-----BEGIN PRIVACY-ENHANCED MESSAGE-----
Proc-Type: 2001,MIC-CLEAR
Originator-Name: webmaster@www.sec.gov
Originator-Key-Asymmetric:
MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen
TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB
MIC-Info: RSA-MD5,RSA,
FGIr1pJZ4n9rtznXhY1+UXq11amVxtLj0nLffFAI886GI/dljlC8+y7zFV7uCOct
roK9ZPru5Ij3jSlHf5HNDA==
0001040593-06-000042.txt : 20060612
0001040593-06-000042.hdr.sgml : 20060612
20060612120133
ACCESSION NUMBER: 0001040593-06-000042
CONFORMED SUBMISSION TYPE: 10-K/A
PUBLIC DOCUMENT COUNT: 11
CONFORMED PERIOD OF REPORT: 20041231
FILED AS OF DATE: 20060612
DATE AS OF CHANGE: 20060612
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: CARRIZO OIL & GAS INC
CENTRAL INDEX KEY: 0001040593
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 760415919
STATE OF INCORPORATION: TX
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K/A
SEC ACT: 1934 Act
SEC FILE NUMBER: 000-29187-87
FILM NUMBER: 06898943
BUSINESS ADDRESS:
STREET 1: 1000 LOUISIANA STREET
STREET 2: SUITE 1500
CITY: HOUSTON
STATE: TX
ZIP: 77002
BUSINESS PHONE: 7133281000
MAIL ADDRESS:
STREET 1: 1000 LOUISIANA STREET
STREET 2: SUITE 1500
CITY: HOUSTON
STATE: TX
ZIP: 77002
10-K/A
1
form_10-ka2004.htm
2004 FORM 10-K/A
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K/A
Amendment
No. 2 to Form 10-K filed March 31, 2005
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.
EXPLANATORY
NOTE
We
hereby
amend the following items of the Form 10-K of Carrizo Oil & Gas, Inc.
(“Carrizo,” the “Company” or “We”) for the year ended December 31, 2004 (the
“Form 10-K”), which was originally filed on March 31, 2005: (1) Part I - Item 1
“Business;” (2) Part I - Item 2 “Properties;” (3) Part II - Item 6 “Selected
Financial Data;” (4) Part II - Item 7 “Management’s Discussion and Analysis of
Financial Condition and Results of Operations;” (5) Part II - Item 8 “Financial
Statements and Supplementary Data;” (6) Part II - Item 9A “Controls and
Procedures;” and Part IV - Item 15 “Exhibit and Financial Statement Schedules.”
No other sections were affected.
This
Amendment No. 2 does not modify or update the disclosures in the Form 10-K
in
any way other than as required to reflect the amendments as described above
and
set forth below.
PART
I
|
4
|
|
4
|
PART
II
|
27
|
|
29
|
|
54
|
|
54
|
PART
IV
|
58
|
|
58
|
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/A 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
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:
· |
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). We
believe our use of 3-D seismic surveys reduces, but does not eliminate,
the risk of drilling.
|
· |
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. The use of 3-D seismic analysis does not
guarantee that hydrocarbons are present or, if present, that they
can be
recovered economically. 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
and
technical support staff, 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.
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.
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
|
|
|
|
3-D
|
|
NET
|
|
|
|
|
|
PRODUCTIVE |
|
|
|
|
|
DRILLING
CAPITAL
|
|
|
|
WELLS |
|
DATA
|
|
LEASED
|
|
EXPENDITURES
|
|
|
|
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
|
|
|
--
|
|
|
--
|
|
|
1,005
|
|
|
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.
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 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 late 2002, we completed a significant well in the area, which
produced an average of 9,787 Mcfe per day during the first 90 full days
of
production when it was placed on line in the spring of 2003. We operate
this
well and own a 40% working interest. In 2003, we had another significant
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 when placed on line
in
mid-June 2003. We operate this well and own a 46.3% working interest. Average
daily net production from our Liberty Project area was 3.3 Mmcfe, 4.5 Mmcfe
and
0.5 Mmcfe during the calendar years 2004, 2003 and 2002,
respectively.
As
of
March 1, 2005, we had identified 20 exploratory drilling locations and
an
additional two potential extension locations in the Liberty Project Area.
