $4.9 million in 2002. Oil and natural gas operating expenses
increased primarily due to higher severance taxes of $0.9 million on higher
commodity prices, higher lifting costs
32
of $0.9 million attributable to the increased number of producing wells and in
part due to higher ad valorem taxes. Operating expenses per equivalent unit in
2003 increased to $0.90 per Mcfe from $0.68 per Mcfe in 2002. The per unit cost
increased primarily as a result of the higher costs noted above.
Depreciation, depletion and amortization ("DD&A") expense for 2003
increased 12% to $11.9 million from $10.6 million in 2002. This increase was
primarily due to the increased land, seismic and drilling costs added to the
proved property cost base.
General and administrative ("G&A") expense for 2003 increased 36% to $5.6
million from $4.1 million for 2002. The increase in G&A was due primarily to
higher incentive compensation of $0.6 million, executive severance of $0.3
million, increased legal and professional fees attributable to special projects
and rising insurance costs of $0.1 million.
We recorded a $0.8 million aftertax charge, or $0.05 per fully diluted
share, on our minority interest in Pinnacle. Of this charge, $0.2 million, or
$0.01 per fully diluted share, relates to a valuation allowance for federal
income taxes. It is likely that Pinnacle will continue to record a valuation
allowance on the deferred federal tax benefit generated from the operating
losses incurred during the early development stages of Pinnacle's coalbed
methane project. Concurrently, we will record valuation allowances relative to
our share of Pinnacle's financial results.
Income taxes increased to $5.1 million in 2003 from $2.8 million in 2002
due to the increase in pre-tax income.
Dividends and accretion of discount on preferred stock increased to $0.7
million in 2003 from $0.6 million in 2002 as a result of the declaration of
dividends on preferred stock in 2003.
Net income available to common shareholders before cumulative effect of
change in accounting principle for 2003 increased to $7.3 million from $4.2
million in 2002 primarily as a result of the factors described above.
LIQUIDITY AND CAPITAL RESOURCES
During 2004, we made capital expenditures in excess of our net cash flows
provided by operating activities, using the proceeds generated from our 2004
public offering, as described in "--General Overview--2004 Public Offering," and
from our October 2004 sale of the 10% Senior Subordinated Secured Notes (the
"Senior Secured Notes") . For future capital expenditures in 2005, we expect to
use cash on hand and cash generated by operating activities, draws on the Credit
Facility and additional sales of Senior Secured Notes to partially fund our
planned drilling expenditures and fund leasehold costs and geological and
geophysical costs on our exploration projects in 2005. We also continue to
consider other financing alternatives to fund our 2005 capital expenditures
program, including possible debt or equity financings.
We may not be able to obtain adequate financing on terms that would be
acceptable to us. If we cannot obtain adequate financing, we anticipate that we
may be required to limit or defer our planned natural gas and oil exploration
and development program, thereby adversely affecting the recoverability and
ultimate value of our natural gas and oil properties.
Our liquidity position was enhanced by our receipt of approximately $23.3
million in net proceeds from the completion of the 2004 public offering, the
increase in availability of funds under the Credit Facility and the proceeds
from the October 2004 sale of the Senior Secured Notes. Our other primary
sources of liquidity have included funds generated by operations, proceeds from
the issuance of various securities, including our common stock, preferred stock
and warrants, and borrowings, primarily under revolving credit facilities and
through the issuance of Senior Subordinated Notes. We also recently increased
our liquidity through the sale of certain oil and gas properties for $9.0
million in the first quarter of 2005.
Cash flows provided by operating activities were $18.6 million, $33.4
million and $32.5 million for 2002, 2003 and 2004, respectively. This increase
in cash flows provided by operations in 2003 as compared to 2002 was due
primarily to higher commodity prices and higher trade payables in 2003. The
decrease in cash flows provided by operations in 2004 as compared to 2003 was
primarily due to a smaller increase in trade payables, partially offset by
higher operating income, generally due to record production and record commodity
prices realized in 2004.
Estimated maturities of long-term debt are $0.1 million in 2005, none in
2006, $18.0 million in 2007 and the remainder in 2008. The following table sets
forth estimates of our contractual obligations as of December 31, 2004:
33
PAYMENTS DUE BY YEAR
(IN THOUSANDS)
-----------------------------------------------
2006 TO 2008 TO
TOTAL 2005 2007 2009 THEREAFTER
------- ---- ------- ------- ----------
Long-Term Debt(1) $64,961 $ 90 $18,032 $46,839 $ --
Operating Leases 3,186 222 954 954 1,056
------- ---- ------- ------- ------
Total Contractual
Cash Obligations $68,147 $312 $18,986 $47,793 $1,056
======= ==== ======= ======= ======
- ----------
(1) Includes future accretion of discounts.
We have planned capital expenditures in 2005 of approximately $85 to $90
million, of which $70.0 million is expected to be used for drilling activities
in our project areas and the balance is expected to be used to fund 3-D seismic
surveys, land acquisitions and capitalized interest and overhead costs. We plan
to drill approximately 34 gross wells (14.4 net) in the onshore Gulf Coast area
and 37 gross wells 24.0 net in our Barnett Shale and nine gross well (7.7 net)
in our East Texas areas in 2005. As described above, we expect to seek
additional financing to fund a portion of our acquisition, exploration and
development program in 2005. If we are not successful in obtaining this
financing, our capital expenditures could be reduced by $15 to $20 million in
2005. The actual number of wells drilled and capital expended is dependent upon
available financing, cash flow, availability and cost of drilling rigs, land and
partner issues and other factors. The planned capital expenditures do not
include the additional contributions to Pinnacle as described under "-
General Overview - Pinnacle Gas Resources, Inc."
We have continued to reinvest a substantial portion of our cash flows into
increasing our 3-D prospect portfolio, improving our 3-D seismic interpretation
technology and funding our drilling program. Oil and gas capital expenditures
were $23.3 million, $31.9 million and $82.6 (including the Barnett Shale
Acquisition) for 2002, 2003 and 2004, respectively. Our drilling efforts
resulted in the successful completion of 17 gross wells (6.0 net) in 2002, 35
gross wells (9.4 net) in 2003, including six gross wells (2.1 net) in the
Barnett Shale area, and 65 gross wells (23.6 net) in 2004 including 33 gross
wells (13.7 net) in the Barnett Shale area . We also expect to make an
additional $2.5 million equity contribution to Pinnacle. See "-Overview-Pinnacle
Gas Resources, Inc."
Since its inception, CCBM has spent $5.0 million for drilling costs through
the end of 2004, 50% of which was applied pursuant to an obligation to fund $2.5
million of drilling costs on behalf of RMG. By December 31, 2004, CCBM had
satisfied all of its drilling obligations on behalf of RMG.
Through the end of 2004, Pinnacle has reported that it has drilled 241
gross wells since inception and estimates that 97% of these wells have been
completed. Pinnacle reportedly added approximately 16.2 Bcfe of net proved
reserves through development drilling through December 31, 2004, excluding the
10.6 Bcfe contributed or acquired at inception. Its gross operated production
has increased by approximately 170% since its inception (to approximately 13
MMcf/d at December 31, 2004), and its total well count stands at 485 gross
operated wells, according to Pinnacle. Because of the nature of coalbed methane
wells that require an extended dewatering period before significant natural gas
production, Pinnacle has not been able to complete its determination on
commerciality of all of these wells.
OFF BALANCE SHEET ARRANGEMENTS
We currently do not have any off balance sheet arrangements.
FINANCING ARRANGEMENTS
Credit Facility
On September 30, 2004, we entered into a Second Amended and Restated Credit
Agreement with Hibernia National Bank and Union Bank of California, N.A. (the
"Credit Facility"), maturing on September 30, 2007. The Credit Facility amended,
restated and extended our prior credit facility with Hibernia National Bank,
amended and restated on December 12, 2002 (such prior facility herein referred
to as the "Prior Credit Facility"). The Credit Facility provides for (1) a
revolving line of credit of up to the lesser of the Facility A Borrowing Base
and $75.0 million and (2) a term loan facility of up to the lesser of the
Facility B Borrowing Base and $25.0 million. It is secured by substantially all
of our assets and is guaranteed by our subsidiary.
The Facility A Borrowing Bases will be determined by the lenders at least
semi-annually on each November 1 and May 1. The Facility A Borrowing Base, under
the Credit Facility, on September 30, 2004 and December 31, 2004 was $28 million
and $30
34
million, respectively, of which $19.0 and $18.0 million, respectively, were
drawn and outstanding. The Facility A Borrowing Base, under the Prior Credit
Facility, on December 31, 2003 was $19.0 million, of which $7.0 million was
drawn and outstanding. We used proceeds from the public offering in February
2004 to repay the outstanding balance under the Prior Credit Facility.
We and the lenders may each request one unscheduled borrowing base
determination subsequent to each scheduled determination. The Facility A
Borrowing Base will at all times equal the Facility A Borrowing Base most
recently determined by the lenders, less quarterly borrowing base reductions
required subsequent to such determination. The lenders will reset the Facility A
Borrowing Base amount at each scheduled and each unscheduled borrowing base
determination date.
If the outstanding principal balance of the revolving loans under the
Credit Facility exceeds the Facility A Borrowing Base at any time (including,
without limitation, due to a quarterly borrowing base reduction (as described
above)), we have the option within 30 days to take any of the following actions,
either individually or in combination: make a lump sum payment curing the
deficiency, pledge additional collateral sufficient in the lenders' opinion to
increase the Facility A Borrowing Base and cure the deficiency or begin making
equal monthly principal payments that will cure the deficiency within the
ensuing six-month period. Those payments would be in addition to any payments
that may come due as a result of the quarterly borrowing base reductions.
Otherwise, any unpaid principal or interest will be due at maturity.
For each revolving loan, the interest rate will be, at our option, (1) the
Eurodollar Rate, plus an applicable margin equal to 2.375% if the amount
borrowed is greater than or equal to 90% of the Facility A Borrowing Base, 2.0%
if the amount borrowed is less than 90%, but greater than or equal to 50% of the
Facility A Borrowing Base, or 1.625% if the amount borrowed is less than 50% of
the Facility A Borrowing Base; or (2) the Base Rate, plus an applicable margin
of 0.375% if the amount borrowed is greater than or equal to 90% of the Facility
A Borrowing Base. The interest rate on each term loan will be, at our option,
(1) the Eurodollar Rate, plus an applicable margin to be determined by the
lenders; or (2) the Base Rate, plus an applicable margin to be determined by the
lenders. Interest on Eurodollar Loans is payable on either the last day of each
Eurodollar option period or monthly, whichever is earlier. Interest on Base Rate
Loans is payable monthly.
We are subject to certain covenants under the terms of the Credit Facility,
which were amended at the time of the issuance of the Senior Secured Notes.
These covenants, as amended, include, but are not limited to the maintenance of
the following financial covenants: (1) a minimum current ratio of 1.0 to 1.0
(including availability under the borrowing base), (2) a minimum quarterly debt
services coverage of 1.25 times, (3) a minimum shareholders' equity equal to
$100.0 million, plus 100% of all subsequent common and preferred equity
contributed by shareholders subsequent to June 30, 2004, plus 50% of all
positive earnings occurring subsequent to June 30, 2004, plus, 180 days after
issuance of any second-lien subordinated debt with another lender (the "Secured
Subordinated Debt"), an amount equal to the difference, if positive, of (A) 50%
of the net proceeds from the issuance less (B) 100% of all common and preferred
equity contributed by shareholders from September 30, 2004 to the date of the
issuance of any Secured Subordinated Debt, and (4) a maximum total recourse debt
to EBITDA ratio (as defined in the Credit Facility) of not more than 3.0 to 1.0.
The Credit Facility also places restrictions on additional indebtedness,
dividends to shareholders, liens, investments, mergers, acquisitions, asset
dispositions, asset pledges and mortgages, change of control, repurchase or
redemption for cash of our common stock, speculative commodity transactions and
other matters.
In connection with the Senior Secured Notes Purchase Agreement, we amended
the Credit Facility including without limitation, to: (1) amend the covenant
regarding maintenance of a minimum shareholders' equity, (2) add a new covenant
requiring maintenance of a minimum EBITDA to interest expense ratio and (3) add
other provisions and a consent which allow for the indebtedness incurred under
the Senior Secured Notes.
On November 7, 2004, we determined that, as of September 30, 2004, we were
not in compliance with the minimum current ratio covenant in the Credit
Facility. We cured the noncompliance on October 29, 2004 with the issuance of
the Senior Secured Notes. On November 10, 2004, the lenders under the Credit
Facility agreed in a letter to the Company to waive the noncompliance period
from September 30, 2004 through October 29, 2004.
At December 31, 2003 and 2004, no letters of credit were issued and
outstanding under the Prior Credit Facility and the Credit Facility,
respectively.
Rocky Mountain Gas Note
In June 2001, CCBM issued a non-recourse promissory note payable in the
amount of $7.5 million to RMG as consideration for certain interests in oil and
natural gas leases held by RMG in Wyoming and Montana. The RMG note was payable
in 41-monthly
35
principal payments of $0.1 million plus interest at 8% per annum commencing July
31, 2001 with the balance due December 31, 2004. The RMG note was secured solely
by CCBM's interests in the oil and natural gas leases in Wyoming and Montana. At
December 31, 2003 and 2004, the outstanding principal balance of this note was
$0.9 million and $0, respectively. In connection with our investment in
Pinnacle, we received a reduction in the principal amount of the RMG note of
approximately $1.5 million and relinquished the right to certain revenues
related to the properties contributed to Pinnacle. In the second quarter of
2004, we opted to exercise our right to cancel one-half of the remaining note
payable to RMG, or approximately $300,000, in exchange for assigning one-half of
our mineral interest in the Oyster Ridge leases to RMG.
Capital Leases
In December 2001, we entered into a capital lease agreement secured by
certain production equipment in the amount of $0.2 million. The lease is payable
in one payment of $11,323 and 35 monthly payments of $7,549 including interest
at 8.6% per annum. In October 2002, we entered into a capital lease agreement
secured by certain production equipment in the amount of $0.1 million. The lease
is payable in 36 monthly payments of $3,462 including interest at 6.4% per
annum. In May 2003, we entered into a capital lease agreement secured by certain
production equipment in the amount of $0.1 million. The lease is payable in 36
monthly payments of $3,030 including interest at 5.5% per annum. In August 2003,
we entered into a capital lease agreement secured by certain production
equipment in the amount of $0.1 million. The lease is payable in 36 monthly
payments of $2,179 including interest at 6.0% per annum. We have the option to
acquire the equipment at the conclusion of the lease for $1 under all of these
leases. Depreciation on the capital leases for the years ended December 31, 2003
and 2004 amounted to $48,000 and $46,000, respectively, and accumulated
depreciation on the leased equipment at December 31, 2003 and 2004 amounted to
$78,000 and $0.1 million, respectively.
Senior Subordinated Notes and Related Securities
In December 1999, we consummated the sale of $22.0 million principal amount
of 9% Senior Subordinated Notes due 2007 (the "Subordinated Notes") and $8.0
million of common stock and warrants. We sold $17.6 million, $2.2 million, $0.8
million, $0.8 million and $0.8 million principal amount of Subordinated Notes;
2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of our common stock and
2,208,152, 276,019, 92,006, 92,006 and 92,006 warrants to CB Capital Investors,
L.P. (now known as JPMorgan Partners (23A SBIC), L.P.), Mellon Ventures, L.P.,
Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton, respectively.
The Subordinated Notes were sold at a discount of $0.7 million, which is being
amortized over the life of the notes. Interest payments are due quarterly
commencing on March 31, 2000. As amended and described below, the Subordinated
Notes allow us, by annual election and we have historically elected, to increase
the amount of the Subordinated Notes by 60% of the interest which would
otherwise be payable in cash through December 15, 2006. As a result, our cash
obligation on the Subordinated Notes will increase significantly after December
2006. As of December 31, 2003 and 2004, the outstanding balance of the
Subordinated Notes had been increased by $5.3 million and $6.8 million,
respectively, for such interest paid in kind. Concurrently with the sale of the
Subordinated Notes, we sold to the original purchasers 3,636,634 shares of our
common stock at a price of $2.20 per share and warrants expiring in December
2007 to purchase up to 2,760,189 shares of our common stock at an exercise price
of $2.20 per share. For accounting purposes, the warrants were valued at $0.25
each.
In 2004, Mellon Ventures, L.P., JPMorgan Partners (23A SBIC), Steven A.
Webster and Douglas A. P. Hamilton exercised warrants to purchase 276,019,
2,208,152, 92,006 and 92,006 shares of common stock, respectively, on a cashless
exercise basis for a total of 205,692, 1,684,949, 70,205 and 70,205 shares of
common stock, respectively, and Paul B. Loyd, Jr., exercised warrants to
purchase 92,006 shares for a total of 92,006 shares of common stock. As a
result, no warrants to purchase shares remain outstanding from the warrants
originally issued in December 1999.
On June 7, 2004, an unaffiliated third party (the "Subordinated Notes
Purchaser") purchased all the outstanding Subordinated Notes from the original
note holders. In exchange for a $0.4 million amendment fee, certain terms and
conditions of the Subordinated Notes were amended, to provide for, among other
things, (1) a one year extension of the maturity to December 15, 2008, (2) a one
year extension, through December 15, 2005, of the paid-in-kind ("PIK") interest
option to pay-in-kind 60% of the interest due each period by increasing the
principal balance by a like amount (the "PIK option"), (3) an additional one
year option to extend the PIK option through December 15, 2006 at an annual
interest rate on the deferred amount of 10% and the payment of a one-time fee
equal to 0.5% of the principal then outstanding, (4) an increase and extension
on the prepayment premium on the Subordinated Notes, (5) a modification of a
covenant regarding maximum quarterly leverage that our Total Debt will not
exceed 3.5 times EBITDA (as such terms are defined in the securities purchase
agreement related to the Subordinated Notes) for the last 12 months at any time
and (6) additional flexibility to obtain a separate project financing facility
in the future. The amendment fee will be amortized over the remaining life of
the Subordinated Notes.
36
We are subject to certain other covenants under the terms under the
Subordinated Notes securities purchase agreement, including but not limited to,
(a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, (c) a limitation of our capital expenditures to an amount equal to our
EBITDA for the immediately prior fiscal year (unless approved by our Board of
Directors) and (d) a limitation on our Total Debt (as defined in the securities
purchase agreement related to the Subordinated Notes) to 3.5 times EBITDA for
any twelve month period.
Senior Subordinated Secured Notes
On October 29, 2004, we entered into a Note Purchase Agreement (the "Senior
Secured Notes Purchase Agreement") with PCRL Investments L.P. (the "Senior
Secured Notes Purchaser"). Pursuant to the Senior Secured Notes Purchase
Agreement, we may issue up to $28 million aggregate principal amount of our 10%
Senior Subordinated Secured Notes due 2008 (the "Senior Secured Notes") for a
purchase price equal to 90% of the principal amount of the Senior Secured Notes
then issued. On October 29, 2004, the Senior Secured Notes Purchaser purchased
$18 million aggregate principal amount of the Senior Secured Notes for a
purchase price of $16.2 million. The debt discount is being amortized to
interest expense using the effective interest method over the life of the notes.
Subject to the satisfaction of certain conditions, we have an option to issue up
to an additional $10 million aggregate principal amount of the Senior Secured
Notes to the Senior Secured Notes Purchaser before October 29, 2006.
The Senior Secured Notes are secured by a second lien on substantially all
of our current proved producing reserves and non-reserve assets, guaranteed by
our subsidiary, and subordinated to our obligations under the Credit Facility.
The Senior Secured Notes bear interest at 10% per annum, payable quarterly on
the 5th day of March, June, September and December of each year beginning March
5, 2005. The principal on the Senior Secured Notes is due December 15, 2008, and
we have the option to prepay the Senior Secured Notes at any time. The Senior
Secured Notes include an option that allows us to pay-in-kind 50% of the
interest due until June 5, 2007 by increasing the principal due by a like
amount. Subject to certain conditions, we have the option to pay the interest on
and principal of (at maturity or upon prepayment) the Senior Secured Notes with
our common stock, as long as the Secured Note Purchaser would not hold more than
9.99% of the number of shares of our common stock outstanding immediately after
giving effect to such payment. The value of such shares issued as payment on the
Senior Secured Notes is determined based on 90% of the volume weighted average
trading price during a specified period of days beginning with the date of the
payment notice and ending before the payment date. Our issuance costs related to
the transaction were $0.5 million.
As contemplated by the Senior Secured Notes Purchase Agreement, we also
entered into a registration rights agreement with the Secured Note Purchaser
(the "Registration Rights Agreement"). In the event that we choose to issue
shares of our common stock as payment of interest on the principal of the Senior
Secured Notes, the Registration Rights Agreement provides registration rights
with respect to such shares. We are generally required to file a resale shelf
registration statement to register the resale of such shares under the
Securities Act of 1933 (the "Securities Act") if such shares are not freely
tradable under Rule 144(k) under the Securities Act. We are subject to certain
covenants under the terms of the Registration Rights Agreement, including the
requirement that the registration statement be kept effective for resale of
shares subject to certain "blackout periods," when sales may not be made. In
certain circumstances, including those relating to (1) delisting of our common
stock, (2) blackout periods in excess of a maximum length of time, (3) certain
failures to make timely periodic filings with the Securities and Exchange
Commission, or (4) certain delays or failures to deliver stock certificates, we
may be required to repurchase common stock issued as payment on the Senior
Secured Notes and, in certain of these circumstances, to pay damages based on
the market value of our common stock. In certain situations, we are required to
indemnify the holders of registration rights under the Registration Rights
Agreement, including, without limitation, for liabilities under the Securities
Act.
The Senior Secured Notes Purchase Agreement includes certain
representations, warranties and covenants by the parties thereto. We are subject
to certain covenants under the terms of the Senior Secured Notes Purchase
Agreement, including, without limitation, the maintenance of the following
financial covenants: (1) a maximum total recourse debt to EBITDA ratio of not
more than 3.50 to 1.0, (2) a minimum EBITDA to interest expense ratio of 2.50 to
1.0, and (3) as of April 30, 2005, a minimum tangible net worth of $12.5 million
in excess of our tangible net worth as of September 30, 2004. Upon a change of
control, any holders of the Senior Secured Notes may require us to repurchase
such holders' Senior Secured Notes at a price equal to the then outstanding
principal amount of such Senior Secured Notes, together with all interest
accrued on such Senior Secured Notes through the date of repurchase. The Senior
Secured Notes Purchase Agreement also places restrictions on additional
indebtedness, dividends to shareholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, repurchase or
redemption for cash of our common stock, speculative commodity transactions and
other matters. The Senior Secured Notes Purchaser is an affiliate of the
Subordinated Notes Purchaser.