We
have since generated an additional eight exploratory drilling locations
from our
2005 seismic survey project, and we expect additional exploratory drilling
locations will be generated from our 2005 seismic survey project during
the
second half of 2005. As a result, our 2005 drilling budget provides for
drilling
of five of these exploratory locations. Accordingly, we expect to continue
significant drilling activity in the Liberty Project area in 2006.
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. In 2004, we incurred capital expenditures
of
$8.9 million and drilled four wells (1.7 net) in the South Louisiana area,
successfully completing three of the four wells. The aggregate initial
and
current (as of October 31, 2004) from these three successful wells drilled
in
2004 were 11,350 Mcfe/d (4,459 Mcfe/d net) and 8,220 Mcfe/d (4,111 Mcfe/d
net),
respectively. We 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.
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. From January 1, 2001 to December 31, 2004, we drilled and completed
nine wells (2.5 net) on 14 attempts in this area. WeIn 2004, we incurred
capital
expenditures of $8.9 million and drilled four wells (1.7 net) in the South
Louisiana area in 2004 and, successfully completing three of the four wells.
The
aggregate initial and current (as of October 31, 2004) from these three
successful wells drilled in 2004 were 11,350 Mcfe/d (4,459 Mcfe/d net)
and 8,220
Mcfe/d (4,111 Mcfe/d net), respectively. We expect to devote approximately
$17.8
million to drill ten wells (6.0 net) in this area in 2005. 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). We
have in the past used, and plan in the future to use, a tertiary steam
drive. In
response to high fuel gas prices, steam injection was suspended in mid-2000.
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). Of those wells, 484 encountered coal accumulations.
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.
As
of
August 31, 2005, Pinnacle had drilled 345 wells; of these 345 wells, (1)
256 are
producing gas; (2) 18 remain in the completion/hook-up phase; (3) 46 are
in the
dewatering phase with no early indication as to gas production; (4) 22
are
waiting on or being evaluated for workovers or redrill or plugging and
abandonment; and (5) three of these wells did encounter coal
accumulations.
As
of
August 31, 2005, of the 241 wells that Pinnacle had acquired, (1) 71 are
producing gas, (2) 108 remain in the completion/hook-up phase; (3) 27 are
in the
dewatering phase with no early indication as to gas production; (4) 12
are
waiting on or being evaluated for workovers or redrill or plugging and
abandonment; (5) 18 that are producing gas at uneconomic rates are currently
shut in; and (6) five have been plugged and abandoned.
The
dewatering process may require significant time and resources, and there
can be
no assurance that a well that encounters coal accumulations will in fact
produce
gas in commercial quantities. The ultimate commercial success of the well
will
depend upon several factors, including the establishment of gas and/or
water
inflow, the presence of pipelines and infrastructure, the satisfaction
of
engineering or production issues and other risks and uncertainties associated
with drilling activities.
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/A. The PV-10 Value was prepared using constant prices as of the
calculation date, discounted at 10% per annum on a pretax basis, and is
not
intended to represent the current market value of the estimated oil and
natural
gas reserves owned by us. For further information concerning the present
value
of future net revenue from these proved reserves, see Note 15 of Notes
to
Consolidated Financial Statements.
|
|
PROVED
RESERVES
|
|
|
|
|
|
|
|
Developed
|
|
Undeveloped
|
|
Total
|
|
|
|
(dollars
in thousands)
|
|
|
|
|
|
Oil
and condensate (MBbls)
|
|
|
1,459
|
|
|
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/A 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.”
DeGolyer
and MacNaughton determined 29% of our proved reserves for the year ended
December 31, 2004, which reserves were located on our Barnett Shale properties.
Fairchild & Wells, Inc. determined 47% of our proved reserves for the year
ended December 31, 2004, which reserves were located on our properties
in the
Camp Hill field. Ryder Scott Company Petroleum Engineers determined 24%
of our
proved reserves for the year ended December 31, 2004, which reserves were
located on our Gulf Coast and all other remaining properties.
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
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
|
|
$
|
41.00
|
|
Natural
gas (per Mcf)
|
|
|
3.50
|
|
|
5.35
|
|
|
6.14
|
|
Natural
gas equivalent (per Mcfe)
|
|
|
3.72
|
|
|
5.16
|
|
|
6.30
|
|
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.
|
|
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.
In
order
to maintain continued growth and profitability, our annual goal is to add
new
reserves exceeding our yearly production at a finding and development cost
that
contributes to an acceptable profit margin. Accordingly, we use the finding
and
development cost in combination with our reserve replacement ratio, as
previously defined, to measure our operating and financial
performance.
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.
|
|
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.
|
|
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.
|
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;
-
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 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.
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.
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,
six engineers and six landmen. 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 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/A. 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;
|
· |
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.
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 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.
PART
II
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, including restatements described
in
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations.” The information should be read in conjunction with “Management’s
Discussion and Analysis of Financial Condition and Results of Operations” and
our consolidated financial statements and related notes included in Item
8.
Financial Statements and Supplementary Data.
|
|
Year
Ended December 31,
|
|
|
|
2000
|
|
2001
|
|
2002
|
|
2003
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
|
|
(In
thousands, except per share data)
|
|
Statement
Of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas revenues
|
|
$
|
26,834
|
|
$
|
26,226
|
|
$
|
26,802
|
|
$
|
38,508
|
|
$
|
52,397
|
|
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
|
|
|
20,263
|
|
Market-to-market
loss on derivatives, net
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(625
|
)
|
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
|
|
|
18,123
|
|
Income
tax expense (benefit)
|
|
|
1,004
|
|
|
5,336
|
|
|
2,809
|
|
|
5,063
|
|
|
7,009
|
|
Income
before cumulative effect of change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
in
accounting principle
|
|
|
11,985
|
|
|
9,531
|
|
|
4,790
|
|
|
8,040
|
|
|
11,114
|
|
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
|
|
|
10,764
|
|
Cumulative
effect of change in accounting principle
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(128
|
)
|
|
-
|
|
Net
income available to common shareholders
|
|
$
|
11,985
|
|
$
|
9,531
|
|
$
|
4,202
|
|
$
|
7,171
|
|
$
|
10,764
|
|
Basic
earnings per common share
|
|
$
|
0.85
|
|
$
|
0.68
|
|
$
|
0.30
|
|
$
|
0.50
|
|
$
|
0.54
|
|
Diluted
earnings per common share
|
|
$
|
0.74
|
|
$
|
0.57
|
|
$
|
0.26
|
|
$
|
0.43
|
|
$
|
0.49
|
|
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
|
)
|
|
(80,294
|
)
|
Net
cash provided by (used in) financing activities
|
|
|
(3,823
|
)
|
|
2,292
|
|
|
5,682
|
|
|
(5,379
|
)
|
|
50,139
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
$
|
19,746
|
|
$
|
38,264
|
|
$
|
23,343
|
|
$
|
31,930
|
|
$
|
83,891
|
|
Debt
repayments (1 )
|
|
|
3,923
|
|
|
5,479
|
|
|
8,745
|
|
|
5,951
|
|
|
13,737
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As
of December 31,
|
|
|
|
2000
|
|
2001
|
|
2002
|
|
2003
|
|
2004
|
|
|
|
|
|
|
|
|
|
|
|
(Restated)
|
|
Balance
Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
Working
capital (deficit)
|
|
$
|
6,433
|
|
$
|
(582
|
)
|
$
|
(1,442
|
)
|
$
|
(11,817
|
)
|
$
|
(8,937
|
)
|
Property
and equipment, net
|
|
|
72,129
|
|
|
104,132
|
|
|
120,526
|
|
|
135,273
|
|
|
205,482
|
|
Total
assets
|
|
|
93,000
|
|
|
117,392
|
|
|
135,388
|
|
|
156,803
|
|
|
234,345
|
|
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
|
|
|
121,060
|
|
__________
(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/A. The financial
information in this section has been restated, as further discussed in
“Item 8.
Financial Statements and Supplementary Data - Note 3 - Financial
Restatement”. The 2004 to 2003 period to period comparison is based upon
restated amounts. Our financial statements and the notes thereto, which
are
found elsewhere in the Form 10-K/A contain detailed information that should
be
referred to in conjunction with the following discussion.