Series B Preferred Stock
37
In February 2002, we consummated the sale of 60,000 shares of Series B
Preferred Stock and 2002 Warrants to purchase 252,632 shares of common stock for
an aggregate purchase price of $6.0 million. We sold $4.0 million and $2.0
million of Series B Preferred Stock and 168,422 and 84,210 warrants to Mellon
Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock
was convertible into common stock by the investors at a conversion price of
$5.70 per share, subject to adjustment for transactions including issuance of
common stock or securities convertible into or exercisable for common stock at
less than the conversion price, and is initially convertible into 1,052,632
shares of common stock. The approximately $5.8 million net proceeds of this
financing were used to fund our ongoing exploration and development program and
general corporate purposes. In the first quarter of 2004, Mellon Ventures
exercised all 168,422 of its 2002 warrants on a cashless basis and received
36,570 shares which were sold in the 2004 public offering.
Mellon Ventures, Inc. converted all of its Series B Preferred Stock
(approximately 49,938 shares) into 876,099 shares of common stock on May 25,
2004. Steven A. Webster converted all of his Series B Preferred Stock
(approximately 25,195 shares) into 442,026 shares of common stock on June 30,
2004. As a result, no shares of Series B Preferred Stock remain outstanding.
The 2002 Warrants have a five-year term and originally entitled the holders
to purchase up to 252,632 shares of our common stock at a price of $5.94 per
share, subject to adjustment, and are exercisable at any time after issuance. As
of December 31, 2004, 84,210 of the 2002 Warrants remained outstanding. For
accounting purposes, the 2002 Warrants were valued at $0.06 per Warrant.
Each of our series of warrants was exerciseable on a cashless basis at the
option of the holder.
On March 22, 2005, Steven A. Webster exercised in full his 2002 Warrants to
purchase 84,211 shares of our common stock at a price of $5.94 per share. As a
result of the cashless exercise of the 2002 Warrants, Mr. Webster received
54,669 shares of common stock upon exercise.
38
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004),
"Share-Based Payment" ("SFAS No. 123(R)"). SFAS No. 123(R) will require
companies to measure all employee stock-based compensation awards using a fair
value method and record such expense in its consolidated financial statements.
In addition, the adoption of SFAS No. 123(R) requires additional accounting and
disclosure related to the income tax and cash flow effects resulting from
share-based payment arrangements. SFAS No. 123(R) is effective beginning as of
the first interim or annual reporting period beginning after June 15, 2005. The
Company is in the process of determining the impact of the requirements of SFAS
No. 123(R). The Company believes it is likely that the impact of the
requirements of SFAS No. 123(R) will significantly impact the Company's future
results of operations and continues to evaluate it to determine the degree of
significance.
In December 2004, SFAS No. 153, "Exchanges of Nonmonetary Assets - an
amendment of APB Opinion No. 29" is effective for fiscal years beginning after
June 15, 2005. This Statement addresses the measurement of exchange of
nonmonetary assets and eliminates the exception from fair value measurement for
nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB
Opinion No. 29, "Accounting for Nonmonetary Transactions" and replaces it with
an exception for exchanges that do not have commercial substance. The adoption
of SFAS No. 153 is expected to have no impact on the Company's consolidated
financial statements.
In October 2004, the SEC released SAB 106, which expresses the staff's
views on the application of SFAS No. 143 by oil and gas producing companies
following the full cost accounting method. SAB 106 provides interpretive
responses related to computing the full cost ceiling to avoid double-counting
the expected future cash outlays associated with asset retirement obligations,
required disclosures relating to the interaction of SFAS No. 143 and the full
cost rules, and the impact of SFAS No. 143 on the calculation of depreciation,
depletion and amortization. The Company is in the process of determining the
impact of the requirements of SAB 106.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The following summarizes several of our critical accounting policies. See a
complete list of significant accounting policies in Note 2 to our consolidated
financial statements.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from these estimates. The use of
these estimates significantly affects natural gas and oil properties through
depletion and the full cost ceiling test, as discussed in more detail below.
Significant estimates include volumes of oil and natural gas reserves used
in calculation depletion of proved oil and natural gas properties, future net
revenues and abandonment obligations, impairment of undeveloped properties,
future income taxes and related assets/liabilities, bad debts, derivatives,
contingencies and litigation. Oil and natural gas reserve estimates, which are
the basis for unit-of-production depletion and the ceiling test, have numerous
inherent uncertainties. The accuracy of any reserve estimate is a function of
the quality of available date and of engineering and geological interpretation
and judgment. Results of drilling, testing and production subsequent to the date
of the estimate may justify revision of such estimate. Accordingly, reserve
estimates are often different from the quantities of oil and natural gas that
are ultimately recovered. In addition, reserve estimates are vulnerable to
changes in wellhead prices of crude oil and natural gas. Such prices have been
volatile in the past and can be expected to be volatile in the future.
The significant estimates are based on current assumptions that may be
materially effected by changes to future economic conditions such as the markets
prices received for sales of volumes of oil and natural gas, interest rates, the
market value of our
39
common stock and corresponding volatility and our ability to generate future
taxable income. Future changes to these assumptions may affect these significant
estimates materially in the near term.
Oil and Natural Gas Properties
We account for investments in natural gas and oil properties using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of natural gas and oil properties are
capitalized. These costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. We proportionally consolidate our interests
in natural gas and oil properties. We capitalized compensation costs for
employees working directly on exploration activities of $1.0 million, $1.4
million and $1.7 million in 2002, 2003 and 2004, respectively. We expense
maintenance and repairs as they are incurred.
We amortize natural gas and oil properties based on the unit-of-production
method using estimates of proved reserve quantities. We do not amortize
investments in unproved properties until proved reserves associated with the
projects can be determined or until these investments are impaired. We
periodically evaluate, on a property-by-property basis, unevaluated properties
for impairment. If the results of an assessment indicate that the properties are
impaired, we add the amount of impairment to the proved natural gas and oil
property costs to be amortized. The amortizable base includes estimated future
development costs and, where significant, dismantlement, restoration and
abandonment costs, net of estimated salvage values. The depletion rate per Mcfe
for 2002, 2003 and 2004 was $1.41, $1.55 and $1.86, respectively.
We account for dispositions of natural gas and oil properties as
adjustments to capitalized costs with no gain or loss recognized, unless such
adjustments would significantly alter the relationship between capitalized costs
and proved reserves. We have not had any transactions that significantly alter
that relationship.
The net capitalized costs of proved oil and natural gas properties are
subject to a "ceiling test" which limits such costs to the estimated present
value, discounted at a 10% interest rate, of future net revenues from proved
reserves, based on current economic and operating conditions (the "Full Cost
Ceiling"). If net capitalized costs exceed this limit, the excess is charged to
operations through depreciation, depletion and amortization.
In mid-March 2004, during the year-end close of our 2003 financial
statements, it was determined that there was a computational error in the
ceiling test calculation which overstated the tax basis used in the computation
to derive our after-tax present value (discounted at 10%) of future net revenues
from proved reserves. We further determined that this tax basis error was also
present in each of our previous ceiling test computations dating back to 1997.
This error only affected our after-tax computation, used in the ceiling test
calculation and the unaudited supplemental oil and gas disclosure, and did not
impact our: (1) pre-tax valuation of the present value (discounted at 10%) of
future net revenues from proved reserves, (2) our proved reserve volumes, (3)
our EBITDA or our future cash flows from operations, (4) our net deferred tax
liability, (5) our estimated tax basis in oil and gas properties, or (6) our
estimated tax net operating losses.
After discovering this computational error, the ceiling tests for all
quarters since 1997 were recomputed and it was determined that no write-down of
our oil and gas assets was necessary in any of the years from 1997 to 2003.
However, based upon the oil and natural gas prices in effect on March 31, 2003
and September 30, 2003, the unamortized cost of oil and natural gas properties
exceeded the cost center ceiling. As permitted by full cost accounting rules,
improvements in pricing and/or the addition of proved reserves subsequent to
those dates sufficiently increased the present value of our oil and natural gas
assets and removed the necessity to record a write-down in these periods. Using
the prices in effect and estimated proved reserves existing on March 31, 2003
and September 30, 2003, the after-tax write-down would have been approximately
$1.0 million, and $6.3 million, respectively, had we not taken into account
these subsequent improvements. These improvements at September 30, 2003 included
estimated proved reserves attributable to our Shady Side #1 well, which we have
since sold in February 2005. Because of the volatility of oil and gas prices, no
assurance can be given that we will not experience a write-down in future
periods.
In connection with our year-end 2004 ceiling test computation, a price
sensitivity study also indicated that a 20 percent increase in commodity prices
at December 31, 2004 would have increased the pre-tax present value of future
net revenues ("NPV") by approximately $56.5 million. Conversely, a 20 percent
decrease in commodity prices at December 31, 2004 would have reduced our NPV by
approximately $56.5 million. This would have caused our unamortized cost of
proved oil and gas properties to exceed the cost pool ceiling, resulting in an
after-tax write-down of approximately $2.7 million. The aforementioned price
sensitivity and NPV is as of December 31, 2004 and, accordingly, does not
include any potential changes in reserves due to first quarter 2005 performance,
such as commodity prices, reserve revisions and drilling results.
The Full Cost Ceiling cushion at the end of 2004 of approximately $32.5
million was based upon average realized oil and
40
natural gas prices of $41.18 per Bbl and $5.68 per Mcf, respectively, or a
volume weighted average price of $37.63 per BOE. This cushion, however, would
have been zero on such date at an estimated volume weighted average price of
$31.50 per BOE. A BOE means one barrel of oil 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 been
higher or substantially higher, more often for oil than natural gas on an energy
equivalent basis, although there have been periods in which they have been lower
or substantially lower.
Under the full cost method of accounting, the depletion rate is the current
period production as a percentage of the total proved reserves. Total proved
reserves include both proved developed and proved undeveloped reserves. The
depletion rate is applied to the net book value and estimated future development
costs to calculate the depletion expense.
We have a significant amount of proved undeveloped reserves, which are
primarily oil reserves. We had 44.9 Bcfe and 72.5 Bcfe of proved undeveloped
reserves, representing 64% and 66% of our total proved reserves at December 31,
2003 and 2004, respectively. As of December 31, 2003 and 2004, a portion of
these proved undeveloped reserves, or approximately 43.9 Bcfe and 45.7,
respectively, are attributable to our Camp Hill properties that we acquired in
1994. See "Business and Properties - East Texas Area -- Camp Hill Project" for
further discussion of the Camp Hill properties. The estimated future development
costs to develop our proved undeveloped reserves on our Camp Hill properties are
relatively low, on a per Mcfe basis, when compared to the estimated future
development costs to develop our proved undeveloped reserves on our other oil
and natural gas properties. Furthermore, the average depletable life of our Camp
Hill properties is considerably longer, or approximately 15 years, when compared
to the depletable life of our remaining oil and natural gas properties of
approximately 2.25 years. Accordingly, the combination of a relatively low ratio
of future development costs and a relatively long depletable life on our Camp
Hill properties has resulted in a relatively low overall historical depletion
rate and DD&A expense. This has resulted in a capitalized cost basis associated
with producing properties being depleted over a longer period than the
associated production and revenue stream. It has also resulted in the build-up
of nondepleted capitalized costs associated with properties that have been
completely depleted. We expect our relatively low historical depletion rate to
continue until the high level of nonproducing reserves to total proved reserves
is reduced and the life of our proved developed reserves is extended through
development drilling and/or the significant addition of new proved producing
reserves through acquisition or exploration. If our level of total proved
reserves, finding cost and current prices were all to remain constant, this
continued build-up of capitalized costs increases the probability of a ceiling
test write-down.
We depreciate other property and equipment using the straight-line method
based on estimated useful lives ranging from five to 10 years.
Oil and Natural Gas Reserve Estimates
The reserve data included in this document are estimates prepared by Ryder
Scott Company, DeGolyer and MacNaughton, and Fairchild & Wells, Inc.,
Independent Petroleum Engineers. Reserve engineering is a subjective process of
estimating underground accumulations of hydrocarbons that cannot be measured in
an exact manner. The process relies on judgment and the interpretation of
available geologic, geophysical, engineering and production data. The extent,
quality and reliability of this data can vary. The process also requires certain
economic assumptions regarding drilling and operating expense, capital
expenditures, taxes and availability of funds. The SEC mandates some of these
assumptions such as oil and natural gas prices and the present value discount
rate.
Proved reserve estimates prepared by others may be substantially higher or
lower than our estimates. Because these estimates depend on many assumptions,
all of which may differ from actual results, reserve quantities actually
recovered may be significantly different than estimated. Material revisions to
reserve estimates may be made depending on the results of drilling, testing, and
rates of production.
You should not assume that the present value of future net cash flows is
the current market value of our estimated proved reserves. In accordance with
SEC requirements, we based the estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate.
Our rate of recording depreciation, depletion and amortization expense for
proved properties is dependent on our estimate of proved reserves. If these
reserve estimates decline, the rate at which we record these expenses will
increase. A 10% increase or decrease in our proved reserves would have increased
or decreased our depletion expense by 9.5% for the year ended December 31, 2004.
Derivative Instruments and Hedging Activities
41
Upon entering into a derivative contract, we designate the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of our
derivative instruments at December 31, 2002, 2003 and 2004 were designated as
cash flow hedges.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is discontinued,
the derivative will be carried at fair value on the balance sheet with future
changes in its fair value recognized in future earnings.
We typically use fixed rate swaps and costless collars to hedge our
exposure to material changes in the price of natural gas and oil. We formally
document all relationships between hedging instruments and hedged items, as well
as our risk management objectives and strategy for undertaking various hedge
transactions. This process includes linking all derivatives that are designated
cash flow hedges to forecasted transactions. We also formally assess, both at
the hedge's inception and on an ongoing basis, whether the derivatives that are
used in hedging transactions are highly effective in offsetting changes in cash
flows of hedged transactions.
For a discussion of the impact of changes in the prices of oil and gas on
our hedging transactions, see "Volatility of Oil and Natural Gas Prices" below.
Our Board of Directors sets all of our hedging policy, and reviews volumes,
types of instruments and counterparties, on a quarterly basis. These policies
are followed by management through the execution of trades by either the
President or Chief Financial Officer after consultation and concurrence by the
President, Chief Financial Officer and Chairman of the Board. The master
contracts with the authorized counterparties identify the President and Chief
Financial Officer as the only representatives authorized to execute trades. The
Board of Directors also reviews the status and results of hedging activities
quarterly.
Income Taxes
Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"),
"Accounting for Income Taxes," deferred income taxes are recognized at each year
end for the future tax consequences of differences between the tax bases of
assets and liabilities and their financial reporting amounts based on tax laws
and statutory tax rates applicable to the periods in which the differences are
expected to affect taxable income. We routinely assess the realizability of our
deferred tax assets. We consider future taxable income in making such
assessments. If we conclude that it is more likely than not that some portion or
all of the deferred tax assets will not be realized under accounting standards,
it is reduced by a valuation allowance. However, despite our attempt to make an
accurate estimate, the ultimate utilization of our deferred tax assets is highly
dependent upon our actual production and the realization of taxable income in
future periods.
Contingencies
Liabilities and other contingencies are recognized upon determination of an
exposure, which when analyzed indicates that it is both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimable.
VOLATILITY OF OIL AND NATURAL GAS PRICES
Our revenues, future rate of growth, results of operations, financial
condition and ability to borrow funds or obtain additional capital, as well as
the carrying value of our properties, are substantially dependent upon
prevailing prices of oil and natural gas. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Risk Factors--Natural
gas and oil prices are highly volatile, and lower prices will negatively affect
our financial results."
We periodically review the carrying value of our oil and natural gas
properties under the full cost accounting rules of the Commission. See
"--Critical Accounting Policies and Estimates--Oil and Natural Gas Properties"
and "--Risk Factors-- We may record ceiling limitation write-downs that would
reduce our shareholders' equity."
Total oil purchased and sold under swaps and collars during 2002, 2003 and
2004 were 131,300 Bbls, 193,600 Bbls and 121,700, respectively. Total natural
gas purchased and sold under swaps and collars in 2002, 2003 and 2004 were
2,314,000
42
MMBtu, 2,739,000 MMBtu and 3,936,000 MMBtu, respectively. The net gains and
(losses) realized by us under such hedging arrangements were $(0.9 million),
$(1.8 million) and $1.0 million for 2002, 2003 and 2004, respectively, and are
included in oil and natural gas revenues.
To mitigate some of our commodity price risk, we engage periodically in
certain other limited hedging activities including price swaps, costless collars
and, occasionally, put options, in order to establish some price floor
protection. We record the costs and any benefits derived from these price floors
as a reduction or increase, as applicable, in natural gas and oil sales revenue;
these reductions and increases were not significant for any year presented in
the financial information included in this report. The costs to purchase put
options are amortized over the option period. We do not hold or issue derivative
instruments for trading purposes.
As of December 31, 2004, $59,000, net of tax of $34,000, remained in
accumulated other comprehensive income related to the valuation of our hedging
positions.
While the use of hedging arrangements limits the downside risk of adverse
price movements, it may also limit our ability to benefit from increases in the
prices of natural gas and oil. We enter into the majority of our hedging
transactions with two counterparties and have a netting agreement in place with
those counterparties. We do not obtain collateral to support the agreements but
monitor the financial viability of counterparties and believe our credit risk is
minimal on these transactions. Under these arrangements, payments are received
or made based on the differential between a fixed and a variable product price.
These agreements are settled in cash at expiration or exchanged for physical
delivery contracts. In the event of nonperformance, we would be exposed again to
price risk. We have some risk of financial loss because the price received for
the product at the actual physical delivery point may differ from the prevailing
price at the delivery point required for settlement of the hedging transaction.
Moreover, our hedging arrangements generally do not apply to all of our
production and thus provide only partial price protection against declines in
commodity prices. We expect that the amount of our hedges will vary from time to
time.
Our gas derivative transactions are generally settled based upon the
average of the reporting settlement prices on the NYMEX for the last three
trading days of a particular contract month. Our oil derivative transactions are
generally settled based on the average reporting settlement prices on the NYMEX
for each trading day of a particular calendar month. For the month of December
2004, a $0.10 change in the price per Mcf of gas sold would have changed revenue
by $71,000. A $0.70 change in the price per barrel of oil would have changed
revenue by $16,000.
The table below summarizes our total natural gas production volumes subject
to derivative transactions during 2004 and the weighted average NYMEX reference
price for those volumes.
NATURAL GAS SWAPS NATURAL GAS CAPS
- --------------------- ---------------------
Volumes MMBtu 180,000 Volumes MMBtu 3,756,000
Average price $/MMBtu $ 6.67 Average price $/MMBtu
Floor $ 4.50
Ceiling $ 6.47
The table below summarizes our total crude oil production volumes subject
to derivative transactions during 2004 and the weighted average NYMEX reference
price for those volumes.
CRUDE OIL SWAPS CRUDE OIL CAPS
- -------------------- --------------------
Volumes Bbls 91,200 Volumes Bbls 30,500
Average price $/Bbls $ 33.72 Average price $/Bbls
Floor $ 42.83
Ceiling $ 51.84
At December 31, 2003 and 2004 we had the following outstanding hedge
positions:
43
DECEMBER 31, 2003
- ----------------------------------------------------------------------------------
CONTRACT VOLUMES
----------------
AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ ------- ----------- ----------- -------------
First Quarter 2004 27,000 $30.36
First Quarter 2004 180,000 6.67
First Quarter 2004 546,000 $4.10 $7.00
Second Quarter 2004 18,300 30.38
Second Quarter 2004 546,000 4.00 5.60
Third Quarter 2004 552,000 4.00 5.60
Fourth Quarter 2004 369,000 4.00 5.80
DECEMBER 31, 2004
- ----------------------------------------------------------------------------------
CONTRACT VOLUMES
----------------
AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ ------- ----------- ----------- -------------
First Quarter 2005 27,000 $41.67 $50.50
First Quarter 2005 928,000 5.40 8.11
Second Quarter 2005 364,000 5.25 7.15
Second Quarter 2005 91,000 $6.03
Third Quarter 2005 368,000 5.25 7.40
Third Quarter 2005 92,000 6.03
Fourth Quarter 2005 276,000 5.25 7.92
Fourth Quarter 2005 92,000 6.03
In addition to the hedge positions above, during the second quarter of
2003, we acquired options to sell 6,000 MMBtu of natural gas per day for the
period July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for
approximately $119,000. We acquired these options to protect our cash position
against potential margin calls on certain natural gas derivatives due to large
increases in the price of natural gas. These options were classified as
derivatives. As of December 31, 2003, these options have expired and a charge of
$119,000 has been included in other income and expense for the year ended
December 31, 2003.
Since year-end 2004, we entered into costless collar arrangements covering
1,099,000 MMBtu of natural gas for April 2005 through December 2005 production
comprised as follows: 455,000 MMbtu in the second quarter 2005 with average
floor and ceiling prices of $6.10 and $7.50, respectively, 368,000 MMbtu in the
third quarter 2005 with average floor and ceiling prices of $6.15 and $7.69,
respectively, and 276,000 MMbtu in the fourth quarter 2005 with average floor
and ceiling prices of $6.00 and $8.60, respectively. We also entered into swap
arrangements covering 27,100 Bbls of crude oil for February 2005 and June 2005
production at an average fixed price of $50.19.
RISK FACTORS
NATURAL GAS AND OIL DRILLING IS A SPECULATIVE ACTIVITY AND INVOLVES NUMEROUS
RISKS AND SUBSTANTIAL AND UNCERTAIN COSTS THAT COULD ADVERSELY AFFECT US.
Our success will be largely dependent upon the success of our drilling
program. Drilling for natural gas and oil involves numerous risks, including the
risk that no commercially productive natural gas or oil reservoirs will be
discovered. The cost of drilling, completing and operating wells is substantial
and uncertain, and drilling operations may be curtailed, delayed or canceled as
a result of a variety of factors beyond our control, including:
- unexpected or adverse drilling conditions;
- elevated pressure or irregularities in geologic formations;
- equipment failures or accidents;
44
- adverse weather conditions;
- compliance with governmental requirements; and
- shortages or delays in the availability of drilling rigs, crews and
equipment.
Because we identify the areas desirable for drilling from 3-D seismic data
covering large areas, we may not seek to acquire an option or lease rights until
after the seismic data is analyzed or until the drilling locations are also
identified; in those cases, we may not be permitted to lease, drill or produce
natural gas or oil from those locations.
Even if drilled, our completed wells may not produce reserves of natural
gas or oil that are economically viable or that meet our earlier estimates of
economically recoverable reserves. Our overall drilling success rate or our
drilling success rate for activity within a particular project area may decline.
Unsuccessful drilling activities could result in a significant decline in our
production and revenues and materially harm our operations and financial
condition by reducing our available cash and resources. Because of the risks and
uncertainties of our business, our future performance in exploration and
drilling may not be comparable to our historical performance described in this
Form 10-K.
WE MAY NOT ADHERE TO OUR PROPOSED DRILLING SCHEDULE.
Our final determination of whether to drill any scheduled or budgeted wells
will be dependent on a number of factors, including:
- the results of our exploration efforts and the acquisition, review and
analysis of the seismic data;
- the availability of sufficient capital resources to us and the other
participants for the drilling of the prospects;
- the approval of the prospects by the other participants after
additional data has been compiled;
- economic and industry conditions at the time of drilling, including
prevailing and anticipated prices for natural gas and oil and the
availability and prices of drilling rigs and crews; and
- the availability of leases and permits on reasonable terms for the
prospects.