Restatement
In
connection with the preparation
of our
consolidated financial statements for the year ended December 31, 2005,
we
reviewed our accounting policy used to account for our derivatives on oil
and
natural gas prices on our proved producing properties and determined that
these
instruments should have been accounted for as non-designated derivatives
instead
of cash flow hedges in accordance with Statement of Financial Accounting
Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging
Activities.” Accordingly, as a result of the changes in accounting for our
derivatives for the oil and natural gas hedges we have restated our consolidated
financial statements for the year ended December 31, 2004, as presented
in this
Form 10-K/A. In addition to the financial statements for the year ended
December
31, 2004, these changes in accounting affect the four quarterly periods
of 2004.
See Note 3 and Note 17 to the Company’s consolidated financial
statements.
Under
cash flow hedge accounting, the after-tax change in the fair value of the
open
derivative positions (“fair value change”) is reported as Other Comprehensive
Income in the equity section of the balance sheet. Alternatively, if the
derivative does not qualify as a cash flow hedge, mark-to-market accounting
requires that the fair value change be reported in earnings. For our cash
flow
commodity hedges, we had accounted for the realized gain or losses on these
hedging activities as being recognized in earnings as oil and natural gas
revenues when the forecasted transaction occurred. Our derivative instruments
had previously been accounted for as cash flow hedges.
The
Company has determined that the derivatives entered into in 2004 were not
timely
designated as cash flow hedges and lacked sufficient documentation to be
accounted for as cash flow hedges. As a result, the Company is restating
its
financial statements for the year ended December 31, 2004 and all the unaudited
quarterly periods in 2004. All such derivatives in this restatement are
now
classified as non-designated derivatives and are marked-to-market, with
realized
and unrealized gains and losses being reflected as “mark-to-market gains
(losses) on derivatives, net” within the other income and expense section of the
Statement of Operations.
In
the
process of restating our financials to account for our derivatives on a
mark-to-market basis, we discovered certain computational errors in the
fair
value of the Company’s derivatives that was previously reported in other
comprehensive income in 2004. These errors resulted from the information
we had
relied upon to establish oil and gas prices in connection with establishing
the
fair value of the derivatives. For all the periods covered by our consolidated
financial statements, we used a third-party website source to obtain oil
and gas
market prices and to calculate the fair value of the derivatives. However,
we
determined in the course of our evaluation that the information from the
third
party provider was not entirely reliable and that Houston Ship Channel
market
prices should have been used in the fair value computation in place of
New York
Mercantile (“NYMEX”) index prices. Nevertheless, in marking these derivatives to
market, the gains and losses reflected in the other income and expense
have been
based upon corrected fair valuations and were not based upon the information
from the third party provider.
These
restated amounts have previously been disclosed in our Form 10-K/A amendment
to
Form 10K for the fiscal year ended December 31, 2005, filed with the SEC
on
April 11, 2006.
Details
of these restatements are presented in this Form 10-K/A in Note 3 to the
consolidated financial statements. Where appropriate, notes to the consolidated
financial statements and certain other disclosures in this Form 10-K/A
have been
adjusted to conform to these restatements. A summary of the restated periods
is