Although we have identified or budgeted for numerous drilling prospects, we
may not be able to lease or drill those prospects within our expected time frame
or at all. Wells that are currently part of our capital budget may be based on
statistical results of drilling activities in other 3-D project areas that we
believe are geologically similar rather than on analysis of seismic or other
data in the prospect area, in which case actual drilling and results are likely
to vary, possibly materially, from those statistical results. In addition, our
drilling schedule may vary from our expectations because of future
uncertainties.
OUR RESERVE DATA AND ESTIMATED DISCOUNTED FUTURE NET CASH FLOWS ARE ESTIMATES
BASED ON ASSUMPTIONS THAT MAY BE INACCURATE AND ARE BASED ON EXISTING ECONOMIC
AND OPERATING CONDITIONS THAT MAY CHANGE IN THE FUTURE.
There are numerous uncertainties inherent in estimating natural gas and oil
reserves and their estimated value, including many factors beyond the control of
the producer. The reserve data set forth in this Form 10-K represents only
estimates. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner. The reserve data included in or filed as an exhibit
to this Form 10-K represents estimates that depend on a number of factors and
assumptions that may vary considerably from actual results, including:
- historical production from the area compared with production from
other areas;
- the assumed effects of regulations by governmental agencies;
- assumptions concerning future natural gas and oil prices;
future operating costs;
45
- severance and excise taxes;
- development costs; and
- workover and remedial costs.
For these reasons, estimates of the economically recoverable quantities of
natural gas and oil attributable to any particular group of properties,
classifications of those reserves based on risk of recovery and estimates of the
future net cash flows expected from them prepared by different engineers or by
the same engineers but at different times may vary substantially. Accordingly,
reserve estimates may be subject to upward or downward adjustment, and actual
production, revenue and expenditures with respect to our reserves likely will
vary, possibly materially, from estimates. Additionally, there recently has been
increased debate and disagreement over the classification of reserves, with
particular focus on proved undeveloped reserves. Changes in interpretations as
to classification standards, or disagreements with our interpretations, could
cause us to write down these reserves.
As of December 31, 2004, approximately 83% of our proved reserves were
proved undeveloped and proved nonproducing. Moreover, some of the producing
wells included in our reserve reports as of December 31, 2004 had produced for a
relatively short period of time as of that date. Because most of our reserve
estimates are calculated using volumetric analysis, those estimates are less
reliable than estimates based on a lengthy production history. Volumetric
analysis involves estimating the volume of a reservoir based on the net feet of
pay of the structure and an estimation of the area covered by the structure
based on seismic analysis. In addition, realization or recognition of our proved
undeveloped reserves will depend on our development schedule and plans. Lack of
certainty with respect to development plans for proved undeveloped reserves
could cause the discontinuation of the classification of these reserves as
proved. We have from time to time chosen to delay development of our proved
undeveloped reserves in the Camp Hill Field in East Texas in favor of pursuing
shorter-term exploration projects with higher potential rates of return, adding
to our lease position in this field and further evaluating additional economic
enhancements for this field's development.
The discounted future net cash flows included in this Form 10-K are not
necessarily the same as the current market value of our estimated natural gas
and oil reserves. As required by the Commission, the estimated discounted future
net cash flows from proved reserves are based on prices and costs as of the date
of the estimate. Actual future net cash flows also will be affected by factors
such as:
- the actual prices we receive for natural gas and oil;
- our actual operating costs in producing natural gas and oil;
- the amount and timing of actual production;
- supply and demand for natural gas and oil;
- increases or decreases in consumption of natural gas and oil; and
- changes in governmental regulations or taxation.
In addition, the 10% discount factor we use when calculating discounted
future net cash flows for reporting requirements in compliance with the
Financial Accounting Standards Board in Statement of Financial Accounting
Standards No. 69 may not be the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with us or the
natural gas and oil industry in general.
WE DEPEND ON SUCCESSFUL EXPLORATION, DEVELOPMENT AND ACQUISITIONS TO MAINTAIN
RESERVES AND REVENUE IN THE FUTURE.
In general, the volume of production from natural gas and oil properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent we conduct successful
exploration and development activities or acquire properties containing proved
reserves, or both, our proved reserves will decline as reserves are produced.
Our future natural gas and oil production is, therefore, highly dependent on our
level of success in finding or acquiring additional reserves. The business of
exploring for, developing or acquiring reserves is capital intensive. Recovery
of our reserves, particularly undeveloped reserves, will require significant
additional capital expenditures and successful drilling operations. To the
extent cash flow from operations is reduced and external sources of capital
become limited or unavailable, our ability to make the necessary capital
investment to maintain
46
or expand our asset base of natural gas and oil reserves would be impaired. In
addition, we are dependent on finding partners for our exploratory activity. To
the extent that others in the industry do not have the financial resources or
choose not to participate in our exploration activities, we will be adversely
affected.
NATURAL GAS AND OIL PRICES ARE HIGHLY VOLATILE, AND LOWER PRICES WILL NEGATIVELY
AFFECT OUR FINANCIAL RESULTS.
Our revenue, profitability, cash flow, future growth and ability to borrow
funds or obtain additional capital, as well as the carrying value of our
properties, are substantially dependent on prevailing prices of natural gas and
oil. Historically, the markets for natural gas and oil prices have been
volatile, and those markets are likely to continue to be volatile in the future.
It is impossible to predict future natural gas and oil price movements with
certainty. Prices for natural gas and oil are subject to wide fluctuation in
response to relatively minor changes in the supply of and demand for natural gas
and oil, market uncertainty and a variety of additional factors beyond our
control. These factors include:
- the level of consumer product demand;
- overall economic conditions;
- weather conditions;
- domestic and foreign governmental relations;
- the price and availability of alternative fuels;
- political conditions;
- the level and price of foreign imports of oil and liquefied natural
gas; and
- the ability of the members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil price controls.
Declines in natural gas and oil prices may materially adversely affect our
financial condition, liquidity and ability to finance planned capital
expenditures and results of operations.
WE FACE STRONG COMPETITION FROM OTHER NATURAL GAS AND OIL COMPANIES.
We encounter competition from other natural gas and oil companies in all
areas of our operations, including the acquisition of exploratory prospects and
proven properties. Our competitors include major integrated natural gas and oil
companies and numerous independent natural gas and oil companies, individuals
and drilling and income programs. Many of our competitors are large,
well-established companies that have been engaged in the natural gas and oil
business much longer than we have and possess substantially larger operating
staffs and greater capital resources than we do. These companies may be able to
pay more for exploratory projects and productive natural gas and oil properties
and may be able to define, evaluate, bid for and purchase a greater number of
properties and prospects than our financial or human resources permit. In
addition, these companies may be able to expend greater resources on the
existing and changing technologies that we believe are and will be increasingly
important to attaining success in the industry. We may not be able to conduct
our operations, evaluate and select suitable properties and consummate
transactions successfully in this highly competitive environment.
WE MAY NOT BE ABLE TO KEEP PACE WITH TECHNOLOGICAL DEVELOPMENTS IN OUR INDUSTRY.
The natural gas and oil industry is characterized by rapid and significant
technological advancements and introductions of new products and services using
new technologies. As others use or develop new technologies, we may be placed at
a competitive disadvantage, and competitive pressures may force us to implement
those new technologies at substantial cost. In addition, other natural gas and
oil companies may have greater financial, technical and personnel resources that
allow them to enjoy technological advantages and may in the future allow them to
implement new technologies before we can. We may not be able to respond to these
competitive pressures and implement new technologies on a timely basis or at an
acceptable cost. If one or more of the technologies we use now or in the future
were to become obsolete or if we are unable to use the most advanced
commercially available technology, our business, financial condition and results
of operations could be materially adversely affected.
47
WE ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS AND ENVIRONMENTAL RISKS.
Natural gas and oil operations are subject to various federal, state and
local government regulations that may change from time to time. Matters subject
to regulation include discharge permits for drilling operations, plug and
abandonment bonds, reports concerning operations, the spacing of wells,
unitization and pooling of properties and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on production by
restricting the rate of flow of natural gas and oil wells below actual
production capacity in order to conserve supplies of natural gas and oil. Other
federal, state and local laws and regulations relating primarily to the
protection of human health and the environment apply to the development,
production, handling, storage, transportation and disposal of natural gas and
oil, by-products thereof and other substances and materials produced or used in
connection with natural gas and oil operations. In addition, we may be liable
for environmental damages caused by previous owners of property we purchase or
lease. As a result, we may incur substantial liabilities to third parties or
governmental entities and may be required to incur substantial remediation
costs. Further, we or our affiliates hold certain mineral leases in the State of
Montana that require coalbed methane drilling permits, the issuance of which has
been challenged in pending litigation. We may not be able to obtain new permits
in an optimal time period or at all. We also are subject to changing and
extensive tax laws, the effects of which cannot be predicted. Compliance with
existing, new or modified laws and regulations could have a material adverse
effect on our business, financial condition and results of operations.
WE ARE SUBJECT TO VARIOUS OPERATING AND OTHER CASUALTY RISKS THAT COULD RESULT
IN LIABILITY EXPOSURE OR THE LOSS OF PRODUCTION AND REVENUES.
The natural gas and oil business involves operating hazards such as:
- well blowouts;
- mechanical failures;
- explosions;
- uncontrollable flows of oil, natural gas or well fluids;
- fires;
- geologic formations with abnormal pressures;
- pipeline ruptures or spills;
- releases of toxic gases; and
- other environmental hazards and risks.
Any of these hazards and risks can result in the loss of hydrocarbons,
environmental pollution, personal injury claims and other damage to our
properties and the property of others.
WE MAY NOT HAVE ENOUGH INSURANCE TO COVER ALL OF THE RISKS WE FACE.
In accordance with customary industry practices, we maintain insurance
coverage against some, but not all, potential losses in order to protect against
the risks we face. We do not carry business interruption insurance. We may elect
not to carry insurance if our management believes that the cost of available
insurance is excessive relative to the risks presented. In addition, we cannot
insure fully against pollution and environmental risks. The occurrence of an
event not fully covered by insurance could have a material adverse effect on our
financial condition and results of operations.
WE CANNOT CONTROL THE ACTIVITIES ON PROPERTIES WE DO NOT OPERATE AND ARE UNABLE
TO ENSURE THEIR PROPER OPERATION AND PROFITABILITY.
We do not operate all of the properties in which we have an interest. As a
result, we have limited ability to exercise influence over, and control the
risks associated with, operations of these properties. The failure of an
operator of our wells to adequately perform operations, an operator's breach of
the applicable agreements or an operator's failure to act in ways that are in
our best interests could
48
reduce our production and revenues. The success and timing of our drilling and
development activities on properties operated by others therefore depend upon a
number of factors outside of our control, including the operator's
- timing and amount of capital expenditures;
- expertise and financial resources;
- inclusion of other participants in drilling wells; and
- use of technology.
THE MARKETABILITY OF OUR NATURAL GAS PRODUCTION DEPENDS ON FACILITIES THAT WE
TYPICALLY DO NOT OWN OR CONTROL, WHICH COULD RESULT IN A CURTAILMENT OF
PRODUCTION AND REVENUES.
The marketability of our production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. We generally deliver natural gas through gas gathering
systems and gas pipelines that we do not own under interruptible or short-term
transportation agreements. Under the interruptible transportation agreements,
the transportation of our gas may be interrupted due to capacity constraints on
the applicable system, for maintenance or repair of the system, or for other
reasons as dictated by the particular agreements. Our ability to produce and
market natural gas on a commercial basis could be harmed by any significant
change in the cost or availability of such markets, systems or pipelines.
OUR FUTURE ACQUISITIONS MAY YIELD REVENUES OR PRODUCTION THAT VARIES
SIGNIFICANTLY FROM OUR PROJECTIONS.
In acquiring producing properties, we assess the recoverable reserves,
future natural gas and oil prices, operating costs, potential liabilities and
other factors relating to the properties. Our assessments are necessarily
inexact and their accuracy is inherently uncertain. Our review of a subject
property in connection with our acquisition assessment will not reveal all
existing or potential problems or permit us to become sufficiently familiar with
the property to assess fully its deficiencies and capabilities. We may not
inspect every well, and we may not be able to observe structural and
environmental problems even when we do inspect a well. If problems are
identified, the seller may be unwilling or unable to provide effective
contractual protection against all or part of those problems. Any acquisition of
property interests may not be economically successful, and unsuccessful
acquisitions may have a material adverse effect on our financial condition and
future results of operations.
OUR BUSINESS MAY SUFFER IF WE LOSE KEY PERSONNEL.
We depend to a large extent on the services of certain key management
personnel, including our executive officers and other key employees, the loss of
any of whom could have a material adverse effect on our operations. We have
entered into employment agreements with each of S.P. Johnson IV, our President
and Chief Executive Officer, Paul F. Boling, our Chief Financial Officer,
Gregory E. Evans, our Vice President of Exploration, Kendall A. Trahan, our Vice
President of Land, and J. Bradley Fisher, our Vice President of Operations. We
do not maintain key-man life insurance with respect to any of our employees. Our
success will be dependent on our ability to continue to employ and retain
skilled technical personnel.
WE MAY EXPERIENCE DIFFICULTY IN ACHIEVING AND MANAGING FUTURE GROWTH.
We have experienced growth in the past primarily through the expansion of
our drilling program. Future growth may place strains on our resources and cause
us to rely more on project partners and independent contractors, possibly
negatively affecting our financial condition and results of operations. Our
ability to grow will depend on a number of factors, including:
- our ability to obtain leases or options on properties, including those
for which we have 3-D seismic data;
- our ability to acquire additional 3-D seismic data;
- our ability to identify and acquire new exploratory prospects;
- our ability to develop existing prospects;
- our ability to continue to retain and attract skilled personnel;
49
- our ability to maintain or enter into new relationships with project
partners and independent contractors;
- the results of our drilling program;
- hydrocarbon prices; and
- our access to capital.
We may not be successful in upgrading our technical, operations and
administrative resources or in increasing our ability to internally provide
certain of the services currently provided by outside sources, and we may not be
able to maintain or enter into new relationships with project partners and
independent contractors. Our inability to achieve or manage growth may adversely
affect our financial condition and results of operations.
WE MAY CONTINUE TO HEDGE THE PRICE RISKS ASSOCIATED WITH OUR PRODUCTION. OUR
HEDGE TRANSACTIONS MAY RESULT IN OUR MAKING CASH PAYMENTS OR PREVENT US FROM
BENEFITING TO THE FULLEST EXTENT POSSIBLE FROM INCREASES IN PRICES FOR NATURAL
GAS AND OIL.
Because natural gas and oil prices are unstable, we periodically enter into
price-risk-management transactions such as swaps, collars, futures and options
to reduce our exposure to price declines associated with a portion of our
natural gas and oil production and thereby to achieve a more predictable cash
flow. The use of these arrangements limits our ability to benefit from increases
in the prices of natural gas and oil. Our hedging arrangements may apply to only
a portion of our production, thereby providing only partial protection against
declines in natural gas and oil prices. These arrangements may expose us to the
risk of financial loss in certain circumstances, including instances in which
production is less than expected, our customers fail to purchase contracted
quantities of natural gas and oil or a sudden, unexpected event materially
impacts natural gas or oil prices.
WE HAVE SUBSTANTIAL CAPITAL REQUIREMENTS THAT, IF NOT MET, MAY HINDER
OPERATIONS.
We have experienced and expect to continue to experience substantial
capital needs as a result of our active exploration, development and acquisition
programs. We expect that additional external financing will be required in the
future to fund our growth. We may not be able to obtain additional financing,
and financing under existing or new credit facilities may not be available in
the future. Without additional capital resources, we may be forced to limit or
defer our planned natural gas and oil exploration and development program and
thereby adversely affect the recoverability and ultimate value of our natural
gas and oil properties, in turn negatively affecting our business, financial
condition and results of operations.
OUR CREDIT FACILITY CONTAINS OPERATING RESTRICTIONS AND FINANCIAL COVENANTS, AND
WE MAY HAVE DIFFICULTY OBTAINING ADDITIONAL CREDIT.
Over the past few years, increases in commodity prices and proved reserve
amounts and the resulting increase in our estimated discounted future net
revenue have allowed us to increase our available borrowing amounts. In the
future, commodity prices may decline, we may increase our borrowings or our
borrowing base may be adjusted downward, thereby reducing our borrowing
capacity. Our credit facility is secured by a pledge of substantially all of our
producing natural gas and oil properties assets, is guaranteed by our subsidiary
and contains covenants that limit additional borrowings, dividends to
nonpreferred shareholders, the incurrence of liens, investments, sales or
pledges of assets, changes in control, repurchases or redemptions for cash of
our common or preferred stock, speculative commodity transactions and other
matters. The credit facility also requires that specified financial ratios be
maintained. We may not be able to refinance our debt or obtain additional
financing, particularly in view of our credit facility restrictions on our
ability to incur additional debt and the fact that substantially all of our
assets are currently pledged to secure obligations under the credit facility.
The restrictions of our credit facility and our difficulty in obtaining
additional debt financing may have adverse consequences on our operations and
financial results including:
- our ability to obtain financing for working capital, capital
expenditures, our drilling program, purchases of new technology or
other purposes may be impaired;
- the covenants in our credit facility that limit our ability to borrow
additional funds and dispose of assets may affect our flexibility in
planning for, and reacting to, changes in business conditions;
- because our indebtedness is subject to variable interest rates, we are
vulnerable to increases in interest rates;
- any additional financing we obtain may be on unfavorable terms;
50
- we may be required to use a substantial portion of our cash flow to
make debt service payments, which will reduce the funds that would
otherwise be available for operations and future business
opportunities;
- a substantial decrease in our operating cash flow or an increase in
our expenses could make it difficult for us to meet debt service
requirements and could require us to modify our operations, including
by curtailing portions of our drilling program, selling assets,
reducing our capital expenditures, refinancing all or a portion of our
existing debt or obtaining additional financing; and
- we may become more vulnerable to downturns in our business or the
economy generally.
We may incur additional debt in order to fund our exploration and
development activities. A higher level of indebtedness increases the risk that
we may default on our debt obligations. Our ability to meet our debt obligations
and reduce our level of indebtedness depends on future performance. General
economic conditions, natural gas and oil prices and financial, business and
other factors, many of which are beyond our control, affect our operations and
our future performance. Our senior subordinated notes and senior subordinated
secured notes contain restrictive covenants similar to those under our credit
facility.
In addition, under the terms of our credit facility, our borrowing base is
subject to redeterminations at least semiannually based in part on prevailing
natural gas and oil prices. In the event the amount outstanding exceeds the
redetermined borrowing base, we could be forced to repay a portion of our
borrowings. We may not have sufficient funds to make any required repayment. If
we do not have sufficient funds and are otherwise unable to negotiate renewals
of our borrowings or arrange new financing, we may have to sell a portion of our
assets.
WE MAY RECORD CEILING LIMITATION WRITE-DOWNS THAT WOULD REDUCE OUR SHAREHOLDERS'
EQUITY.
We use the full-cost method of accounting for investments in natural gas
and oil properties. Accordingly, we capitalize all the direct costs of
acquiring, exploring for and developing natural gas and oil properties. Under
the full-cost accounting rules, the net capitalized cost of natural gas and oil
properties may not exceed a "ceiling limit" that is based upon the present value
of estimated future net revenues from proved reserves, discounted at 10%, plus
the lower of the cost or the fair market value of unproved properties. If net
capitalized costs of natural gas and oil properties exceed the ceiling limit, we
must charge the amount of the excess to operations through depreciation,
depletion and amortization expense. This charge is called a "ceiling limitation
write-down." This charge does not impact cash flow from operating activities but
does reduce our shareholders' equity. The risk that we will be required to write
down the carrying value of our natural gas and oil properties increases when
natural gas and oil prices are low or volatile. In addition, write-downs would
occur if we were to experience sufficient downward adjustments to our estimated
proved reserves or the present value of estimated future net revenues, as
further discussed in "Risk Factors--Our reserve data and estimated discount
future net cash flows are estimates based upon assumptions that may be
inaccurate and are based on existing economic and operating conditions that may
change in the future." Once incurred, a write-down of natural gas and oil
properties is not reversible at a later date. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Critical Accounting
Policies and Estimates" for additional information on these matters.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY RISK. Our major market risk exposure is the commodity pricing
applicable to our oil and natural gas production. Realized commodity prices
received for such production are primarily driven by the prevailing worldwide
price for oil and spot prices applicable to natural gas. The effects of such
pricing volatility have been discussed above, and such volatility is expected to
continue. A 10% fluctuation in the price received for oil and gas production
would have an approximate $5.1 million impact on our annual revenues and
operating income.
To mitigate some of this risk, we engage periodically in certain limited
hedging activities, including price swaps, costless collars and, occasionally,
put options, in order to establish some price floor protection. Costs and any
benefits derived from these price floors are accordingly recorded as a reduction
or increase, as applicable, in oil and gas sales revenue and were not
significant for any year presented. The costs to purchase put options are
amortized over the option period. We do not hold or issue derivative instruments
for trading purposes. Income and (losses) realized by us related to these
instruments were $(0.9 million), $(1.8 million), and $(1.0 million) or $(0.12),
$(0.46) and $(0.21) per MMBtu for the years ended December 31, 2002, 2003, and
2004, respectively.
INTEREST RATE RISK. Our exposure to changes in interest rates results from
our floating rate debt. In regards to our Credit Facility, the result of a 10%
fluctuation in short-term interest rates would have impacted 2004 cash flow by
approximately $0.2 million.
51
FINANCIAL INSTRUMENTS & DEBT MATURITIES. Our financial instruments consist
of cash and cash equivalents, accounts receivable, accounts payable, bank
borrowing, Senior Secured Notes and Senior Subordinated Notes. The carrying
amounts of cash and cash equivalents, accounts receivable and accounts payable
approximate fair value due to the highly liquid nature of these short-term
instruments. The fair values of the bank and vendor borrowings approximate the
carrying amounts as of December 31, 2004 and 2003, and were determined based
upon interest rates currently available to us for borrowings with similar terms.
Maturities of the debt are $0.1 million in 2005, $0.0 million in 2006, $18.0
million in 2007 and the balance in 2008.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The response to this item is included elsewhere in this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
In accordance with Exchange Act 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that, except as provided below,
our disclosure controls and procedures were effective as of December 31, 2004
to provide reasonable assurance that information required to be disclosed in
our reports filed or submitted under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the Securities and
Exchange Commission's rules and forms.
During the course of conducting the December 31, 2004 audit of the
consolidated financial statements, several accounting adjustments were
identified that individually and in the aggregate were not material. However,
these accounting adjustments are an indication of significant deficiencies in
our internal control that, upon complete assessment by management on or before
May 2, 2005, may become a material weakness. In addition, as a result of our
ongoing evaluation of internal control over financial reporting, and in
preparation for management's assessment, additional problems may be identified
that result in our disclosure controls and procedures not being effective at
December 31, 2004 for other reasons.
There has been no material change in our internal control over financial
reporting that occurred during the three months ended December 31, 2004 that has
materially affected, or is reasonably likely to materially affect, our internal
control over financial reporting.
We are relying on the exemption provided in the Order of the SEC in Release
No. 34-50754 (the "Order"). Accordingly, we have not included in this Annual
Report on Form 10-K either "Management's Annual Report on Internal Control Over
Financial Reporting," required by Item 308(a) of Regulation S-K, or the related
"Attestation Report of the Registered Public Accounting Firm," required by Item
308(b) of Regulation 8-K. We will file both of these reports pursuant to an
amendment to our Form 10-K on or before May 2, 2005, in accordance with the
Order.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated by reference to
information under the caption "Proposal 1-Election of Directors" and to the
information under the caption "Section 16(a) Reporting Delinquencies" in our
definitive Proxy Statement (the "2005 Proxy Statement") for our 2005 annual
meeting of shareholders. The 2005 Proxy Statement will be filed with the
Securities and Exchange Commission (the "Commission") not later than 120 days
subsequent to December 31, 2004.
Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to our executive officers is set forth in Part I of this
report.
ITEM 11. EXECUTIVE COMPENSATION
Salaries
Effective April 1, 2005, current annual salaries for Mr. Johnson, Mr.
Boling, Mr. Fisher and Mr. Trahan are $283,500, $173,250, $226,800 and
$173,845, respectively.
Other
The information required by this item is incorporated herein by reference
to the 2005 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2004.
52
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED SHAREHOLDER MATTERS
Information required by this item is incorporated herein by reference to
the 2005 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 2004.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is incorporated herein by reference
to the 2005 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 2004.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated by reference to the
2005 Proxy Statement, which will be filed with the Commission not later than 120
days subsequent to December 31, 2004.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(A)(1) FINANCIAL STATEMENTS
The response to this item is submitted in a separate section of this
report.
(A)(2) FINANCIAL STATEMENT SCHEDULES
All schedules and other statements for which provision is made in the
applicable regulations of the Commission have been omitted because they are not
required under the relevant instructions or are inapplicable.
53
(A)(3) EXHIBITS
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
+2.1 -- Combination Agreement by and among the Company, Carrizo Production,
Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners
Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas
A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1998
(Incorporated herein by reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+3.1 -- Amended and Restated Articles of Incorporation of the Company
(Incorporated herein by reference to Exhibit 3.1 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1998).
+3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment
No. 1 (Incorporated herein by reference to Exhibit 3.2 to the
Company's Registration Statement on Form 8-A (Registration No.
000-22915), Amendment No. 2 (Incorporated herein by reference to
Exhibit 3.2 to the Company's Current Report on Form 8-K dated December
15, 1999) and Amendment No. 3 (Incorporated herein by reference to
Exhibit 3.1 to the Company's Current Report on Form 8-K dated February
20, 2002).
+10.1 -- Amendment No. 1 to the Letter Agreement Regarding Participation in the
Company's 2001 Seismic and Acreage Program, dated June 1, 2001
(Incorporated herein by reference to Exhibit 4.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
+10.2 -- Amended and Restated Incentive Plan of the Company effective as of
February 17, 2000 (Incorporated herein by reference to Exhibit 10.3 to
the Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 2000).
+10.3 -- Amendment No. 1 to the Amended and Restated Incentive Plan of the
Company (Incorporated herein by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
2002).
+10.4 -- Amendment No. 2 to the Amended and Restated Incentive Plan of the
Company (Incorporated herein by reference to Exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year ended December 31,
2002).
+10.5 -- Amendment No. 3 to the Amended and Restated Incentive Plan of the
Company (Incorporated herein by reference to Appendix A to the
Company's Proxy Statement dated April 21, 2003).
+10.6 -- Amendment No. 4 to the Amended and Restated Incentive Plan of the
Company (incorporated herein by reference to Appendix B to the
Company's Proxy Statement dated April 26, 2004).
+10.7 -- Employment Agreement between the Company and S.P. Johnson IV
(Incorporated herein by reference to Exhibit 10.2 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.8 -- Employment Agreement between the Company and Kendall A. Trahan
(Incorporated herein by reference to Exhibit 10.4 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.9 -- Employment Agreement between the Company and J. Bradley Fisher
(Incorporated herein by reference to Exhibit 10.8 to the Company's
Registration Statement on Form S-2 (Registration No. 333-111475)).
+10.10 -- Employment Agreement between the Company and Paul F. Boling
(Incorporated herein by reference to Exhibit 10.9 to the Company's
Registration Statement on Form S-2 (Registration No. 333-111475)).
+10.11 -- Form of Indemnification Agreement between the Company and each of its
directors and executive officers (Incorporated herein by reference to
Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
+10.12 -- S Corporation Tax Allocation, Payment and Indemnification Agreement
among the Company and Messrs. Loyd, Webster, Johnson, Hamilton and
Wojtek (Incorporated herein by reference to Exhibit 10.8 to the
Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.13 -- S Corporation Tax Allocation, Payment and Indemnification Agreement
among Carrizo Production, Inc. and Messrs. Loyd, Webster, Johnson,
Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.9
to the Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.14 -- Form of Amendment to Executive Officer Employment Agreement.
(Incorporated herein by reference to Exhibit
54
99.3 to the Company's Current Report on Form 8-K dated January 8,
1998).
+10.15 -- Securities Purchase Agreement dated December 15, 1999 among the
Company, CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B.
Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated
herein by reference to Exhibit 99.1 to the Company's Current Report on
Form 8-K dated December 15, 1999).
+10.16 -- First Amendment to Securities Purchase Agreement dated as of June 7,
2004 among Carrizo Oil & Gas, Inc., Steelhead Investments Ltd.,
Douglas A.P. Hamilton, Paul B. Loyd, Jr., Steven A. Webster and Mellon
Ventures, L.P. (incorporated herein by reference to Exhibit 99.1 to
the Company's Current Report on Form 8-K filed on June 10, 2004).
+10.17 -- Form of Amended and Restated 9% Senior Subordinated Note due 2008
(incorporated herein by reference to Exhibit 99.2 to the Company's
Current Report on Form 8-K filed on June 10, 2004).
+10.18 -- Second Amendment to Securities Purchase Agreement dated as of October
29, 2004 among Carrizo Oil & Gas, Inc. and the Investors named therein
(incorporated herein by reference to Exhibit 10.7 to the Company's
Current Report on Form 8-K filed on November 3, 2004).
+10.19 -- Shareholders Agreement dated December 15, 1999 among the Company,
CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B. Loyd Jr.,
Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A.
Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference
to Exhibit 99.2 to the Company's Current Report on Form 8-K dated
December 15, 1999).
+10.20 -- First Amendment to Shareholders Agreement dated as of December 15,
1999 by and among Carrizo Oil & Gas, Inc, J.P. Morgan Partners (23A
SBIC), LLC, Mellon Ventures, L.P., S.P. Johnson IV, Frank A. Wojtek,
Steven A. Webster, Douglas A.P. Hamilton, Paul B. Loyd, Jr. and DAPHAM
Partnership, L.P. dated April 21, 2004 (incorporated herein by
reference to Exhibit 32 to the Schedule 13D/A filed by Paul B. Loyd,
Jr. on May 27, 2004).
+10.21 -- Second Amendment to Shareholders Agreement dated as of December 15,
1999 by and among Carrizo Oil & Gas, Inc., J.P. Morgan Partners (23A
SBIC), LLC, Mellon Ventures, L.P., S.P. Johnson IV, Frank A. Wojtek
and Steven A. Webster dated June 7, 2004 (incorporated herein by
reference to Exhibit 99.4 to the Company's Current Report on Form 8-K
filed on June 10, 2004).
+10.22 -- Registration Rights Agreement dated December 15, 1999 among the
Company, CB Capital Investors, L.P. and Mellon Ventures, L.P.
(Incorporated herein by reference to Exhibit 99.4 to the Company's
Current Report on Form 8- K dated December 15, 1999).
+10.23 -- Amended and Restated Registration Rights Agreement dated December 15,
1999 among the Company, Paul B. Loyd Jr., Douglas A. P. Hamilton,
Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM
Partnership, L.P. (Incorporated herein by reference to Exhibit 99.5 to
the Company's Current Report on Form 8-K dated December 15, 1999).
+10.24 -- Form of Amendment to Executive Officer Employment Agreement
(Incorporated herein by reference to Exhibit 99.7 to the Company's
Current Report on Form 8-K dated December 15, 1999).
+10.25 -- Form of Amendment to Director Indemnification Agreement
(Incorporated herein by reference to Exhibit 99.8 to the Company's
Current Report on Form 8-K dated December 15, 1999).
+10.26 -- Purchase and Sale Agreement by and between Rocky Mountain Gas, Inc.
and CCBM, Inc., dated June 29, 2001 (Incorporated herein by reference
to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2001).
+10.27 -- Securities Purchase Agreement dated February 20, 2002 among the
Company, Mellon Ventures, L.P. and Steven A. Webster (Incorporated
herein by reference to Exhibit 99.1 to the Company's Current Report on
Form 8-K dated February 20, 2002).
+10.28 -- Warrant Agreement dated February 20, 2002 among the Company, Mellon
Ventures, L.P. and Steven A. Webster (including Warrant Certificate)
(Incorporated herein by reference to Exhibit 99.4 to the Company's
Current Report on Form 8-K dated February 20, 2002).
+10.29 -- Registration Rights Agreement dated February 20, 2002 among the
Company, Mellon Ventures, L.P. and Steven A. Webster (Incorporated
herein by reference to Exhibit 99.5 to the Company's Current Report on
Form 8-K dated February 20, 2002).
+10.30 -- Form of Amendment to Executive Officer Employment Agreement
(Incorporated herein by reference to Exhibit 99.7 to the Company's
Current Report on Form 8-K dated February 20, 2002).
+10.31 -- Form of Amendment to Director Indemnification Agreement
(Incorporated herein by reference to Exhibit 99.8 to
55
the Company's Current Report on Form 8-K dated February 20, 2002).
+10.32 -- Contribution and Subscription Agreement dated June 23, 2003 by and
among Pinnacle Gas Resources, Inc., CCBM, Inc., Rocky Mountain Gas,
Inc. and the CSFB Parties listed therein (Incorporated herein by
reference to Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2003).
+10.33 -- Transition Services Agreement dated June 23, 2003 by and between the
Company and Pinnacle Gas Resources, Inc. (Incorporated herein by
reference to Exhibit 10.2 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2003).
+10.34 -- Second Amended and Restated Credit Agreement dated as of September 30,
2004 by and among Carrizo Oil & Gas, Inc., CCBM, Inc., Hibernia
National Bank, as Agent, Union Bank of California, N.A., as co-agent,
and Hibernia National Bank and Union Bank of California, N.A., as
lenders (incorporated herein by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K filed on October 6, 2004).
+10.35 -- First Amendment to Second Amended and Restated Credit Agreement dated
as of October 29, 2004 among Carrizo Oil & Gas, Inc., CCBM, Inc.,
Hibernia National Bank and Union Bank of California, N.A.
(incorporated herein by reference to Exhibit 10.6 to the Company's
Current Report on Form 8-K filed on November 3, 2004).
+10.36 -- Commercial Guaranty made and entered into as of September 30, 2004 by
CCBM, Inc. in favor of Hibernia National Bank, as agent (incorporated
herein by reference to Exhibit 10.2 to the Company's Current Report on
Form 8-K filed on October 6, 2004).
+10.37 -- Amended and Restated Stock Pledge and Security Agreement dated and
effective as of September 30, 2004 by Carrizo Oil & Gas, Inc. in favor
of Hibernia National Bank, as agent (incorporated herein by reference
to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on
October 6, 2004).
+10.38 -- Note Purchase Agreement dated as of October 29, 2004 among Carrizo
Oil & Gas, Inc., the Purchasers named therein and PCRL Investments
L.P., as collateral agent (incorporated herein by reference to Exhibit
10.1 to the Company's Current Report on Form 8-K filed on November 3,
2004).
+10.39 -- Form of 10% Senior Subordinated Secured Note due 2008 (incorporated
herein by reference to Exhibit 10.2 to the Company's Current Report on
Form 8-K filed on November 3, 2004).
+10.40 -- Stock Pledge and Security Agreement dated as of October 29, 2004 by
Carrizo Oil & Gas, Inc. in favor of PCRL Investments L.P., as
collateral agent (incorporated herein by reference to Exhibit 10.3 to
the Company's Current Report on Form 8-K filed on November 3, 2004).
+10.41 -- Commercial Guaranty dated as of October 29, 2004 by CCBM, Inc. in
favor of PCRL Investments L.P., guarantying the indebtedness of
Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit
10.4 to the Company's Current Report on Form 8-K filed on November 3,
2004).
+10.42 -- Registration Rights Agreement dated as of October 29, 2004 among
Carrizo Oil & Gas, Inc. and the Investors named therein (incorporated
herein by reference to Exhibit 10.5 to the Company's Current Report on
Form 8-K filed on November 3, 2004).
10.43 -- Form of Stock Option Award Agreement.
+10.44 -- Employment Agreement between the Company and Gregory E. Evans dated,
March 21, 2005 (incorporated herein by reference to Exhibit 10.1 to
the Company's Current Report on Form 8-K filed on March 22, 2005).
10.45 -- Director Compensation.
10.46 -- Base Salaries and 2004 Annual Bonuses for certain Executive Officers.
21.1 -- Subsidiaries of the Company.
23.1 -- Consent of Pannell Kerr Forster of Texas, P.C.
23.2 -- Consent of Ernst & Young LLP.
23.3 -- Consent of Ryder Scott Company Petroleum Engineers.
23.4 -- Consent of Fairchild & Wells, Inc.
23.5 -- Consent of DeGolyer and MacNaughton.
31.1 -- CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2 -- CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
56
32.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
32.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers as of December 31, 2004.
99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of December
31, 2004.
99.3 -- Summary of Reserve Report of DeGolyer and MacNaughton as of
December 31, 2004.
- ----------
+ Incorporated by reference as indicated.
57
CARRIZO OIL & GAS, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Carrizo Oil & Gas, Inc. --
Reports of Independent Registered Public Accounting Firms F-2
Consolidated Balance Sheets, December 31, 2003 and 2004 F-4
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2003 and 2004 F-5
Consolidated Statements of Shareholders' Equity for the
Years Ended December 31, 2002, 2003 and 2004 F-6
Consolidated Statements of Cash Flows for the
Years Ended December 31, 2002, 2003 and 2004 F-8
Notes to Consolidated Financial Statements F-9
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Carrizo Oil & Gas, Inc.
We have audited the accompanying consolidated balance sheet of Carrizo Oil &
Gas, Inc. as of December 31, 2003, and the related consolidated statements of
operations, shareholders' equity, and cash flows for each of the two years in
the period ended December 31, 2003. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits. The consolidated
financial statements of Carrizo Oil & Gas, Inc. as of December 31, 2001 and for
the year then ended, were audited by other auditors who have ceased operations
and whose report dated March 20, 2002, expressed an unqualified opinion on those
statements.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Carrizo Oil & Gas,
Inc. at December 31, 2003, and the consolidated results of its operations and
its cash flows for each of the two years in the period ended December 31, 2003,
in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2003, the Company changed its method of accounting for asset
retirement obligations.
(Ernst & Young LLP)
Houston, Texas
March 25, 2004
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders of
Carrizo Oil & Gas, Inc.
We have audited the accompanying consolidated balance sheet of Carrizo Oil
& Gas, Inc. as of December 31, 2004 and the related consolidated statements of
operations, shareholders' equity and cash flows for the year ended December 31,
2004. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Carrizo Oil &
Gas, Inc. at December 31, 2004, and the consolidated results of its operations
and its cash flows for the year then ended, in conformity with U.S. generally
accepted accounting principles.
PANNELL KERR FORSTER OF TEXAS, P.C.
Houston, Texas
March 15, 2005
F-3
CARRIZO OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31,
-------------------
2003 2004
-------- --------
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 3,322 $ 5,668
Accounts receivable, trade (net of allowance for doubtful accounts of
none and $325 at December 31, 2003 and 2004, respectively) 8,970 12,738
Advances to operators 1,877 1,614
Other current assets 156 1,614
-------- --------
Total current assets 14,325 21,634
PROPERTY AND EQUIPMENT, net-full-cost method of accounting for oil and
natural gas properties (including unevaluated costs of properties of
$32,978 and $45,067 at December 31, 2003 and 2004, respectively) 135,273 205,482
Investment in Pinnacle Gas Resources, Inc. 6,637 5,229
Deferred financing costs, net 479 1,633
Other assets 89 57
-------- --------
$156,803 $234,035
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 19,515 $ 21,358
Accrued liabilities 1,057 7,516
Advances for joint operations 3,430 1,808
Current maturities of long-term debt 1,037 90
Current maturities of seismic obligation payable 1,103 --
-------- --------
Total current liabilities 26,142 30,772
LONG-TERM DEBT 34,113 62,884
ASSET RETIREMENT OBLIGATION 883 1,407
DEFERRED INCOME TAXES 12,479 18,113
COMMITMENTS AND CONTINGENCIES (Note 10)
CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000
shares of preferred stock authorized, of which 150,000 are shares
designated as convertible participating shares, with 71,987 and
zero convertible participating shares issued and outstanding at
December 31, 2003 and 2004, respectively) (Note 9) 7,114 --
SHAREHOLDERS' EQUITY:
Warrants (3,262,821 and 334,210 outstanding at December 31, 2003
and 2004, respectively) 780 80
Common stock, par value $.01 (40,000,000 shares authorized with
14,591,348 and 22,161,457 issued and outstanding at December 31,
2003 and 2004, respectively) 146 221
Additional paid in capital 65,103 99,766
Retained earnings 10,229 20,733
Accumulated other comprehensive income (loss) (186) 59
-------- --------
Total shareholders' equity 76,072 120,859
-------- --------
$156,803 $234,035
======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
F-4
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------
2002 2003 2004
----------- ----------- -----------
(In thousands except for per
share amounts)
OIL AND NATURAL GAS REVENUES $ 26,802 $ 38,508 $ 51,374
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of
depletion, depreciation and amortization, shown separately below) 4,908 6,724 8,392
Depreciation, depletion and amortization 10,574 11,868 15,464
General and administrative 4,133 5,639 7,191
Accretion expenses related to asset retirement obligation -- 41 23
Stock option compensation (benefit) (84) 313 1,064
----------- ----------- -----------
Total costs and expenses 19,531 24,585 32,134
----------- ----------- -----------
OPERATING INCOME 7,271 13,923 19,240
OTHER INCOME AND EXPENSES:
Equity in loss of Pinnacle Gas Resources, Inc. -- (830) (1,399)
Other income and expenses 274 29 506
Interest income 55 58 75
Interest expense (846) (617) (2,553)
Interest expense, related parties (2,255) (2,379) (1,082)
Capitalized interest 3,100 2,919 2,938
----------- ----------- -----------
INCOME BEFORE INCOME TAXES 7,599 13,103 17,725
INCOME TAXES (Note 6) 2,809 5,063 6,871
----------- ----------- -----------
INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE 4,790 8,040 10,854
DIVIDENDS AND ACCRETION ON PREFERRED STOCK 588 741 350
----------- ----------- -----------
INCOME AVAILABLE TO COMMON SHAREHOLDERS
BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 4,202 7,299 10,504
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE,
NET OF INCOME TAXES -- (128) --
----------- ----------- -----------
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS $ 4,202 $ 7,171 $ 10,504
=========== =========== ===========
BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.30 $ 0.51 $ 0.53
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES -- (0.01) --
----------- ----------- -----------
BASIC EARNINGS PER COMMON SHARE $ 0.30 $ 0.50 $ 0.53
=========== =========== ===========
DILUTED EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE $ 0.26 $ 0.44 $ 0.48
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, NET OF INCOME TAXES -- (0.01) --
----------- ----------- -----------
DILUTED EARNINGS PER COMMON SHARE $ 0.26 $ 0.43 $ 0.48
=========== =========== ===========
WEIGHTED AVERAGE SHARES OUTSTANDING:
BASIC 14,158,438 14,311,820 19,958,452
=========== =========== ===========
DILUTED 16,148,443 16,744,296 21,818,065
=========== =========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
F-5
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
WARRANTS COMMON STOCK
------------------- -------------------
NUMBER AMOUNT SHARES AMOUNT
---------- ------ ---------- ------
BALANCE, January 1, 2002 3,010,189 $ 765 14,064,077 $141
Net income -- -- -- --
Net change in fair value of
hedging instruments -- -- -- --
---------- ----- ---------- ----
Comprehensive income
Warrants issued 252,632 15 -- --
Common stock issued -- -- 113,306 1
Dividends and accretion of discount
on preferred stock -- -- -- --
---------- ----- ---------- ----
BALANCE, December 31, 2002 3,262,821 780 14,177,383 142
---------- ----- ---------- ----
Net income -- -- -- --
Net charge in fair value of
hedging instruments -- -- -- --
---------- ----- ---------- ----
Comprehensive income
Common stock issued -- -- 413,965 4
Dividends and accretion of
discount on preferred stock -- -- -- --
---------- ----- ---------- ----
BALANCE, December 31, 2003 3,262,821 780 14,591,348 146
---------- ----- ---------- ----
Net income -- -- -- --
Net change in fair value of
hedging instruments -- -- -- --
---------- ----- ---------- ----
Comprehensive income
Warrants converted (2,836,605) (677) 2,067,621 20
Warrants exercised for cash (92,006) (23) 92,006 1
Common stock issued, secondary
offering, net of offering costs -- -- 3,655,500 37
Stock options exercised for cash -- -- 436,858 4
Preferred stock conversion -- -- 1,318,124 13
Tax benefit of stock options exercised -- -- -- --
Stock option compensation -- -- -- --
Dividends and accretion of
discount on preferred stock -- -- -- --
---------- ----- ---------- ----
BALANCE, December 31, 2004 334,210 $ 80 22,161,457 $221
========== ===== ========== ====
The accompanying notes are an integral part of these consolidated
financial statements.