comprised as follows:
|
|
Year
Ended
|
|
|
|
December
31, 2004
|
|
|
|
As
|
|
As
|
|
|
|
Reported
|
|
Restated
|
|
Statement
of Operations:
|
|
|
|
|
|
Oil
and natural gas revenues
|
|
$
|
51,374
|
|
$
|
52,397
|
|
Operating
income
|
|
|
19,240
|
|
|
20,263
|
|
|
|
|
|
|
|
|
|
Mark-to-market
loss of derivatives, net
|
|
|
-
|
|
|
(625
|
)
|
Income
before income taxes
|
|
|
17,725
|
|
|
18,123
|
|
Income
tax Expense
|
|
|
6,871
|
|
|
7,009
|
|
Net
income
|
|
|
10,854
|
|
|
11,114
|
|
Net
income available to common shareholders
|
|
$
|
10,504
|
|
$
|
10,764
|
|
Earnings
per common share
|
|
|
|
|
|
|
|
Basic
Earnings per common share
|
|
$
|
0.53
|
|
$
|
0.54
|
|
Diluted
earnings per common share
|
|
$
|
0.48
|
|
$
|
0.49
|
|
|
|
Year
Ended
|
|
|
|
December
31, 2004
|
|
|
|
As
|
|
As
|
|
|
|
Reported
|
|
Restated
|
|
Cash
Flow Statement:
|
|
|
|
|
|
Net
income
|
|
$
|
10,854
|
|
$
|
11,114
|
|
Fair
value (gain) of derivative financial instruments
|
|
|
-
|
|
|
(400
|
)
|
Deferred
income taxes
|
|
|
6,678
|
|
|
6,818
|
|
Net
cash provided by operating activities
|
|
|
32,501
|
|
|
32,501
|
|
|
|
Year
Ended
|
|
|
|
December
31, 2004
|
|
|
|
As
|
|
As
|
|
|
|
Reported
|
|
Restated
|
|
Statement
of Shareholders' Equity
|
|
|
|
|
|
Net
income
|
|
$
|
10,854
|
|
$
|
11,114
|
|
Accumulated
other comprehensive income
|
|
|
59
|
|
|
-
|
|
Comprehensive
income
|
|
|
11,099
|
|
|
11,300
|
|
|
|
December
31, 2004
|
|
|
|
As
|
|
As
|
|
|
|
Reported
|
|
Restated
|
|
Balance
Sheet:
|
|
|
|
|
|
Other
current assets
|
|
$
|
1,614
|
|
$
|
1,924
|
|
Total
current assets
|
|
|
21,634
|
|
|
21,944
|
|
Other
assets
|
|
|
57
|
|
|
57
|
|
Total
assets
|
|
|
234,035
|
|
|
234,345
|
|
Accrued
liabilities
|
|
|
7,516
|
|
|
7,624
|
|
Total
current liabilities
|
|
|
30,772
|
|
|
30,881
|
|
Deferred
Income Taxes
|
|
|
18,113
|
|
|
18,113
|
|
Retained
earnings
|
|
|
20,733
|
|
|
20,993
|
|
Accumulated
other comprehensive income
|
|
|
59
|
|
|
-
|
|
Total
Liabilities and Shareholders' Equity
|
|
|
234,035
|
|
|
234,345
|
|
Quarterly
Financial Statements (Restated) (Unaudited)
|
|
Quarters
Ended
|
|
|
March
31, 2004
|
|
June
30, 2004
|
|
September
30, 2004
|
|
December
31, 2004
|
|
|
|
As
Reported
|
|
As
Restated
|
|
As
Reported
|
|
As
Restated
|
|
As
Reported
|
|
As
Restated
|
|
As
Reported
|
|
As
Restated
|
|
Statement
of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and Natural Gas Revenues
|
|
$
|
10,873
|
|
$
|
10,861
|
|
$
|
11,959
|
|
$
|
11,935
|
|
$
|
12,274
|
|
$
|
13,041
|
|
$
|
16,268
|
|
$
|
16,560
|
|
Operating
Income
|
|
|
3,801
|
|
|
3,789
|
|
|
3,907
|
|
|
3,883
|
|
|
5,274
|
|
|
6,041
|
|
|
6,258
|
|
|
6,550
|
|
Mark-to-market
gain (loss) of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivatives,
net
|
|
|
-
|
|
|
(972
|
)
|
|
-
|
|
|
460
|
|
|
-
|
|
|
(1,296
|
)
|
|
-
|
|
|
1,183
|
|
Income
Before Income Taxes
|
|
|
3,536
|
|
|
2,552
|
|
|
3,526
|
|
|
3,962
|
|
|
5,469
|
|
|
4,940
|
|
|
5,194
|
|
|
6,669
|
|
Income
Tax Expense
|
|
|
1,353
|
|
|
1,008
|
|
|
1,388
|
|
|
1,539
|
|
|
2,079
|
|
|
1,893
|
|
|
2,051
|
|
|
2,569
|
|
Net
Income
|
|
|
2,183
|
|
|
1,544
|
|
|
2,138
|
|
|
2,423
|
|
|
3,390
|
|
|
3,047
|
|
|
3,143
|
|
|
4,100
|
|
Net
Income Available to
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Shareholders
|
|
|
1,985
|
|
|
1,346
|
|
|
1,986
|
|
|
2,271
|
|
|
3,390
|
|
|
3,047
|
|
|
3,143
|
|
|
4,100
|
|
Earnings
per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per common share
|
|
$
|
0.12
|
|
$
|
0.08
|
|
$
|
0.10
|
|
$
|
0.12
|
|
$
|
0.15
|
|
$
|
0.14
|
|
$
|
0.16
|
|
$
|
0.19
|
|
Diluted
earnings per common
share
|
|
$
|
0.10
|
|
$
|
0.07
|
|
$
|
0.09
|
|
$
|
0.10
|
|
$
|
0.15
|
|
$
|
0.13
|
|
$
|
0.14
|
|
$
|
0.18
|
|
In
conjunction with the Restatement of the quarterly information above, the
respective Form 10-Qs as previously filed for the quarterly periods ended
March
31, 2004, June 30, 2004 and September 30, 2004 should no longer be relied
upon.
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.”
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, our realized natural gas price was 15% higher and our realized oil
price
was 42% 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 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.
Derivative
Transactions
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 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 derivative 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 36% to $52.4 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 15% to
$6.14
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.
Average
oil prices increased 42% to $41.00 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
|
|
$
|
41.00
|
|
$
|
12.10
|
|
|
42
|
%
|
Natural
gas (per Mcf)
|
|
|
5.35
|
|
|
6.14
|
|
|
0.79
|
|
|
15
|
%
|
Operating
revenues (In thousands) -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and condensate
|
|
$
|
13,014
|
|
$
|
12,687
|
|
$
|
(327
|
)
|
|
(3
|
%)
|
Natural
gas
|
|
|
25,494
|
|
|
39,710
|
|
|
14,216
|
|
|
56
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
38,508
|
|
$
|
52,397
|
|
$
|
13,889
|
|
|
36
|
%
|
__________
(1) Including
the impact of hedging in 2003.
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.
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.
Mark-to-market
gain (loss) on derivatives, net was ($0.6) million in 2004 comprised of
(1) $1.0
million of realized loss on net settled derivatives and (2) $0.4 million
of net
unrealized gain on the derivatives. There were no such gains reported in
2003.
Income
taxes increased to $7.0 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 $10.8
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 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:
|
|
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 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 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.
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
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 exercisable
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.
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
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 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. Proved reserves materially impact depletion
expense. If the proved reserves decline, then the depletion rate (the rate
at
which we record depletion expense) increases, reducing net income.
We
have a
significant amount of proved undeveloped reserves, which are primarily
oil
reserves. We had 42.0 Bcfe, 44.9 Bcfe and 72.5 Bcfe of proved undeveloped
reserves, representing 66%, 64% and 66% of our total proved reserves at
December
31, 2002, 2003 and 2004, respectively. As of December 31, 2002, 2003 and
2004, a
portion of these proved undeveloped reserves, or approximately 41.9 Bcfe,
43.9
Bcfe and 45.7 Bcfe, 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 (the estimated time that it will take to produce all recoverable reserves)
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, causing
the
build-up of nondepleted capitalized costs associated with properties that
have
been completely depleted. This combination of factors, in turn, has had
a
favorable impact on our earnings, which have
been
higher than they would have been had the Camp Hill properties not resulted
in a
relatively low overall depletion rate and DD&A expense and longer depletion
period. As a hypothetical illustration of this impact, the removal of our
Camp
Hill proved undeveloped reserves starting January 1, 2002 would have reduced
our
earnings by (i) an estimated $11.2 million in 2002 (comprised of after-tax
charges for a $7.1 million full cost ceiling impairment and a $4.1 million
depletion expense increase), (ii) an estimated $5.9 million in 2003 (due
to
higher depletion expense) and (iii) an estimated $3.4 million in 2004 (due
to
higher depletion expense).
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
Upon
entering into a derivative contract, we must either designate the derivative
instruments as a hedge of the variability of cash flow to be received (cash
flow
hedge) or the derivatives must be accounted for as non-designated derivatives.
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 had been designated
as cash flow hedges. However, in connection with the preparation of our
consolidated financial statements for the year ended December 31, 2005,
we
determined that we had not timely designated the instruments as a cash
flow
hedges and was lacking certain other documentation for the derivatives
entered
into during 2004. As a result, we are restating in this Form 10-K/A the
consolidated financial information for 2004 (and the quarterly financial
data
for all periods in 2004), accounting for them as non-designated derivatives.