F-6
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
ACCUMULATED
ADDITIONAL RETAINED OTHER
PAID IN COMPREHENSIVE EARNINGS COMPREHENSIVE SHAREHOLDERS'
CAPITAL INCOME (DEFICIT) INCOME (LOSS) EQUITY
---------- ------------- ------------------------- -------------
(Dollars in thousands)
BALANCE, January 1, 2002 $62,736 $(1,144) $ 706 $ 63,204
Net income -- $ 4,790 4,790 -- 4,790
Net change in fair value of
hedging instruments -- (1,094) -- (1,094) (1,094)
------- ------- ------- ------- --------
Comprehensive income $ 3,696
=======
Warrants issued -- -- -- 15
Common stock issued 488 -- -- 489
Dividends and accretion of
discount on preferred stock -- (588) -- (588)
------- ------- ------- --------
BALANCE, December 31, 2002 63,224 3,058 (388) 66,816
------- ------- ------- --------
Net income -- $ 7,912 7,912 -- 7,912
Net change in fair value of
hedging instruments -- 202 -- 202 202
------- ------- ------- ------- --------
Comprehensive income $ 8,114
=======
Common stock issued 1,879 -- -- 1,883
Dividends and accretion of
discount on preferred stock -- (741) -- (741)
------- ------- ------- --------
BALANCE, December 31, 2003 65,103 10,229 (186) 76,072
------- ------- ------- --------
Net income -- $10,854 10,854 -- 10,854
Net change in fair value of
hedging instruments -- 245 -- 245 245
------- ------- ------- ------- --------
Comprehensive income $11,099
=======
Warrants converted 657 -- -- --
Warrants exercised for cash 224 -- -- 202
Common stock issued, secondary
offering, net of offering costs 23,262 -- -- 23,299
Stock options exercised for cash 1,650 -- -- 1,654
Preferred stock conversion 7,452 -- -- 7,465
Tax benefit of stock options exercised 1,045 -- -- 1,045
Stock option compensation 373 -- -- 373
Dividends and accretion of
discount on preferred stock -- (350) (350)
------- ------- ------- --------
BALANCE, December 31, 2004 $99,766 $20,733 $ 59 $120,859
======= ======= ======= ========
F-7
CARRIZO OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2002 2003 2004
-------- -------- --------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Income before cumulative effect of change
in accounting principle $ 4,790 $ 8,040 $ 10,854
Adjustments to reconcile net income to net
cash provided by operating activities -
Depreciation, depletion and amortization 10,574 11,868 15,464
Provision for allowance for doubtful accounts -- -- 325
Accretion of discounts on asset retirement obligations and debt 86 161 177
Ineffective derivative instruments (706) 119 --
Stock option compensation (benefit) (84) 313 1,064
Equity in loss of Pinnacle Gas Resources, Inc. -- 830 1,399
Deferred income taxes 2,645 4,883 6,678
Other -- -- 296
Changes in assets and liabilities -
Accounts receivable 530 (762) (4,094)
Other assets (59) 335 (1,470)
Accounts payable 643 7,803 (689)
Accrued liabilities 153 41 2,497
-------- -------- --------
Net cash provided by operating activities 18,572 33,631 32,501
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (23,343) (31,930) (83,891)
Proceeds from the sale of oil and natural gas properties 355 -- --
Change in capital expenditure accrual (949) 1,755 4,955
Advances to operators 8 (1,377) 263
Advances for joint operations 1,182 1,879 (1,621)
-------- -------- --------
Net cash used in investing activities (22,747) (29,673) (80,294)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from sale of common stock:
Secondary offering, net of offering costs -- -- 23,299
Other 14 691 1,856
Net proceeds from sale of preferred stock 5,800 -- --
Net proceeds from debt issuance 8,613 -- 16,200
Advances under borrowing base facility -- -- 24,000
Debt repayments (8,745) (5,951) (13,737)
Deferred loan costs -- -- (1,479)
Loss on ineffective derivatives -- (119) --
-------- -------- --------
Net cash provided by (used in) financing activities 5,682 (5,379) 50,139
-------- -------- --------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 1,507 (1,421) 2,346
CASH AND CASH EQUIVALENTS, beginning of year 3,236 4,743 3,322
-------- -------- --------
CASH AND CASH EQUIVALENTS, end of year $ 4,743 $ 3,322 $ 5,668
======== ======== ========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized) $ 1 $ 77 $ 697
======== ======== ========
Cash paid for income taxes $ -- $ -- $ --
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-8
CARRIZO OIL & GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS
Carrizo Oil & Gas, Inc. (Carrizo, a Texas corporation; together with its
subsidiary, affiliates and predecessors, the Company) is an independent energy
company formed in 1993 and is engaged in the exploration, development,
exploitation and production of oil and natural gas. Its operations are focused
along the onshore Gulf Coast of Texas and Louisiana, primarily the Frio, Wilcox
and Vicksburg trends and in the Barnett Shale trend in North Texas. The Company,
through CCBM, Inc. (a wholly-owned subsidiary) ("CCBM"), acquired interests in
certain oil and natural gas leases in Wyoming and Montana in areas prospective
for coalbed methane. During 2003, the Company obtained offshore licensees to
explore in the U.K. North Sea and acquired interests in the Barnett Shale trend
located in Tarrant and Parker counties in North Texas.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statement are presented in accordance with U.S.
generally accepted accounting principles . The consolidated financial statements
include the accounts of the Company and its wholly-owned subsidiary. All
intercompany accounts and transactions have been eliminated in consolidation.
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY
The Company's investment in Pinnacle Gas Resources, Inc. ("Pinnacle") is
recorded using the equity method of accounting. Under this method, the
investment is recorded at cost initially, and the investment is adjusted for the
Company's equity in the subsidiary's profit or loss. The investment is further
adjusted for additional contributions to and distributions from the subsidiary.
The Company would also record any loss in fair value of the investment
other than a temporary decline.
RECLASSIFICATIONS
Certain reclassifications have been made to prior periods' financial
statements to conform to the current presentation.
CRITICAL ACCOUNTING POLICIES AND USE OF ESTIMATES
The preparation of financial statements in conformity with U. S. generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenues and expenses during
the reporting periods. Actual results could differ from these estimates.
SIGNIFICANT ESTIMATES
Significant estimates include volumes of oil and natural gas reserves used
in calculating depletion of proved oil and natural gas properties, future net
revenues and abandonment obligations, impairment of undeveloped properties,
future income taxes and related assets/liabilities, bad debts, derivatives,
contingencies and litigation. Oil and natural gas reserve estimates, which are
the basis for unit-of-production depletion and the ceiling test, have numerous
inherent uncertainties. The accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Results of drilling, testing and production subsequent to the date
of the estimate may justify revision of such estimate. Accordingly, reserve
estimates are often different from the quantities of oil and natural gas that
are ultimately recovered. In addition, reserve estimates are vulnerable to
changes in wellhead prices of crude oil and natural gas. Such prices have been
volatile in the past and can be expected to be volatile in the future.
The significant estimates are based on current assumptions that may be
materially effected by changes to future economic conditions such as the market
prices received for sales of volumes of oil and natural gas, interest rates, the
market value of the Company's common stock and corresponding volatility and the
Company's ability to generate future taxable income. Future changes to these
assumptions may affect these significant estimates materially in the near term.
F-9
The Company believes the following critical accounting policies affect its
more significant judgments and estimates used in the preparation of its
consolidated financial statements:
OIL AND NATURAL GAS PROPERTIES
Investments in oil and natural gas properties are accounted for using the
full-cost method of accounting. All costs directly associated with the
acquisition, exploration and development of oil and natural gas properties are
capitalized. Such costs include lease acquisitions, seismic surveys, and
drilling and completion equipment. The Company proportionally consolidates its
interests in oil and natural gas properties. The Company capitalized
compensation costs for employees working directly on exploration activities of
$1.0 million, $1.4 million and $1.7 million in 2002, 2003 and 2004,
respectively. Maintenance and repairs are expensed as incurred.
Oil and natural gas properties are amortized based on the
unit-of-production method using estimates of proved reserve quantities.
Investments in unproved properties are not amortized until proved reserves
associated with the projects can be determined or until they are impaired.
Unevaluated properties are evaluated periodically for impairment on a
property-by-property basis. If the results of an assessment indicate that the
properties are impaired, the amount of impairment is added to the proved oil and
natural gas property costs to be amortized. The amortizable base includes
estimated future development costs and, dismantlement, restoration and
abandonment costs, net of estimated salvage values. The depletion rate per Mcfe
for 2002, 2003 and 2004 was $1.41, $1.55 and $1.86, respectively.
Dispositions of oil and natural gas properties are accounted for as
adjustments to capitalized costs with no gain or loss recognized, unless such
adjustments would significantly alter the relationship between capitalized costs
and proved reserves.
The net capitalized costs of proved oil and natural gas properties are
subject to a "ceiling test" which limits such costs to the estimated present
value, discounted at a 10% interest rate, of future net revenues from proved
reserves, based on current economic and operating conditions. If net capitalized
costs exceed this limit, the excess is charged to operations through
depreciation, depletion and amortization. During the year-end close of 2003, a
computational error was identified in the ceiling test calculation which
overstated the tax basis used in the computation to derive the after-tax present
value (discounted at 10%) of future net revenues from proved reserves. This tax
basis error was also present in each of the previous ceiling test computations
dating back to 1997. This error only affected the after-tax computation, used in
the ceiling test calculation and the unaudited supplemental oil and natural gas
disclosure and did not impact: (1) the pre-tax valuation of the present value
(discounted at 10%) of future net revenues from proved reserves, (2) the proved
reserve volumes, (3) our EBITDA or our future cash flows from operations, (4)
the net deferred tax liability, (5) the estimated tax basis in oil and natural
gas properties, or (6) the estimated tax net operating losses.
After discovering this computational error, the ceiling tests for all
quarters since 1997 were recomputed and it was determined that no write-down of
oil and natural gas assets was necessary in any of the years from 1997 to 2003.
However, based upon the oil and natural gas prices in effect on March 31, 2003
and September 30, 2003, the unamortized cost of oil and natural gas properties
exceeded the cost center ceiling. As permitted by full cost accounting rules,
improvements in pricing and/or the addition of proved reserves subsequent to
those dates sufficiently increased the present value of the oil and natural gas
assets and removed the necessity to record a write-down in these periods. Using
the prices in effect and estimated proved reserves on March 31, 2003 and
September 30, 2003, the after-tax write-down would have been approximately $1.0
million and $6.3 million, respectively, had we not taken into account the
subsequent improvements. These improvements at September 30, 2003 included
estimated proved reserves attributable to our Shady Side # 1 well. Because of
the volatility of oil and natural gas prices, no assurance can be given that we
will not experience a write-down in future periods.
Depreciation of other property and equipment is provided using the
straight-line method based on estimated useful lives ranging from five to 10
years.
OIL AND NATURAL GAS RESERVE ESTIMATES
The process of estimating quantities of proved reserves is inherently
uncertain, and the reserve data included in this document are estimates prepared
by Ryder Scott Company, DeGolyer and MacNaughton and Fairchild & Wells, Inc.,
independent petroleum engineers. Reserve engineering is a subjective process of
estimating underground accumulations of hydrocarbons that cannot be measured in
an exact manner. The process relies on interpretation of available geologic,
geophysical, engineering and production data. The extent, quality and
reliability of this data can vary. The process also requires certain economic
assumptions regarding drilling and operating expense, capital expenditures,
taxes and availability of funds. The SEC mandates some of these assumptions such
as oil and natural gas prices and the present value discount rate.
F-10
Proved reserve estimates prepared by others may be substantially higher or
lower than the Company's estimates. Because these estimates depend on many
assumptions, all of which may differ from actual results, reserve quantities
actually recovered may be significantly different than estimated. Material
revisions to reserve estimates may be made depending on the results of drilling,
testing, and rates of production.
You should not assume that the present value of future net cash flows is
the current market value of the Company's estimated proved reserves. In
accordance with SEC requirements, the Company based the estimated discounted
future net cash flows from proved reserves on market prices and costs on the
date of the estimate.
The Company's rate of recording depreciation, depletion and amortization
expense for proved properties is dependent on the Company's estimate of proved
reserves. If these reserve estimates decline, the rate at which the Company
records these expenses will increase.
The Company's full cost ceiling test also depends on the Company's estimate
of proved reserves. If these reserve estimates decline, the Company may be
subjected to a full cost ceiling write-down.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include highly liquid investments with maturities
of three months or less when purchased.
REVENUE RECOGNITION AND NATURAL GAS IMBALANCES
The Company follows the sales method of accounting for revenue recognition
and natural gas imbalances, which recognizes over and under lifts of natural gas
when sold, to the extent sufficient natural gas reserves or balancing agreements
are in place. Natural gas sales volumes are not significantly different from the
Company's share of production.
FINANCING COSTS
Long-term debt financing costs of $0.5 million and $1.6 million are
included in other assets as of December 31, 2003 and 2004, respectively, and are
being amortized using the effective yield method over the term of the loans
(through September 30, 2007 for the credit facility and through December 15,
2008 for both the Senior Subordinated Notes payable and the Senior Subordinated
Secured Notes payable).
SUPPLEMENTAL CASH FLOW INFORMATION
The Statement of Cash Flows for the year ended December 31, 2002 does not
reflect the following non-cash transactions: the $2.5 million acquisition of
seismic data, the $0.5 million acquisition of oil and natural gas properties
through the issuance of common stock, and the $0.6 million reduction of oil and
natural gas properties for the amount of insurance recoveries expected to be
received related to difficulties encountered in the drilling of a well. The
Statement of Cash Flows for the year ended December 31, 2003 does not include
the acquisition of $1.2 million of seismic data through the issuance of common
stock, and the $0.2 million non-cash cumulative effect recorded in connection
with the implementation of Statement of Financial Accounting Standards (SFAS)
No. 143, "Accounting for Asset Retirement Obligations." The Statement of Cash
Flows for the year ended December 31, 2004 does not include the net exercise of
$0.7 million of warrants and the conversion of $7.5 million of preferred stock
into common stock and the $0.3 relinquishment of interests in certain leases to
RMG in lieu of principal payments on a note payable.
FINANCIAL INSTRUMENTS
The Company's recorded financial instruments consist of cash, receivables,
payables and long-term debt. The carrying amount of cash, receivables and
payables approximates fair value because of the short-term nature of these
items. The carrying amount of bank debt approximates fair value as this
borrowing bears interest at variable interest rates. The fair value of the 9%
Senior Subordinated Notes payable and the 10% Senior Subordinated Secured Notes
payable at December 31, 2004 was $28.8 million and $18.0 million, respectively.
Fair values of these subordinated notes payable were determined based upon
interest rates available to the Company at December 31, 2004 with similar terms.
F-11
STOCK-BASED COMPENSATION
The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board (APB) Opinion
No. 25, "Accounting for Stock Issued to Employees" and related interpretations.
Under this method, the Company records no compensation expense for stock options
granted when the exercise price of those options is equal to or greater than the
market price of the Company's common stock on the date of grant. As allowed by
SFAS No. 123, "Accounting for Stock Based Compensation," the Company has
continued to apply APB No. 25 for the purposes of determining net income.
In December 2002, the Financial Accounting Standards Board (FASB) issued
SFAS No. 148, "Accounting for Stock Based Compensation - Transition and
Disclosure, an amendment of SFAS No. 123." The Company has adopted the
disclosure requirements of SFAS No. 148 and has elected to record employee
compensation expense utilizing the intrinsic value method permitted under APB
25. The Company accounts for its employees' stock-based compensation plan under
APB Opinion No. 25 and its related interpretations. Accordingly, any deferred
compensation expense would be recorded for stock options based on the excess of
the market value of the common stock on the date the options were granted over
the aggregate exercise price of the options. This deferred compensation would be
amortized over the vesting period of each option to the extent that the market
value exceeds the exercise price of the option. Had compensation cost been
determined consistent with SFAS No. 123 "Accounting for Stock Based
Compensation" for all options, the Company's net income and earnings per share
would have been as follows:
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2002 2003 2004
------ ------ -------
(In thousands except per
share amounts)
Income available to common shareholders
before cumulative effect of change in accounting
principle as reported $4,202 $7,299 $10,504
Add: Stock-based employee compensation
expense (benefit) recognized, net of tax -- -- 691
Less: Total stock-based employee
compensation expense determined under fair
value method for all awards, net of tax (872) (662) (578)
------ ------ -------
Pro forma income available to common
shareholders before cumulative effect of change
in accounting principle $3,330 $6,637 $10,617
====== ====== =======
Income available to common shareholders before
cumulative effect of change in accounting
principle per common share, as reported:
Basic $ 0.30 $ 0.51 $ 0.53
Diluted 0.26 0.44 0.48
Pro Forma income available to common shareholders
before cumulative effect of change in accounting
principle per common share, as if the fair value
method had been applied to all awards:
Basic $ 0.24 $ 0.46 $ 0.53
Diluted 0.21 0.40 0.49
Repriced options are accounted for as compensatory options using variable
accounting treatment in accordance with FASB Interpretation No. 44, "Accounting
for Certain Transactions involving Stock Based Compensation - on Interpretation
of APB No. 25" (FIN 44). Under variable plan accounting, compensation expense is
adjusted for increases or decreases in the fair market value of the
F-12
Company's common stock to the extent that the market value exceeds the exercise
price of the option. Variable plan accounting is applied to the repriced options
until the options are exercised, forfeited, or expire unexercised (See Note 11).
The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option pricing model with the following assumptions used
for grants in 2002, 2003 and 2004: risk free interest rate of 4.8%, 4.0%, and
4.3% respectively, expected dividend yield of 0%, expected life of 10 years and
expected volatility of 77.7%, 72.2% and 43.2%, respectively.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Upon entering into a derivative contract, the Company designates the
derivative instruments as a hedge of the variability of cash flow to be received
(cash flow hedge). Changes in the fair value of a cash flow hedge are recorded
in other comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as oil and
natural gas revenues when the forecasted transaction occurs. All of the
Company's derivative instruments at December 31, 2002, 2003 and 2004 were
designated as cash flow hedges.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is discontinued,
the derivative will be carried at fair value on the balance sheet with future
changes in its fair value recognized in future earnings. See Note 13 with
respect to the Company's positions with an affiliate of Enron Corp.
The Company typically uses fixed rate swaps and costless collars to hedge
its exposure to material changes in the price of oil and natural gas. The
Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated cash flow hedges to forecasted transactions. The
Company also formally assesses, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions.
The Company's Board of Directors sets all of the Company's hedging policy,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by either the President or Chief Financial Officer after consultation and
concurrence by the President, Chief Financial Officer and Chairman of the Board.
The master contracts with the authorized counterparties identify the President
and Chief Financial Officer as the only Company representatives authorized to
execute trades. The Board of Directors also reviews the status and results of
hedging activities quarterly.
INCOME TAXES
Under SFAS No. 109, "Accounting for Income Taxes," deferred income taxes
are recognized for the future tax consequences of differences between the tax
bases of assets and liabilities and their financial reporting amounts based on
tax laws and statutory tax rates applicable to the periods in which the
differences are expected to affect taxable income. Valuation allowances are
established when necessary to reduce deferred tax assets to the amounts expected
to be realized.
CONCENTRATION OF CREDIT RISK
Substantially all of the Company's accounts receivable result from oil and
natural gas sales or joint interest billings to third parties in the oil and
natural gas industry. This concentration of customers and joint interest owners
may impact the Company's overall credit risk in that these entities may be
similarly affected by changes in economic and other industry conditions. The
Company does not require collateral from its customers and the Company has not
experienced material credit losses on such receivables. Further, the Company
generally has the right to offset revenue against related billings to joint
interest owners. Derivative contracts subject the Company to a concentration of
credit risk. The Company transacts the majority of its derivative contracts with
two counterparties.
MAJOR CUSTOMERS
The Company sold oil and natural gas production representing more than 10%
of its oil and natural gas revenues as follows:
F-13
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2002 2003 2004
---- ---- ----
WMJ Investments Corp. -- 16% 12%
Cokinos Natural Gas Company 12% 15% 17%
Gulfmark Energy, Inc. -- 14% --
Texon L.P. -- -- 13%
Discovery Producer Services, LLC. 10% -- --
EARNINGS PER SHARE
Supplemental earnings per share information is provided below:
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
(In thousands except share and per share amounts)
INCOME SHARES PER-SHARE AMOUNT
----------------------- ---------------------------------- -------------------
2002 2003 2004 2002 2003 2004 2002 2003 2004
------ ------ ------- ---------- ---------- ---------- ----- ----- -----
Basic Earnings per Common Share
Income available to common shareholders
before cumulative effect of change in
accounting principle $4,202 $7,299 $10,504 14,158,438 14,311,820 19,958,452 $0.30 $0.51 $0.53
===== ===== =====
Dilutive effect of Stock Options, Warrants
and Preferred Stock conversions -- -- -- 1,990,005 2,432,476 1,859,613
------ ------ ------- ---------- ---------- ----------
Diluted Earnings per Share
Income available to common shareholders
plus assumed conversions before
cumulative effect of change in
accounting principle $4,202 $7,299 $10,504 16,148,443 16,744,296 21,818,065 $0.26 $0.44 $0.48
====== ====== ======= ========== ========== ========== ===== ===== =====
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------------------
(In thousands except share and per share amounts)
INCOME SHARES PER-SHARE AMOUNT
----------------- ---------------------------------- ----------------------------------
2002 2003 2004 2002 2003 2004 2002 2003 2004
---- ----- ---- ---------- ---------- ---------- ---------- ---------- ----------
Cumulative effect of change in accounting
principle net of income taxes Basic
Earnings per Common Share Net loss
available to common shareholders $-- $(128) $-- 14,158,438 14,311,820 19,958,452 $0.00 $(0.01) $0.00
===== ====== =====
Dilutive effect of Stock Options,
Warrants and Preferred Stock
conversions -- -- -- 1,990,005 2,432,476 1,859,613
---- ----- ---- ---------- ---------- ----------
Diluted Earnings per Share Cumulative
effect of change in accounting
principle net of income taxes plus
assumed conversions $-- $(128) $-- 16,148,443 16,744,296 21,818,065 $0.00 $(0.01) $0.00
=== ===== === ========== ========== ========== ===== ====== =====
F-14
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
(In thousands except share and per share amounts)
INCOME SHARES PER-SHARE AMOUNT
----------------------- ---------------------------------- -------------------
2002 2003 2004 2002 2003 2004 2002 2003 2004
------ ------ ------- ---------- ---------- ---------- ----- ----- -----
Basic Earnings per Common Share
Net income available to common
shareholders $4,202 $7,171 $10,504 14,158,438 14,311,820 19,958,452 $0.30 $0.50 $0.53
===== ===== =====
Dilutive effect of Stock Options,
Warrants and Preferred Stock
conversions -- -- -- 1,990,005 2,432,476 1,859,613
------ ------ ------- ---------- ---------- ----------
Diluted Earnings per Share
Net income available to common
shareholders plus assumed
conversions $4,202 $7,171 $10,504 16,148,443 16,744,296 21,818,065 $0.26 $0.43 $0.48
====== ====== ======= ========== ========== ========== ===== ===== =====
Basic earnings per common share is based on the weighted average number of
shares of common stock outstanding during the periods. Diluted earnings per
common share is based on the weighted average number of common shares and all
dilutive potential common shares outstanding during the period. The Company had
outstanding 172,333, 117,000 and 30,000 stock options at December 31, 2002, 2003
and 2004, respectively, that were antidilutive. The Company had outstanding
252,632 warrants at December 31, 2002 that were antidilutive. These antidilutive
stock options and warrants were not included in the calculation because the
exercise price of these instruments exceeded the underlying market value of the
options and warrants as of the dates presented. The Company had 1,145,515 and
1,262,930 convertible preferred shares at December 31, 2002 and 2003,
respectively, that were antidilutive and were not included in the calculation.
CONTINGENCIES
Liabilities and other contingencies are recognized upon determination of an
exposure, which when analyzed indicates that it is both probable that an asset
has been impaired or that a liability has been incurred and that the amount of
such loss is reasonably estimable.
ASSET RETIREMENT OBLIGATION
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 requires that an asset retirement
obligation (ARO) associated with the retirement of a tangible long-lived asset
be recognized as a liability in the period in which a legal obligation is
incurred and becomes determinable, with an offsetting increase in the carrying
amount of the associated asset. The cost of the tangible asset, including the
initially recognized ARO, is depleted such that the cost of the ARO is
recognized over the useful life of the asset. The ARO is recorded at fair value,
and accretion expense will be recognized over time as the discounted liability
is accreted to its expected settlement value. The fair value of the ARO is
measured using expected future cash outflows discounted at the company's
credit-adjusted risk-free interest rate.
The Company adopted SFAS No. 143 on January 1, 2003, which resulted in an
increase to net oil and natural gas properties of $0.4 million and additional
liabilities related to asset retirement obligations of $0.6 million. These
amounts reflect the ARO of the Company had the provisions of SFAS No. 143 been
applied since inception and resulted in a non-cash cumulative effect decrease to
earnings of $0.1 million ($0.2 million pretax). In accordance with the
provisions of SFAS No. 143, the Company records an abandonment liability
associated with its oil and natural gas wells when those assets are placed in
service, rather than its past practice of accruing the expected undiscounted
abandonment costs on a unit-of-production basis over the productive life of the
associated full cost pool. Under SFAS No. 143, depletion expense is reduced
since a discounted ARO is depleted in the property balance rather than the
undiscounted value previously depleted under the old rules. The lower depletion
expense under SFAS No. 143 is offset, however, by accretion expense, which is
recognized over time as the discounted liability is accreted to its expected
settlement value.
Inherent in the fair value calculation of ARO are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the fair value of the existing ARO
liability, a corresponding adjustment is made to the oil and natural gas
property balance. Settlements greater than or less then amounts accrued with the
ARO are recovered as a gain or loss upon settlement.
The following table is a reconciliation of the asset retirement obligation
liability since adoption:
F-15
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2003 2004
---- ------
(in thousands)
Asset retirement obligation at beginning of year $597 $ 883
Liabilities incurred 91 425
Liabilities settled -- (29)
Accretion expense 42 23
Revisions in estimated liabilities 153 105
---- ------
Asset retirement obligation at end of year $883 $1,407
==== ======
The following table shows the pro forma effect of the implementation on the
Company's income available to common shareholders before cumulative effect of
change in accounting principle had SFAS No. 143 been adopted by the Company on
January 1, 2002.
FOR THE YEAR ENDED
DECEMBER 31,
2002
---------------------
(In thousands, except
per share data)
Income Available to Common Shareholders $4,202
Effect on Net Income had SFAS No. 143 been applied (37)
------
Income Attributable to Common Stock before Cumulative
Effect of Change in Accounting Principle $4,165
======
Basic Net Income per Common Share:
Net Income $ 0.30
Effect on Net Income had SFAS No. 143 been applied --
------
Net Income $ 0.30
======
Diluted Net Income per Common Share:
Net Income $ 0.26
Effect on Net Income had SFAS No. 143 been applied --
------
Net Income $ 0.26
======
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004),
"Share-Based Payment" ("SFAS No. 123(R)"). SFAS No. 123(R) will require
companies to measure all employee stock-based compensation awards using a fair
value method and record such expense in their consolidated financial statements.
In addition, the adoption of SFAS No. 123(R) requires additional accounting and
disclosure related to the income tax and cash flow effects resulting from
share-based payment arrangements. SFAS No. 123(R) is effective beginning as of
the first interim or annual reporting period beginning after June 15, 2005. The
Company believes it is likely that the impact of the requirements of SFAS No.
123(R) will significantly impact the Company's future results of operations and
continues to evaluate it to determine the degree of significance.
In December 2004, SFAS No. 153, "Exchanges of Nonmonetary Assets - an
Amendment of APB Opinion No. 29" is effective for fiscal years beginning after
June 15, 2005. This statement addresses the measurement of exchange of
nonmonetary assets and eliminates the exception from fair value measurement for
nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB
Opinion No. 29, "Accounting for Nonmonetary Transactions" and replaces it with
an exception for exchanges that do not have commercial substance. The Company
expects the adoption of SFAS No. 153 to have no impact on its consolidated
financial statements.
F-16
In October 2004, the SEC released SAB 106, which expresses the staff's
views on the application of SFAS No. 143 by oil and gas producing companies
following the full cost accounting method. SAB 106 provides interpretive
responses related to computing the full cost ceiling to avoid double counting
the expected future cash outflows associated with asset retirement obligations,
required disclosure relating to the interaction of SFAS No. 143 and the full
cost rules, and the impact of SFAS No. 143 on the calculation of depreciation,
depletion and amortization. The Company is in the process of determining the
impact of the requirements of SAB 106.
3. INVESTMENT IN MICHAEL PETROLEUM CORPORATION
In 2000, the Company received a finder's fee valued at $1.5 million from
affiliates of Donaldson, Lufkin & Jenrette ("DLJ") in connection with their
purchase of a significant minority shareholder interest in Michael Petroleum
Corporation ("MPC"). MPC is a privately held exploration and production company
which focuses on the natural gas producing Lobo Trend in South Texas. The
minority shareholder interest in MPC was purchased by entities affiliated with
DLJ. The Company elected to receive the fee in the form of 18,947 shares of
common stock, 1.9% of the outstanding common shares of MPC, which, until its
sale in 2001, was accounted for as a cost basis investment. Steven A. Webster,
who is the Chairman of the Board of the Company, and a Managing Director of
Global Energy Partners Ltd., a merchant banking affiliate of DLJ which makes
investments in energy companies, joined the Board of Directors of MPC in
connection with the transaction.
In 2001, the Company agreed to sell its interest in MPC pursuant to an
agreement between MPC and its shareholders for the sale of a majority interest
in MPC to Calpine Natural Gas Company. The Company received total cash proceeds
of $5.7 million, of which $5.5 million was paid to the Company during the third
quarter of 2001, resulting in a financial statement gain of $3.9 million being
reflected in the third quarter 2001 financial results. The remaining amounts
were paid in 2003.
4. INVESTMENT IN PINNACLE GAS RESOURCES, INC.
THE PINNACLE TRANSACTION
On June 23, 2003, pursuant to a Subscription and Contribution Agreement by
and among the Company and its wholly-owned subsidiary, CCBM, Inc., Rocky
Mountain Gas, Inc. ("RMG") and the Credit Suisse First Boston Private Equity
entities, named therein (the "CSFB Parties"), CCBM and RMG contributed their
respective interests, having a estimated fair value of approximately $7.5
million each, in (1) leases in the Clearmont, Kirby, Arvada and Bobcat project
areas and (2) oil and natural gas reserves in the Bobcat project area to a newly
formed entity, Pinnacle Gas Resources, Inc., a Delaware corporation. In exchange
for the contribution of these assets, CCBM and RMG each received 37.5% of the
common stock of Pinnacle ("Pinnacle Common Stock") as of the closing date and
options to purchase Pinnacle Common Stock ("Pinnacle Stock Options"). CCBM no
longer has a drilling obligation in connection with the oil and natural gas
leases contributed to Pinnacle.
Simultaneously with the contribution of these assets, the CSFB Parties
contributed approximately $17.6 million of cash to Pinnacle in return for the
Redeemable Preferred Stock of Pinnacle ("Pinnacle Preferred Stock"), 25% of the
Pinnacle Common Stock as of the closing date and warrants to purchase Pinnacle
Common Stock ("Pinnacle Warrants"). The CSFB Parties also agreed to contribute
additional cash, under certain circumstances, of up to approximately $11.8
million to Pinnacle to fund future drilling, development and acquisitions. The
CSFB Parties currently have greater than 50% of the voting power of the Pinnacle
capital stock through their ownership of Pinnacle Common Stock and Pinnacle
Preferred Stock.
Immediately following the contribution and funding, Pinnacle used
approximately $6.2 million of the proceeds from the funding to acquire an
approximate 50% working interest in existing leases and acreage prospective for
coalbed methane development in the Powder River Basin of Wyoming from Gastar
Exploration, Ltd. Pinnacle also agreed to fund up to $14.9 million of future
drilling and development costs on these properties on behalf of Gastar prior to
December 31, 2005. The drilling and development work will be done under the
terms of an earn-in joint venture agreement between Pinnacle and Gastar. The
majority of these leases are part of, or adjacent to, the Bobcat project area.
All of CCBM and RMG's interests in the Bobcat project area, the only producing
coalbed methane property owned by CCBM prior to the transaction, were
contributed to Pinnacle.
Prior to and in connection with its contribution of assets to Pinnacle,
CCBM paid RMG approximately $1.8 million in cash as part of its outstanding
purchase obligation on the coalbed methane property interests CCBM previously
acquired from RMG. As of June 30, 2003, approximately $1.1 million of the
remaining balance of CCBM's obligation to RMG was scheduled to be paid in
monthly installments of approximately $52,805 through November 2004 and a
balloon payment on December 31, 2004, all of which were paid. The RMG note was
secured solely by CCBM's interests in the remaining oil and natural gas leases
in Wyoming and Montana. In
F-17
connection with the Company's investment in Pinnacle, the Company received a
reduction in the principal amount of the RMG note of approximately $1.5 million
and relinquished the right to receive certain revenues related to the properties
contributed to Pinnacle.
CCBM continues its coalbed methane business activities and, in addition to
its interest in Pinnacle, owns direct interests in acreage in coalbed methane
properties in the Castle Rock project area in Montana and the Oyster Ridge
project area in Wyoming, which were not contributed to Pinnacle. CCBM and RMG
will continue to conduct exploration and development activities on these
properties as well as pursue other potential acquisitions. Other than indirectly
through Pinnacle, CCBM currently has no proved reserves of, and is no longer
receiving revenue from, coalbed methane gas.
As of December 31, 2004, on a fully diluted basis, assuming that all
parties exercised their Pinnacle Warrants and Pinnacle Stock Options, the CSFB
Parties, CCBM and RMG would have ownership interests of approximately 54.6%,
22.7% and 22.7%, respectively. In March 2004, the CSFB Parties contributed
additional funds of $11.8 million into Pinnacle to continue funding the 2004
development program which increased their ownership to 66.7% on a fully diluted
basis should CCBM and RMG each elect not to exercise their available options.
For accounting purposes, the transaction was treated as a reclassification
of a portion of CCBM's investments in the contributed properties to an
investment in Pinnacle Gas Resources, Inc. The property contribution made by
CCBM to Pinnacle is intended to be treated as a tax-deferred exchange as
constituted by property transfers under section 351(a) of the Internal Revenue
Code of 1986, as amended.
The reclassification of investments in contributed properties resulting
from the transaction with Pinnacle are reflected in accordance with the full
cost method of accounting in the Company's December 31, 2003 balance sheet
included in this Form 10-K.
5. PROPERTY AND EQUIPMENT
At December 31, 2003 and 2004, property and equipment consisted of the
following:
AS OF DECEMBER 31,
-------------------
2003 2004
-------- --------
(IN THOUSANDS)
Proved oil and natural gas properties $168,329 $241,746
Unproved oil and natural gas properties 32,978 45,067
Other equipment 742 846
-------- --------
Total property and equipment 202,049 287,659
Accumulated depreciation, depletion and amortization (66,776) (82,177)
-------- --------
Property and equipment, net $135,273 $205,482
======== ========
Oil and natural gas properties not subject to amortization consist of the
cost of unevaluated leaseholds, seismic costs associated with specific
unevaluated properties, exploratory wells in progress, and secondary recovery
projects before the assignment of proved reserves. These unproved costs are
reviewed periodically by management for impairment, with the impairment
provision included in the cost of oil and natural gas properties subject to
amortization. Factors considered by management in its impairment assessment
include drilling results by the Company and other operators, the terms of oil
and natural gas leases not held by production, production response to secondary
recovery activities and available funds for exploration and development. Of the
$45.1 million of unproved property costs at December 31, 2004 being excluded
from the amortizable base, $5.1 million, $5.8 million and $24.8 million were
incurred in 2002, 2003 and 2004, respectively, and $9.4 million was incurred in
prior years. These costs are primarily seismic and lease acquisition costs. The
Company expects it will complete its evaluation of the properties representing
the majority of these costs within the next two to five years.
F-18
6. INCOME TAXES
All of the Company's income is derived from domestic activities. Actual
income tax expense differs from income tax expense computed by applying the U.S.
federal statutory corporate rate of 35% to pretax income as follows:
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2002 2003 2004
------ ------ ------
(IN THOUSANDS)
Provision at the statutory tax rate $2,660 $4,586 $6,204
Preferred dividend on Pinnacle -- 108 405
Increase in valuation allowance
for equity in loss of Pinnacle -- 189 70
State taxes 149 180 192
------ ------ ------
Income tax provision $2,809 $5,063 $6,871
====== ====== ======
Deferred income tax provisions result from temporary differences in the
recognition of income and expenses for financial reporting purposes and for tax
purposes. At December 31, 2003 and 2004, the tax effects of these temporary
differences resulted principally from the following:
AS OF DECEMBER 31,
------------------
2003 2004
------ -------
(IN THOUSANDS)
Deferred income tax assets:
Net operating loss carryforward $ 1,763 $ 2,519
Hedge valuation 100 --
Equity in the loss of Pinnacle 189 274
Valuation allowance (204) (274)
------- -------
1,848 2,519
------- -------
Deferred income tax liabilities:
Oil and gas acquisition, exploration and development
costs deducted for tax purposes in excess of
financial statement, DD&A 9,544 14,903
Capitalized interest 4,683 5,697
Hedge valuation -- 32
------- -------
14,227 20,632
------- -------
Net deferred income tax liability $12,379 $18,113
======= =======
The net deferred income tax liability is classified as follows:
AS OF DECEMBER 31,
------------------
2003 2004
------- -------
(IN THOUSANDS)
Other current assets $ 100 $ --
Other current liabilities -- 32
Deferred income taxes 12,479 18,081
------- -------
Net deferred income tax liability $12,379 $18,113
======= =======
F-19
Realization of deferred tax assets are dependent on the Company's ability
to generate taxable earnings in the future. The Company believes it will
generate taxable income in the NOL carryforward period. As such management
believes that it is more likely than not that its deferred tax assets other than
the deferred tax asset attributable to Pinnacle will be fully realized. A full
valuation allowance has been established for the equity in loss of Pinnacle's
tax asset as the realization of the deferred tax asset is dependent on
generating sufficient taxable income in Pinnacle in future periods. It is more
unlikely than not that Pinnacle will not realize the tax benefit. The Company
has net operating loss carryforwards totaling approximately $7.2 million, which
begin expiring in 2012 through 2021.
7. LONG-TERM DEBT
At December 31, 2003 and 2004, long-term debt consists of the following:
AS OF DECEMBER 31,
------------------
2003 2004
------- -------
(IN THOUSANDS)
Credit Facility $ 7,000 $18,000
Senior Secured notes(1) -- 16,268
Senior Subordinated notes(1) -- 28,584
Senior Subordinated notes, related parties(1) 26,992 --
Capital lease obligations 295 122
Non-recourse note payable to RMG 863 --
------- -------
35,150 62,974
Less: current maturities (1,037) (90)
------- -------
$34,113 $62,884
======= =======
- ----------
(1) Amounts are presented net of discount of $0.3 and $2.0 million as of
December 31, 2003 and 2004, respectively.
Credit Facility
On September 30, 2004, the Company entered into a Second Amended and
Restated Credit Agreement with Hibernia National Bank and Union Bank of
California, N.A. (the "Credit Facility"), which matures on September 30, 2007.
The Credit Facility amended, restated and extended the Company's prior credit
facility (such prior facility herein referred to as the "Prior Credit
Facility"). The Credit Facility provides for (1) a revolving line of credit of
up to the lesser of the Facility A Borrowing Base and $75.0 million and (2) a
term loan facility of up to the lesser of the Facility B Borrowing Base and
$25.0 million. It is secured by substantially all of the Company's assets and is
guaranteed by the Company's wholly-owned subsidiary, CCBM.
The Facility A Borrowing Bases will be redetermined by the lenders at least
semi-annually on each November 1 and May 1. The initial Facility A Borrowing
Base, under the Credit Facility on September 30, 2004 was $28.0 million and is
$30.0 million as of December 31, 2004. The initial Facility B Borrowing Base was
$0.00 and is subject to redetermination by the lenders in their sole discretion.
The Company and the lenders may each request one unscheduled borrowing base
redetermination subsequent to each scheduled redetermination. The Facility A
Borrowing Base will at all times equal the Facility A Borrowing Base most
recently redetermined by the lenders, less quarterly borrowing base reductions
required subsequent to such redetermination. The lenders will reset the Facility
A Borrowing Base amount at each scheduled and each unscheduled borrowing base
redetermination date.
If the outstanding principal balance of the revolving loans under the
Credit Facility exceeds the Facility A Borrowing Base at any time (including,
without limitation, due to a quarterly borrowing base reduction (as described
above)), the Company has the option within 30 days to take any of the following
actions, either individually or in combination: make a lump sum payment curing
the deficiency, pledge additional collateral sufficient in the lenders' opinion
to increase the Facility A Borrowing Base and cure the deficiency or begin
making equal monthly principal payments that will cure the deficiency within the
ensuing six-month period. Those payments would be in addition to any payments
that may come due as a result of the quarterly borrowing base reductions.
Otherwise, any unpaid principal or interest will be due at maturity.
F-20
For each revolving loan, the interest rate will be, at the Company's
option, (1) the Eurodollar Rate, plus an applicable margin equal to 2.375% if
the amount borrowed is greater than or equal to 90% of the Facility A Borrowing
Base, 2.0% if the amount borrowed is less than 90%, but greater than or equal to
50% of the Facility A Borrowing Base, or 1.625% if the amount borrowed is less
than 50% of the Facility A Borrowing Base; or (2) the Base Rate, plus an
applicable margin of 0.375% if the amount borrowed is greater than or equal to
90% of the Facility A Borrowing Base. The interest rate on each term loan will
be, at the Company's option, (1) the Eurodollar Rate, plus an applicable margin
to be determined by the lenders; or (2) the Base Rate, plus an applicable margin
to be determined by the lenders. Interest on Eurodollar Loans is payable on
either the last day of each Eurodollar option period or monthly, whichever is
earlier. Interest on Base Rate Loans is payable monthly.
The Company is subject to certain covenants under the terms of the Credit
Facility, including, but not limited to the maintenance of the following
financial covenants: (1) a minimum current ratio of 1.0 to 1.0 (including
availability under the borrowing base), (2) a minimum quarterly debt services
coverage of 1.25 times, (3) a minimum shareholders equity equal to $100.0
million, plus 100% of all subsequent common and preferred equity contributed by
shareholders' subsequent to June 30, 2004, plus 50% of all positive earning
occurring subsequent to June 30, 2004, plus, 180 days after issuance of any
second-lien subordinated debt with another lender ("the Secured Subordinated
Debt"), an amount equal to the difference, if positive, of (A) 50% of the net
proceeds from the issuance less (B) 100% of all common and preferred equity
contributed by shareholders from September 30, 2004 to the date of the issuance
of any Secured Subordinated Debt, and (4) a maximum total recourse debt to
EBITDA ratio (as defined in the Credit Facility) of not more than 3.0 to 1.0.
The Credit Facility also places restrictions on additional indebtedness,
dividends to shareholders, liens, investments, mergers, acquisitions, asset
dispositions, asset pledges and mortgages, change of control, repurchase or
redemption for cash of the Company's common stock, speculative commodity
transactions and other matters.
In connection with the Senior Secured Notes Purchase Agreement, we amended
the Credit Facility including without limitation, to: (1) amend the covenant
regarding maintenance of a minimum shareholders' equity, (2) add a new covenant
requiring maintenance of a minimum EBITDA to interest expense ratio and (3) add
other provisions and a consent which allow for the indebtedness incurred under
the Senior Secured Notes.
On November 7, 2004, we determined that, as of September 30, 2004, we were
not in compliance with the minimum current ratio covenant in the Credit
Facility. We cured the noncompliance on October 29, 2004 with the issuance of
the Senior Secured Notes. On November 10, 2004, the lenders under the Credit
Facility agreed in a letter to the Company to waive the noncompliance period
from September 30, 2004 through October 29, 2004.
At December 31, 2003, amounts outstanding under the Prior Credit Facility
totaled $7.0 million with an additional $12.0 million available for future
borrowings. At December 31, 2004, amounts outstanding under the Credit Facility
totaled $18.0 million, with an additional $12.0 million available for future
borrowings. At December 31, 2003, no letters of credit were issued and
outstanding under the Prior Credit Facility. At December 31, 2003 and 2004, no
letters of credit were issued and outstanding under the prior Credit Facility
and the Credit Facility, respectively.
Rocky Mountain Gas, Inc. Note
On June 29, 2001, CCBM, Inc. issued a non-recourse promissory note payable
in the amount of $7.5 million to RMG as consideration for certain interests in
oil and natural gas leases held by RMG in Wyoming and Montana. The RMG note was
payable in 41-monthly principal payments of $0.1 million plus interest at 8% per
annum commencing July 31, 2001 with the balance due December 31, 2004, all of
which have been paid. The RMG note was secured solely by CCBM's interests in the
oil and natural gas leases in Wyoming and Montana. In connection with the
Company's investment in Pinnacle Gas Resources, Inc., the Company received a
reduction in the principal amount of the RMG note of approximately $1.5 million
and relinquished the right to certain revenues related to the properties
contributed to Pinnacle. During the second quarter of 2004, CCBM relinquished a
portion of its interests in certain oil and natural gas leases to RMG and
reduced the principal due on the RMG note by $0.3 million.
Capital Leases
In December 2001, the Company entered into a capital lease agreement
secured by certain production equipment in the amount of $0.2 million. The lease
was payable in one payment of $11,323 and 35 monthly payments of $7,549
including interest at 8.6% per annum. In October 2002, the Company entered into
a capital lease agreement secured by certain production equipment in the amount
of $0.1 million. The lease is payable in 36 monthly payments of $3,462 including
interest at 6.4% per annum. In May 2003, the Company entered into a capital
lease agreement secured by certain production equipment in the amount of $0.1
million. The lease is payable in 36 monthly payments of $3,030 including
interest at 5.5% per annum. In August 2003, the Company entered into a capital
lease agreement secured by certain production equipment in the amount of $0.1
million. The lease is payable in 36 monthly payments
F-21
of $2,179 including interest at 6.0% per annum. The Company has the option to
acquire the equipment at the conclusion of the lease for $1 under all of these
leases. Depreciation on the capital leases for the years ended December 31,
2002, 2003 and 2004 amounted to $28,000, $48,000 and $46,000, respectively, and
accumulated depreciation on the leased equipment at December 31, 2003 and 2004
amounted to $78,000 and $124,000, respectively.
Senior Subordinated Notes and Related Securities
In December 1999, the Company consummated the sale of $22.0 million
principal amount of 9% Senior Subordinated Notes due 2007 (the "Subordinated
Notes") and $8.0 million of common stock and warrants. The Company sold $17.6
million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal
amount of Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212
shares of the Company's common stock and 2,208,152, 276,019, 92,006, 92,006 and
92,006 Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners
(23A SBIC), L.P.), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster
and Douglas A.P. Hamilton, respectively. The Subordinated Notes were sold at a
discount of $0.7 million, which is being amortized over the life of the notes.
Interest payments are due quarterly commencing on March 31, 2000. As amended as
described below, the Subordinated Notes allow the Company, until December 2005,
to increase the amount of the Subordinated Notes for 60% of the interest which
would otherwise be payable in cash. As of December 31, 2003 and December 31,
2004, the outstanding balance of the Subordinated Notes had been increased by
$5.3 million and $6.8 million respectively, for such interest paid in kind.
During 2004, Mellon Ventures, L.P., JPMorgan Partners (23A SBIC), Steven A.
Webster and Douglas A. P. Hamilton exercised warrants to purchase 276,019,
2,208,152, 92,006 and 92,006 shares of common stock, respectively, on a cashless
exercise basis for a total of 205,692, 1,684,949, 70,205 and 70,205 shares of
common stock, respectively, and Paul B. Loyd, Jr., exercised warrants for cash
to purchase 92,006 shares for a total of 92,006 shares of common stock. As a
result, no warrants to purchase shares of common stock remain outstanding from
the warrants originally issued in December 1999.
On June 7, 2004, an unaffiliated third party (the "Subordinated Notes
Purchaser") purchased all the outstanding Subordinated Notes from the original
note holders. In exchange for a $0.4 million amendment fee, certain terms and
conditions of the Subordinated Notes were amended, to provide for, among other
things, (1) a one year extension of the maturity to December 15, 2008, (2) a one
year extension, through December 15, 2005, of the paid-in-kind ("PIK") interest
option to pay-in-kind 60% of the interest due each period by increasing the
principal balance by a like amount (the "PIK option"), (3) an additional one
year option to extend the PIK option through December 15, 2006 at an annual
interest rate on the deferred amount of 10% and the payment of a one-time
amendment fee equal to 0.5% of the principal then outstanding and (4) additional
flexibility to obtain a separate project financing facility in the future. The
amendment fee will be amortized over the remaining life of the Note.
The Company is subject to certain covenants under the terms of the
Subordinated Notes securities purchase agreement, including but not limited to,
(a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of
EBITDA (earnings before interest, taxes, depreciation and amortization) to
quarterly Debt Service (as defined in the agreement) of not less than 1.00 to
1.00, (c) a limitation of its capital expenditures to an amount equal to the
Company's EBITDA for the immediately prior fiscal year (unless approved by the
Company's Board of Directors) and (d) a limitation on our Total Debt (as defined
in the securities purchase agreement) to 3.5 times EBITDA for any twelve month
period.
Senior Subordinated Secured Notes
On October 29, 2004, the Company entered into a Note Purchase Agreement
(the "Senior Secured Notes Purchase Agreement") with PCRL Investments L.P. (the
"Senior Secured Notes Purchaser"). Pursuant to the Senior Secured Notes Purchase
Agreement, the Company may issue up to $28 million aggregate principal amount of
10% Senior Subordinated Secured Notes due 2008 (the "Senior Secured Notes") for
a purchase price equal to 90% of the principal amount of the Senior Secured
Notes then issued. On October 29, 2004, the Senior Secured Notes Purchaser
purchased $18 million aggregate principal amount of the Senior Secured Notes for
a purchase price of $16.2 million. The debt discount is being amortized to
interest expense using the effective interest method over the life of the note.
Subject to the satisfaction of certain conditions, the Company has an option to
issue up to an additional $10 million aggregate principal amount of the Senior
Secured Notes to the Senior Secured Notes Purchaser before October 29, 2006.
The Senior Secured Notes are secured by a second lien on substantially all
of the Company's current proved producing reserves and non-reserve assets,
guaranteed by the Company's subsidiary, and subordinated to the Company's
obligations under the Credit Facility. The Senior Secured Notes bear interest at
10% per annum, payable quarterly on the 5th day of March, June, September and
December of each year beginning March 5, 2005. The principal on the Senior
Secured Notes is due December 15, 2008, and the Company has the option to prepay
the Senior Secured Notes at any time. The Senior Secured Notes include an option
that allows the Company to pay-in-kind 50% of the interest due until June 5,
2007 by increasing the principal due by a like amount. Subject to certain
conditions, the Company has the option to pay the interest on and principal of
(at maturity or upon prepayment) the Senior Secured
F-22
Notes with the Company's common stock, as long as the Secured Note Purchaser not
hold more than 9.99% of the number of shares of the Company's common stock
outstanding immediately after giving effect to such payment. The value of such
shares issued as payment on the Senior Secured Notes is determined based on 90%
of the volume weighted average trading price during a specified period of days
beginning with the date of the payment notice and ending before the payment
date. Issuance costs related to the transaction were $0.5 million and have been
recorded as deferred financing costs amortized to interest expense over the life
of the Senior Secured Notes.
As contemplated by the Secured Senior Notes Purchase Agreement, the Company
also entered into a registration rights agreement with the Secured Note
Purchaser (the "Registration Rights Agreement"). In the event the Company
chooses to issue shares of its common stock as payment of interest on the
principal of the Senior Secured Notes, the Registration Rights Agreement
provides registration rights with respect to such shares. The Company is
generally required to file a resale shelf registration statement to register the
resale of such shares under the Securities Act of 1933 (the "Securities Act") if
such shares are not freely tradable under Rule 144(k) under the Securities Act.
The Company is subject to certain covenants under the terms of the Registration
Rights Agreement, including the requirement that the registration statement be
kept effective for resale of shares subject to certain "blackout periods," when
sales may not be made. In certain circumstances, including those relating to (1)
delisting of the Company's common stock, (2) blackout periods in excess of a
maximum length of time, (3) certain failures to make timely periodic filings
with the Securities and Exchange Commission, or (4) certain delays or failures
to deliver stock certificates, the Company may be required to repurchase common
stock issued as payment on the Senior Secured Notes and, in certain of these
circumstances, to pay damages based on the market value of its common stock. In
certain situations, the Company is required to indemnify the holders of
registration rights under the Registration Rights Agreement, including, without
limitation, for liabilities under the Securities Act.
The Senior Secured Notes Purchase Agreement includes certain
representations, warranties and covenants by the parties thereto. The Company is
subject to certain covenants under the terms of the Senior Secured Notes
Purchase Agreement, including, without limitation, the maintenance of the
following financial covenants: (1) a maximum total recourse debt to EBITDA ratio
of not more than 3.50 to 1.0, (2) a minimum EBITDA to interest expense ratio of
2.50 to 1.0, and (3) as of April 30, 2005, a minimum tangible net worth of $12.5
million in excess of the Company's tangible net worth as of September 30, 2004.
Upon a change of control, any holders of the Senior Secured Notes may require
the Company to repurchase such holders' Senior Secured Notes at a price equal to
then outstanding principal amount of such Senior Secured Notes, together with
all interest accrued on such Senior Secured Notes through the date of
repurchase. The Senior Secured Notes Purchase Agreement also places restrictions
on additional indebtedness, dividends to stockholders, liens, investments,
mergers, acquisitions, asset dispositions, asset pledges and mortgages,
repurchase or redemption for cash of the Company's common stock, speculative
commodity transactions and other matters. The Senior Secured Notes Purchaser is
an affiliate of the Subordinated Notes Purchaser.
Estimated maturities of long-term debt are $0.1 million in 2005, none in
2006, $18.0 million in 2007, and the remainder in 2008.
At December 31, 2004, the Company was in compliance with all of its debt
covenants.
8. SEISMIC OBLIGATION PAYABLE
In 2002, the Company acquired (or obtained the right to acquire) certain
seismic data in its core areas in the Texas and Louisiana Gulf Coast regions.
Under the terms of the acquisition agreements, the Company was required to make
monthly payments of $0.1 million through March 2004 and an additional payment of
$0.8 million in April 2004. All payments have been made.
9. CONVERTIBLE PARTICIPATING PREFERRED STOCK
In February 2002, the Company consummated the sale of 60,000 shares of
Convertible Participating Series B Preferred Stock (the "Series B Preferred
Stock") and warrants to purchase 252,632 shares of common stock for an aggregate
purchase price of $6.0 million. The Company sold 40,000 and 20,000 shares of
Series B Preferred Stock and 168,422 and 84,210 warrants to Mellon Ventures,
Inc. and Steven A. Webster, respectively. The Series B Preferred Stock was
convertible into common stock by the investors at a conversion price of $5.70
per share, subject to adjustments, and was initially convertible into 1,052,632
shares of common stock. Dividends on the Series B Preferred Stock were payable
in either cash at a rate of 8% per annum or, at the Company's option, by payment
in kind of additional shares of the same series of preferred stock at a rate of
10% per annum. At December 31, 2003 and through the conversion dates specified
below, the outstanding balance of the Series B Preferred Stock has been
increased by $1.2 million (11,987 shares) and $1.5 million (15,133 shares),
respectively, for dividends paid in kind. The Series B Preferred Stock was
redeemable at varying prices in whole or in part at the holders' option after
three years or at the Company's option at any time. The Series B Preferred Stock
also participated in any dividends declared on the common stock. Holders of the
Series B Preferred Stock would have received a liquidation preference upon the
liquidation of, or certain mergers or sales of substantially all assets
involving,
F-23
the Company. Such holders also had the option of receiving a change of control
repayment price upon certain deemed change of control transactions. Mellon
Ventures, Inc., converted all of its Series B Preferred Stock (approximately
49,938 shares) into 876,099 shares of common stock on May 25, 2004. Steven A.
Webster converted all of his Series B Preferred Stock (approximately 25,195
shares) into 442,026 shares of common stock on June 30, 2004. As a result, no
shares of Series B Preferred Stock remain outstanding at December 31, 2004. The
total value of the Series B Preferred Stock upon conversion was $7.5 million and
was reclassified to stockholders' equity following the conversion.
The warrants have a five-year term and entitle the holders to purchase up
to 252,632 shares of Carrizo's common stock at a price of $5.94 per share,
subject to adjustments, and are exercisable at any time after issuance. The
warrants may be exercised on a cashless exercise basis. During the year ended
December 31, 2004, Mellon Ventures, Inc. exercised all of its 168,422 warrants
on a cashless exercise basis for a total of 36,570 shares of common stock.
Net proceeds of the sale of the Series B Preferred Stock were approximately
$5.8 million and were used primarily to fund the Company's ongoing exploration
and development program and general corporate purposes.
10. COMMITMENTS AND CONTINGENCIES
From time to time, the Company is party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position or results of
operations of the Company.
The operations and financial position of the Company continue to be
affected from time to time in varying degrees by domestic and foreign political
developments as well as legislation and regulations pertaining to restrictions
on oil and natural gas production, imports and exports, natural gas regulation,
tax increases, environmental regulations and cancellation of contract rights.
Both the likelihood and overall effect of such occurrences on the Company vary
greatly and are not predictable.
In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in N. La Copita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. The Company, along
with GMT and other partners, reached a final settlement with ExxonMobil on
February 11, 2003. Under the terms of the settlement, the Company recovered the
balance of its drilling costs (approximately $0.1 million) and certain other
costs and retained no further interest in the property. No reserves with respect
to these properties were included in the Company's reported proved reserves as
of December 31, 2002.
Rent expense for each of the years ended December 31, 2002, 2003 and 2004
was $0.2 million. Effective December 2004, the Company relocated its offices and
entered into a new long-term operating lease agreement that expires December
2011. Under the terms of the lease agreement, the Company received a rent
abatement equal to six months of lease payments that is being amortized to
expense over the term of the lease. The Company is obligated for remaining lease
payments as of December 31, 2004 as follows:
DECEMBER 31, AMOUNT
- ------------ --------------
(In thousands)
2005 $ 222
2006 477
2007 477
2008 477
2009 477
Remainder 1,056
------
$3,186
======
F-24
11. SHAREHOLDERS' EQUITY
In the first quarter of 2004, the Company completed the public offering of
6,485,000 shares of common stock at $7.00 per share. The offering included
3,655,500 newly issued shares offered by the Company and 2,829,500 shares
offered by certain existing selling shareholders. The Company did not receive
any proceeds from the shares sold by the selling shareholders. The Company used
part of the net proceeds from this offering to accelerate its drilling program
and to retain larger interests in portions of its drilling prospects that the
Company otherwise would sell down or for which the Company would seek joint
partners and for general corporate purposes. Initially, the Company used a
portion of the net proceeds to repay the $7 million outstanding principal amount
under its revolving credit facility and to complete an $8.2 million Barnett
Shale acquisition on February 27, 2004.
The Company issued 413,965 and 7,570,109 shares of common stock during the
years ended December 31, 2003 and 2004, respectively. In June of 1997, the
Company established the Incentive Plan of Carrizo Oil & Gas, Inc. (the
"Incentive Plan"). The shares issued during the year ended December 31, 2003
were the result of the exercise of options granted under the Company's Incentive
Plan. The shares issued during the year ended December 31, 2004, consisted of
3,655,500 shares issued through the public offering, 2,159,627 shares issued
through the exercise of warrants, 1,318,124 shares issued through the conversion
of Series B Preferred Stock and the balance issued through the exercise of
options granted under the Company's Incentive Plan.
The following table summarizes information for the options outstanding at
December 31, 2004:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------- ---------------------------------
WEIGHTED
NUMBER OF AVERAGE WEIGHTED NUMBER OF WEIGHTED
OPTIONS REMAINING AVERAGE OPTIONS AVERAGE
OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE
RANGE OF EXERCISE PRICES AT 12/31/04 LIFE IN YEARS PRICE AT 12/31/04 PRICE
- ------------------------ ----------- ------------- -------- ----------- --------
$1.75-2.25 436,635 5.13 $2.21 436,635 $2.21
$3.14-4.00 111,629 4.75 $3.52 102,517 $3.50
$4.01-5.00 524,202 7.20 $4.30 374,480 $4.24
$5.17-8.00 252,835 7.67 $7.18 95,611 $6.43
The Company may grant options ("Incentive Plan Options") to purchase up to
2,350,000 shares under the Incentive Plan and has granted options
covering 1,955,168 shares through December 31, 2004. Through December 31, 2004,
739,656 stock options had been exercised. A summary of the status of the
Company's stock options at December 31, 2002, 2003 and 2004 is presented in the
table below:
2002
-------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- -------- -------------
Outstanding at beginning of year 1,636,657 $3.49 $1.75 - $8.00
Granted (Incentive Plan Options) 54,500 $4.31 $3.76 - $5.37
Exercised (Incentive Plan Options) (6,834) $2.12 $2.00 - $2.25
Expired (Incentive Plan Options) (54,000) $6.38 $1.75 - $8.00
---------- -----
Outstanding at end of year 1,630,323 $3.35 $1.75 - $8.00
========== =====
Exercisable at end of year 1,048,212 $3.28
========== =====
Weighted average of fair value of
options granted during the year $ 3.57
==========
F-25
2003
-------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- -------- -------------
Outstanding at beginning of year 1,630,323 $3.35 $1.75 - $8.00
Granted (Incentive Plan Options) 257,500 $4.63 $4.37 - $5.75
Exercised (Pre-IPO Options) (85,000) $3.60 $3.60
Exercised (Incentive Plan Options) (161,001) $2.39 $2.00 - $4.40
Expired (Incentive Plan Options) (4,000) $3.33 $2.25 - $4.40
---------- -----
Outstanding at end of year 1,637,822 $3.63 $1.75 - $8.00
========== =====
Exercisable at end of year 1,261,655 $3.44
========== =====
Weighted average of fair value of
options granted during the year $ 3.65
==========
2004
---------------------------------------
WEIGHTED
AVERAGE RANGE OF
EXERCISE EXERCISE
SHARES PRICES PRICES
---------- -------- ---------------
Outstanding at beginning of year 1,637,822 $3.63 $1.75 - $8.00
Granted (Incentive Plan Options) 131,668 $8.01 $6.98 - $9.215
Exercised (Pre-IPO Options) (88,825) $3.60 $3.60
Exercised (Incentive Plan Options) (348,033) $3.83 $1.8125 - $8.00
Expired (Incentive Plan Options) (7,331) $5.89 $4.40 - $8.00
---------- -----
Outstanding at end of year 1,325,301 $4.09 $1.75 - $9.215
========== =====
Exercisable at end of year 1,009,243 $3.49
========== =====
Weighted average of fair value of
options granted during the year $ 4.86
==========
In March of 2000, the FASB issued FIN No. 44 which was effective July 1,
2000 and clarifies the application of APB No. 25 for certain issues associated
with the issuance or subsequent modifications of stock compensation. For certain
modifications, including stock option repricings made subsequent to December 15,
1998, the Interpretation requires that variable plan accounting be applied to
those modified awards prospectively from July 1, 2000. This requires that the
change in the intrinsic value of the modified awards be recognized as
compensation expense. On February 17, 2000, Carrizo repriced certain employee
and director stock options covering 348,500 shares of stock with a weighted
average exercise price of $9.13 to a new exercise price of $2.25 through the
cancellation of existing options and issuance of new options at current market
prices. Subsequent to the adoption of the Interpretation, the Company records
the effects of any changes in its stock price over the remaining vesting period
through February 2010 on the corresponding intrinsic value of the repriced
options in its results of operations as compensation expense until the repriced
options either are exercised or expire. Stock option compensation expense
(benefit) relating to the repriced options for the years ended December 31,
2002, 2003 and 2004 amounted to $(0.1 million), $0.3 million and $1.1 million,
respectively.
In December 1999, the Company reduced the exercise price of certain
warrants originally issued to affiliates of Enron Corp. in January 1998. 250,000
of these warrants outstanding as of December 31, 2003 and 2004 were exercised
in January 2005, for 250,000 shares of the Company's common stock at
$4.00 per share.
12. RELATED-PARTY TRANSACTIONS
During the years ended December 31, 2003 and 2004, the Company incurred
drilling costs in the amount of and $2.2 million and $1.6 million, respectively,
with Grey Wolf Drilling. Mr. Webster is the Chairman of the Board of Carrizo and
a member of the Board of Directors of Grey Wolf Drilling. During the year ended
December 31, 2003 and 2004, the Company incurred lease operating costs of $0.4
million and $0.4 million, respectively, with Basic Services, Inc. Mr. Webster
and Mr. Johnson are members of the Board of Directors of Basic Services, Inc. It
is management's opinion that the transactions with both of these entitities were
performed at prevailing market rates.
F-26
At December 31, 2004, the Company had outstanding related-party accounts
receivable and payable balances of $0.3 million and $0.7 million, respectively.
At December 31, 2003, the Company had outstanding related party accounts payable
balances of $0.9 million.
During the year ended 2004, Goodrich Petroleum ("Goodrich") participated in
the drilling of one well operated by the Company. During the year ended December
31, 2004, the Company incurred land and drilling expenses of $0.6 million with
the Company. Mr. Webster is a member of the Board of Directors of Goodrich. The
terms of the operating agreements between the Company and Goodrich are
consistent with standard industry practices.
See Notes 4, 7 and 9 for a discussion of the investment in Pinnacle,
Subordinated Notes and Series B Preferred Stock with parties that include
members of the Company's Board of Directors or their affiliates.
Steven A. Webster, Chairman of the Board of the Company, is also a managing
director of Credit Suisse First Boston Private Equity and is therefore a related
party to the Pinnacle transaction.
The Company entered into a transition services agreement with Pinnacle
pursuant to which the Company provided certain accounting, treasury, tax,
insurance and financial reporting functions to Pinnacle for a monthly fee equal
to the Company's actual cost to provide such services. No such services were
provided during 2004.
13. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
The Company's operations involve managing market risks related to changes
in commodity prices. Derivative financial instruments, specifically swaps,
futures, options and other contracts, are used to reduce and manage those risks.
The Company addresses market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. The
Company enters into swaps, options, collars and other derivative contracts to
hedge the price risks associated with a portion of anticipated future oil and
natural gas production. While the use of hedging arrangements limits the
downside risk of adverse price movements, it may also limit future gains from
favorable movements. Under these agreements, payments are received or made based
on the differential between a fixed and a variable product price. These
agreements are settled in cash at termination, expiration or exchanged for
physical delivery contracts. The Company enters into the majority of its hedging
transactions with two counterparties and a netting agreement is in place with
those counterparties. The Company does not obtain collateral to support the
agreements but monitors the financial viability of counterparties and believes
its credit risk is minimal on these transactions. In the event of
nonperformance, the Company would be exposed to price risk. The Company has some
risk of accounting loss since the price received for the product at the actual
physical delivery point may differ from the prevailing price at the delivery
point required for settlement of the hedging transaction.
As of December 31, 2003 and 2004, the unrealized gain/(loss), net of tax,
of $0.2 million and $59,000, respectively, (net of tax of $0.1 million and
$34,000, respectively) remained in accumulated other comprehensive income
related to the valuation of the Company's hedging positions.
Total oil purchased and sold under swaps and collars during 2002, 2003 and
2004 were 131,300 Bbls, 193,600 Bbls and 121,700 Bbls, respectively. Total
natural gas purchased and sold under swaps and collars in 2002, 2003 and 2004
were 2,314,000 MMBtu, 2,739,000 MMBtu and 3,936,000 MMBtu, respectively. The net
losses realized by the Company under such hedging arrangements were $(0.9)
million, $(1.8) million and $(1.0) million for 2002, 2003 and 2004,
respectively, and are included in oil and natural gas revenues.
F-27
At December 31, 2003 and 2004 the Company had the following outstanding
hedge positions:
DECEMBER 31, 2003
------------------------------------------------------------
CONTRACT VOLUMES
---------------- AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ ------- ----------- ----------- -------------
First Quarter 2004 27,000 $30.36
First Quarter 2004 180,000 6.67
First Quarter 2004 546,000 $4.10 $7.00
Second Quarter 2004 18,300 30.38
Second Quarter 2004 546,000 4.00 5.60
Third Quarter 2004 552,000 4.00 5.60
Fourth Quarter 2004 369,000 4.00 5.80
DECEMBER 31, 2003
------------------------------------------------------------
CONTRACT VOLUMES
---------------- AVERAGE AVERAGE AVERAGE
QUARTER BBLS MMBTU FIXED PRICE FLOOR PRICE CEILING PRICE
------- ------ ------- ----------- ----------- -------------
First Quarter 2005 27,000 $41.67 $50.50
First Quarter 2005 928,000 5.40 8.11
Second Quarter 2005 364,000 5.25 7.15
Second Quarter 2005 91,000 $6.03
Third Quarter 2005 368,000 5.25 7.40
Third Quarter 2005 92,000 6.03
Fourth Quarter 2005 276,000 5.25 7.92
Fourth Quarter 2005 92,000 6.03
In addition to the hedge positions above, during the second quarter of
2003, the Company acquired options to sell 6,000 MMBtu of natural gas per day
for the period July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu
for approximately $119,000. The Company acquired these options to protect its
cash position against potential margin calls on certain natural gas derivatives
due to large increases in the price of natural gas. These options were
classified as derivatives. As of December 31, 2003, these options have expired
and a charge of $119,000 has been included in other income and expenses for the
year ended December 31, 2003.
In November 2001, the Company had no-cost collars with an affiliate of
Enron Corp. which, because of Enron's financial condition, were no longer
considered effective. An allowance was recorded at that time for the full value
of the collars (the "Enron Claim") that was classified as other expense. The
Company sold its Enron Claim to a financial institution for $0.5 million that
was recorded in the third quarter of 2004 as other income.
14. SUBSEQUENT EVENT
Effective February 1, 2005, the Company sold to a private company its
interest in the Patterson Prospect Area in St. Mary Parish, Louisiana, including
the Shadyside #1 well and any anticipated follow-up wells, for approximately
$9.0 million. The Company's average daily production from the Shadyside #1
during the fourth quarter 2004 was approximately 970 Mcfe per day. Proceeds from
the sale are expected to be used in the 2005 Barnett Shale and Gulf Coast
drilling program and for general corporate purposes.
15. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
The following disclosures provide unaudited information required by SFAS
No. 69, "Disclosures About Oil and Gas Producing Activities."
COSTS INCURRED
Costs incurred in oil and natural gas property acquisition, exploration and
development activities are summarized below:
F-28
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2002 2003 2004
------- ------- -------
(IN THOUSANDS)
Property acquisition costs
Unproved $ 6,402 $ 7,280 $21,831
Proved 660 -- 8,357
Exploration costs 14,194 23,745 39,181
Development costs 2,351 112 12,697
Asset retirement obligation 744 529
--
------- ------- -------
Total costs incurred (1) $23,607 $31,881 $82,595
======= ======= =======
- ----------
(1) Excludes capitalized interest on unproved properties of $3.1 million, $2.9
million and $2.9 million for the years ended December 31, 2002, 2003 and
2004, respectively, and includes capitalized overhead of $1.0 million, $1.4
million and $1.7 million for the years ended December 31, 2002, 2003 and
2004, respectively. The table also includes non-cash asset retirement
obligations of $0.7 million and $0.5 million for the year ended December
31, 2003 and 2004, respectively.
OIL AND NATURAL GAS RESERVES
Proved reserves are estimated quantities of oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved oil and natural gas reserve quantities at December 31, 2002, 2003
and 2004, and the related discounted future net cash flows before income taxes
are based on estimates prepared by Ryder Scott Company, DeGolyer and MacNaughton
and Fairchild & Wells, Inc., independent petroleum engineers. Such estimates
have been prepared in accordance with guidelines established by the Securities
and Exchange Commission.
The Company's net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below:
THOUSANDS OF BARRELS OF
OIL AND CONDENSATE
AT DECEMBER 31,
-----------------------
2002 2003 2004
----- ----- -----
Proved developed and undeveloped reserves -
Beginning of year 6,857 8,381 8,714
Purchase of oil and natural gas properties in place -- -- 5
Discoveries and extensions 369 231 208
Revisions 1,568 553 500
Sales of oil and gas properties in place (12) (1) --
Production (401) (450) (309)
----- ----- -----
End of year 8,381 8,714 9,118
===== ===== =====
Proved developed reserves at beginning of year 1,158 1,393 1,395
===== ===== =====
Proved developed reserves at end of year 1,393 1,395 1,459
===== ===== =====
F-29
MILLIONS OF CUBIC FEET
OF NATURAL GAS
AT DECEMBER 31,
--------------------------
2002 2003 2004
------- ------ -------
Proved developed and undeveloped reserves -
Beginning of year 17,858 12,922 18,069
Purchase of oil and natural gas properties in place 585 -- 13,390
Discoveries and extensions 3,280 10,305 32,002
Revisions (3,726) 129 (2,378)
Sales of oil and gas properties in place (274) (523) --
Production (4,801) (4,764) (6,462)
------- ------ -------
End of year 12,922 18,069 54,621
======= ====== =======
Proved developed reserves at beginning of year 13,754 12,826 17,098
======= ====== =======
Proved developed reserves at end of year 12,826 17,098 28,066
======= ====== =======
Carrizo uses the equity method of accounting to record its minority
ownership in the operations of Pinnacle, formed in June 2003. Accordingly, the
proved reserve tables, above, do not include the Company's interest ownership,
22.7% on a fully diluted basis, in the proved reserves of Pinnacle at the end of
2004, or an estimated 5.6 Bcfe of proved reserves.
Standardized Measure
The standardized measure of discounted future net cash flows relating to
the Company's ownership interests in proved oil and natural gas reserves as of
year-end is shown below:
YEAR ENDED DECEMBER 31,
------------------------------
2002 2003 2004
-------- -------- --------
(IN THOUSANDS)
Future cash inflows $305,087 $375,160 $685,598
Future oil and natural gas operating expenses 142,597 167,090 244,618
Future development costs 15,259 15,943 55,730
Future income tax expenses 33,232 45,540 108,295
-------- -------- --------
Future net cash flows 113,999 146,587 276,955
10% annual discount for estimating timing of cash flows 49,702 58,961 127,234
-------- -------- --------
Standard measure of discounted future net cash flows $ 64,297 $ 87,626 $149,721
======== ======== ========
Future cash flows are computed by applying year-end prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Average prices used in computing year end 2002, 2003 and 2004 future cash flows
were $29.16, $30.29 and $41.18 for oil, respectively and $4.70, $6.19 and $5.68
for natural gas, respectively. Future operating expenses and development costs
are computed primarily by the Company's petroleum engineers by estimating the
expenditures to be incurred in developing and producing the Company's proved oil
and natural gas reserves at the end of the year, based on year end costs and
assuming continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for tax
basis and availability of applicable tax assets. A discount factor of 10% was
used to reflect the timing of future net cash flows. The standardized measure of
discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company's oil and natural gas properties. An
estimate of fair value would also take into account, among other things, the
recovery of reserves not presently classified as proved, anticipated future
changes in prices and costs, and a discount factor more representative of the
time value of money and the risks inherent in reserve estimates.
CHANGE IN STANDARDIZED MEASURE
Changes in the standardized measure of future net cash flows relating to
proved oil and natural gas reserves are summarized below:
F-30
2002 2003 2004
-------- -------- --------
(IN THOUSANDS)
Changes due to current-year operations -
Sales of oil and natural gas, net of oil
and natural gas operating expenses $(23,377) $(34,177) $(42,982)
Extensions and discoveries 20,680 42,530 80,933
Purchases of oil and gas properties 888 -- 16,467
Changes due to revisions in standardized variables
Prices and operating expenses 36,511 8,654 34,516
Income taxes (12,748) (9,606) (31,667)
Estimated future development costs 417 (377) 12,951
Revision of quantities 8,818 5,374 (1,307)
Sales of reserves in place (191) (836) --
Accretion of discount 4,795 8,304 11,485
Production rates, timing and other (12,880) 3,463 (18,301)
-------- -------- --------
Net change 22,913 23,329 62,095
Beginning of year 41,384 64,297 87,626
-------- -------- --------
End of year $ 64,297 $ 87,626 $149,721
======== ======== ========
Sales of oil and natural gas, net of oil and natural gas operating
expenses, are based on historical pretax results. Sales of oil and natural gas
properties, extentions and discoveries, purchases of minerals in place and the
changes due to revisions in standardized variables are reported on a pretax
discounted basis, while the accretion of discount is presented on an after-tax
basis.
16. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
FIRST SECOND THIRD FOURTH
------- ------- ------- -------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
2004
Revenues $10,873 $11,960 $12,274 $16,267
Costs and expenses, net 8,690 9,822 8,884 13,124
------- ------- ------- -------
Net income 2,183 2,138 3,390 3,143
Dividends and accretion 198 152 -- --
------- ------- ------- -------
Net income available to common
shareholders $ 1,985 $ 1,986 $ 3,390 $ 3,143
======= ======= ======= =======
Basic net income per share (1) $ 0.12 $ 0.10 $ 0.15 $ 0.14
======= ======= ======= =======
Diluted net income per share (1) $ 0.10 $ 0.09 $ 0.15 $ 0.14
======= ======= ======= =======
F-31
FIRST SECOND THIRD FOURTH
------- ------ ------- ------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
2003
Revenues $10,663 $8,828 $10,123 $8,893
Costs and expenses, net 7,693 6,868 8,041 7,866
------- ------ ------- ------
Net income 2,970 1,960 2,082 1,027
Dividends and accretion 181 181 190 189
------- ------ ------- ------
Net income available to common
shareholders before cumulative effect
in accounting principle $ 2,789 $1,779 $ 1,892 $ 838
======= ====== ======= ======
Cumulative effect in change of
in accounting principle 128 -- -- --
------- ------ ------- ------
Net income available to
common shareholders $ 2,661 $1,779 $ 1,892 $ 838
======= ====== ======= ======
Basic net income per share (1) $ 0.19 $ 0.13 $ 0.13 $ 0.06
======= ====== ======= ======
Diluted net income per share (1) $ 0.16 $ 0.11 $ 0.11 $ 0.05
======= ====== ======= ======
- ----------
(1) The sum of individual quarterly net income per common share may not agree
with year-to-date net income per common share as each period's computation
is based on the weighted average number of common shares outstanding during
that period.
F-32
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CARRIZO OIL & GAS, INC.
By: /s/ PAUL F. BOLING
------------------------------------
Paul F. Boling
Chief Financial Officer, Vice President,
Secretary and Treasurer
Date: March 31, 2005
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
NAME CAPACITY DATE
---- -------- ----
/s/ S. P. JOHNSON IV President, Chief Executive March 31, 2005
- ------------------------- Officer and Director (Principal
S. P. Johnson IV Executive Officer)
/s/ PAUL F. BOLING Chief Financial Officer, Vice March 31, 2005
- ------------------------- President, Secretary and
Paul F. Boling Treasurer (Principal Financial
Officer and Principal
Accounting Officer)
/s/ STEVEN A. WEBSTER Chairman of the Board March 31, 2005
- -------------------------
Steven A. Webster
/s/ THOMAS L. CARTER, JR. Director March 31, 2005
- -------------------------
Thomas L. Carter, Jr.
/s/ PAUL B. LOYD, JR. Director March 31, 2005
- -------------------------
Paul B. Loyd, Jr.
/s/ F. GARDNER PARKER Director March 31, 2005
- -------------------------
F. Gardner Parker
/s/ ROGER A. RAMSEY Director March 31, 2005
- -------------------------
Roger A. Ramsey
/s/ FRANK A. WOJTEK Director March 31, 2005
- -------------------------
Frank A. Wojtek
F-33
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
+2.1 -- Combination Agreement by and among the Company, Carrizo Production,
Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners
Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas
A.P. Hamilton and Frank A. Wojtek dated as of June 6, 1998
(Incorporated herein by reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+3.1 -- Amended and Restated Articles of Incorporation of the Company
(Incorporated herein by reference to Exhibit 3.1 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1998).
+3.2 -- Amended and Restated Bylaws of the Company, as amended by Amendment
No. 1 (Incorporated herein by reference to Exhibit 3.2 to the
Company's Registration Statement on Form 8-A (Registration No.
000-22915), Amendment No. 2 (Incorporated herein by reference to
Exhibit 3.2 to the Company's Current Report on Form 8-K dated December
15, 1999) and Amendment No. 3 (Incorporated herein by reference to
Exhibit 3.1 to the Company's Current Report on Form 8-K dated February
20, 2002).
+10.1 -- Amendment No. 1 to the Letter Agreement Regarding Participation in
the Company's 2001 Seismic and Acreage Program, dated June 1, 2001
(Incorporated herein by reference to Exhibit 4.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
+10.2 -- Amended and Restated Incentive Plan of the Company effective as of
February 17, 2000 (Incorporated herein by reference to Exhibit 10.3 to
the Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 2000).
+10.3 -- Amendment No. 1 to the Amended and Restated Incentive Plan of the
Company (Incorporated herein by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
2002).
+10.4 -- Amendment No. 2 to the Amended and Restated Incentive Plan of the
Company (Incorporated herein by reference to Exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year ended December 31,
2002).
+10.5 -- Amendment No. 3 to the Amended and Restated Incentive Plan of the
Company (Incorporated herein by reference to Appendix A to the
Company's Proxy Statement dated April 21, 2003).
+10.6 -- Amendment No. 4 to the Amended and Restated Incentive Plan of the
Company (incorporated herein by reference to Appendix B to the
Company's Proxy Statement dated April 26, 2004).
+10.7 -- Employment Agreement between the Company and S.P. Johnson IV
(Incorporated herein by reference to Exhibit 10.2 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.8 -- Employment Agreement between the Company and Kendall A. Trahan
(Incorporated herein by reference to Exhibit 10.4 to the Company's
Registration Statement on Form S-1 (Registration No. 333-29187)).
+10.9 -- Employment Agreement between the Company and J. Bradley Fisher
(Incorporated herein by reference to Exhibit 10.8 to the Company's
Registration Statement on Form S-2 (Registration No. 333-111475)).
+10.10 -- Employment Agreement between the Company and Paul F. Boling
(Incorporated herein by reference to Exhibit 10.9 to the Company's
Registration Statement on Form S-2 (Registration No. 333-111475)).
+10.11 -- Form of Indemnification Agreement between the Company and each of its
directors and executive officers (Incorporated herein by reference to
Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
+10.12 -- S Corporation Tax Allocation, Payment and Indemnification Agreement
among the Company and Messrs. Loyd, Webster, Johnson, Hamilton and
Wojtek (Incorporated herein by reference to Exhibit 10.8 to the
Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.13 -- S Corporation Tax Allocation, Payment and Indemnification Agreement
among Carrizo Production, Inc. and Messrs. Loyd, Webster, Johnson,
Hamilton and Wojtek (Incorporated herein by reference to Exhibit 10.9
to the Company's Registration Statement on Form S-1 (Registration No.
333-29187)).
+10.14 -- Form of Amendment to Executive Officer Employment Agreement.
(Incorporated herein by reference to Exhibit 99.3 to the Company's
Current Report on Form 8-K dated January 8, 1998).
+10.15 -- Securities Purchase Agreement dated December 15, 1999 among the
Company, CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B.
Loyd Jr., Douglas A. P. Hamilton and Steven A. Webster (Incorporated
herein by reference to Exhibit 99.1 to the Company's Current Report on
Form 8-K dated December 15, 1999).
+10.16 -- First Amendment to Securities Purchase Agreement dated as of June
7, 2004 among Carrizo Oil & Gas, Inc., Steelhead Investments Ltd.,
Douglas A.P. Hamilton, Paul B. Loyd, Jr., Steven A. Webster and Mellon
Ventures, L.P. (incorporated herein by reference to Exhibit 99.1 to
the Company's Current Report on Form 8-K filed on June 10, 2004).
+10.17 -- Form of Amended and Restated 9% Senior Subordinated Note due 2008
(incorporated herein by reference to Exhibit 99.2 to the Company's
Current Report on Form 8-K filed on June 10, 2004).
+10.18 -- Second Amendment to Securities Purchase Agreement dated as of
October 29, 2004 among Carrizo Oil & Gas, Inc. and the Investors named
therein (incorporated herein by reference to Exhibit 10.7 to the
Company's Current Report on Form 8-K filed on November 3, 2004).
+10.19 -- Shareholders Agreement dated December 15, 1999 among the Company,
CB Capital Investors, L.P., Mellon Ventures, L.P., Paul B. Loyd Jr.,
Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A.
Wojtek and DAPHAM Partnership, L.P. (Incorporated herein by reference
to Exhibit 99.2 to the Company's Current Report on Form 8-K dated
December 15, 1999).
+10.20 -- First Amendment to Shareholders Agreement dated as of December 15,
1999 by and among Carrizo Oil & Gas, Inc, J.P. Morgan Partners (23A
SBIC), LLC, Mellon Ventures, L.P., S.P. Johnson IV, Frank A. Wojtek,
Steven A. Webster, Douglas A.P. Hamilton, Paul B. Loyd, Jr. and DAPHAM
Partnership, L.P. dated April 21, 2004 (incorporated herein by
reference to Exhibit 32 to the Schedule 13D/A filed by Paul B. Loyd,
Jr. on May 27, 2004).
+10.21 -- Second Amendment to Shareholders Agreement dated as of December
15,1999 by and among Carrizo Oil & Gas, Inc., J.P. Morgan Partners
(23A SBIC), LLC, Mellon Ventures, L.P., S.P. Johnson IV, Frank A.
Wojtek and Steven A. Webster dated June 7, 2004 (incorporated herein
by reference to Exhibit 99.4 to the Company's Current Report on Form
8-K filed on June 10, 2004).
+10.22 -- Registration Rights Agreement dated December 15, 1999 among the
Company, CB Capital Investors, L.P. and Mellon Ventures, L.P.
(Incorporated herein by reference to Exhibit 99.4 to the Company's
Current Report on Form 8- K dated December 15, 1999).
+10.23 -- Amended and Restated Registration Rights Agreement dated December
15, 1999 among the Company, Paul B. Loyd Jr., Douglas A. P. Hamilton,
Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM
Partnership, L.P. (Incorporated herein by reference to Exhibit 99.5 to
the Company's Current Report on Form 8-K dated December 15, 1999).
+10.24 -- Form of Amendment to Executive Officer Employment Agreement
(Incorporated herein by reference to Exhibit 99.7 to the Company's
Current Report on Form 8-K dated December 15, 1999).
+10.25 -- Form of Amendment to Director Indemnification Agreement
(Incorporated herein by reference to Exhibit 99.8 to the Company's
Current Report on Form 8-K dated December 15, 1999).
+10.26 -- Purchase and Sale Agreement by and between Rocky Mountain Gas, Inc.
and CCBM, Inc., dated June 29, 2001 (Incorporated herein by reference
to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2001).
+10.27 -- Securities Purchase Agreement dated February 20, 2002 among the
Company, Mellon Ventures, L.P. and Steven A. Webster (Incorporated
herein by reference to Exhibit 99.1 to the Company's Current Report on
Form 8-K dated February 20, 2002).
+10.28 -- Warrant Agreement dated February 20, 2002 among the Company, Mellon
Ventures, L.P. and Steven A. Webster (including Warrant Certificate)
(Incorporated herein by reference to Exhibit 99.4 to the Company's
Current Report on Form 8-K dated February 20, 2002).
+10.29 -- Registration Rights Agreement dated February 20, 2002 among the
Company, Mellon Ventures, L.P. and Steven A. Webster (Incorporated
herein by reference to Exhibit 99.5 to the Company's Current Report on
Form 8-K dated February 20, 2002).
+10.30 -- Form of Amendment to Executive Officer Employment Agreement
(Incorporated herein by reference to Exhibit 99.7 to the Company's
Current Report on Form 8-K dated February 20, 2002).
+10.31 -- Form of Amendment to Director Indemnification Agreement
(Incorporated herein by reference to Exhibit 99.8 to the Company's
Current Report on Form 8-K dated February 20, 2002).
+10.32 -- Contribution and Subscription Agreement dated June 23, 2003 by and
among Pinnacle Gas Resources, Inc., CCBM, Inc., Rocky Mountain Gas,
Inc. and the CSFB Parties listed therein (Incorporated herein by
reference to Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2003).
+10.33 -- Transition Services Agreement dated June 23, 2003 by and between
the Company and Pinnacle Gas Resources, Inc. (Incorporated herein by
reference to Exhibit 10.2 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2003).
+10.34 -- Second Amended and Restated Credit Agreement dated as of September
30, 2004 by and among Carrizo Oil & Gas, Inc., CCBM, Inc., Hibernia
National Bank, as Agent, Union Bank of California, N.A., as co-agent,
and Hibernia National Bank and Union Bank of California, N.A., as
lenders (incorporated herein by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K filed on October 6, 2004).
+10.35 -- First Amendment to Second Amended and Restated Credit Agreement
dated as of October 29, 2004 among Carrizo Oil & Gas, Inc., CCBM,
Inc., Hibernia National Bank and Union Bank of California, N.A.
(incorporated herein by reference to Exhibit 10.6 to the Company's
Current Report on Form 8-K filed on November 3, 2004).
+10.36 -- Commercial Guaranty made and entered into as of September 30, 2004
by CCBM, Inc. in favor of Hibernia National Bank, as agent
(incorporated herein by reference to Exhibit 10.2 to the Company's
Current Report on Form 8-K filed on October 6, 2004).
+10.37 -- Amended and Restated Stock Pledge and Security Agreement dated and
effective as of September 30, 2004 by Carrizo Oil & Gas, Inc. in favor
of Hibernia National Bank, as agent (incorporated herein by reference
to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on
October 6, 2004).
+10.38 -- Note Purchase Agreement dated as of October 29, 2004 among Carrizo
Oil & Gas, Inc., the Purchasers named therein and PCRL Investments
L.P., as collateral agent (incorporated herein by reference to Exhibit
10.1 to the Company's Current Report on Form 8-K filed on November 3,
2004).
+10.39 -- Form of 10% Senior Subordinated Secured Note due 2008 (incorporated
herein by reference to Exhibit 10.2 to the Company's Current Report on
Form 8-K filed on November 3, 2004).
+10.40 -- Stock Pledge and Security Agreement dated as of October 29, 2004 by
Carrizo Oil & Gas, Inc. in favor of PCRL Investments L.P., as
collateral agent (incorporated herein by reference to Exhibit 10.3 to
the Company's Current Report on Form 8-K filed on November 3, 2004).
+10.41 -- Commercial Guaranty dated as of October 29, 2004 by CCBM, Inc. in
favor of PCRL Investments L.P., guarantying the indebtedness of
Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit
10.4 to the Company's Current Report on Form 8-K filed on November 3,
2004).
+10.42 -- Registration Rights Agreement dated as of October 29, 2004 among
Carrizo Oil & Gas, Inc. and the Investors named therein (incorporated
herein by reference to Exhibit 10.5 to the Company's Current Report on
Form 8-K filed on November 3, 2004).
10.43 -- Form of Stock Option Award Agreement.
+10.44 -- Employment Agreement between the Company and Gregory E. Evans dated
March 21, 2005 (incorporated herein by reference to Exhibit 10.1 to
the Company's Current Report on Form 8-K filed on March 22, 2005).
10.45 -- Director Compensation.
10.46 -- Base Salaries and 2004 Annual Bonuses for certain Executive
Officers.
21.1 -- Subsidiaries of the Company.
23.1 -- Consent of Pannell Kerr Forster of Texas, P.C.
23.2 -- Consent of Ernst & Young LLP.
23.3 -- Consent of Ryder Scott Company Petroleum Engineers.
23.4 -- Consent of Fairchild & Wells, Inc.
23.5 -- Consent of DeGolyer and MacNaughton.
31.1 -- CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2 -- CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
32.1 -- CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
32.2 -- CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers as of December 31, 2004.
99.2 -- Summary of Reserve Report of Fairchild & Wells, Inc. as of December
31, 2004.
99.3 -- Summary of Reserve Report of DeGolyer and MacNaughton as of
December 31, 2004.
- ----------
+ Incorporated by reference as indicated.