Accordingly, these derivatives will be marked-to-market at the end of each
period and the realized and unrealized gain or loss will be recorded as
market
to market gains and losses on derivatives, net within other income on our
Statement of Income. See Note 3 of the notes to the consolidated financial
statements for further discussion of the financial restatement.
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.
For
2003
and prior years, we typically used fixed rate swaps and costless collars
to
hedge our exposure to material changes in the price of natural gas and
oil. We
formally documented all relationships between
hedging
instruments and hedged items, as well as our risk management objectives
and
strategy for undertaking various hedge transactions. This process included
linking all derivatives that are designated cash flow hedges to forecasted
transactions. We also formally assessed, 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 risk management 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 derivative
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
MMBtu, 2,739,000 MMBtu and 3,936,000 MMBtu, respectively.
The net
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
were
included in oil and natural gas revenues for 2002 and 2003 and mark-to-market
gain (loss) on derivative, net for 2004.
To
mitigate some of our commodity price risk, we engage periodically in certain
other limited derivative activities including price swaps, costless collars
and,
occasionally, put options, in order to establish some price floor protection.
For derivatives designated as cash flow hedges, 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. 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, unrealized gains on oil and gas derivatives of $0.4
million
were included in mark-to-market gain on derivatives, net.
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 derivative 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 derivative transaction. Moreover,
our derivative 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 Houston Ship Channel index 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 West Texas Intermediate index 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 Houston Ship Channel 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 Houston Ship Channel 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 derivative positions:
December
31, 2003
|
|
|
|
|
|
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 derivative 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 on the success of our drilling efforts,
which
involve numerous risks, including the risk that no commercially productive
natural gas or oil reservoirs will be discovered. Historically, we have
been
particularly dependent upon exploratory drilling, which generally involves
greater risk than developmental drilling. The cost of drilling, completing
and
operating wells is substantial and uncertain, and drilling operations may
be
curtailed, delayed or canceled as a result of a variety of factors beyond
our
control, including:
· |
unexpected
or adverse drilling conditions;
|
· |
elevated
pressure or irregularities in geologic formations;
|
· |
equipment
failures or accidents;
|
· |
adverse
weather conditions;
|
· |
compliance
with governmental requirements; and
|
· |
shortages
or delays in the availability of drilling rigs, crews and
equipment.
|
Because
we identify the areas desirable for drilling from 3-D seismic data covering
large areas, we may not seek to acquire an option or lease rights until
after
the seismic data is analyzed or until the drilling locations are also
identified; in those cases, we may not be permitted to lease, drill or
produce
natural gas or oil from those locations. 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. 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 reduce
our
available cash and other resources, which would result in a significant
decline
in our production and revenues. 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/A.
WE
MAY NOT ADHERE TO OUR PROPOSED DRILLING SCHEDULE.
Our
final
determination of whether to drill any scheduled or budgeted wells will
depend on
a number of factors, including:
· |
the
results of our exploration efforts and the acquisition, review
and
analysis of our 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, license options, farm-outs, other rights
to
explore 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.
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.
There
are
uncertainties
inherent in estimating natural gas and oil reserves and their estimated
values,
including many factors beyond the control of the producer. The reserve
data set
forth in this Form 10-K/A 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 this Form 10-K/A represents estimates that depend
on a
number of factors
and
is based
on
assumptions that may vary considerably from actual results,
including:
· |
historical
production from the area compared with production from other
areas;
|
· |
the
assumed effects of regulations by governmental agencies;
|
· |
assumptions
concerning future natural gas and oil prices;
|
· |
future
operating costs;
|
· |
severance
and excise taxes;
|
· |
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 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/A are not
necessarily the same as the current market value of our estimated natural
gas
and oil reserves. As required by the
SEC,
the
estimated discounted future net cash flows from proved reserves are based
on
prices and costs as of the date of the estimate. Actual future net cash
flows
also will be affected by factors such as:
· |
the
actual prices we receive for natural gas and oil;
|
· |
our
actual operating costs in producing natural gas and oil;
|
· |
the
amount and timing of actual production;
|
· |
supply
and demand for natural gas and oil;
|
· |
increases
or decreases in consumption of natural gas and oil; and
|
· |
changes
in governmental regulations or taxation.
|
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 depletion dependent on reservoir
characteristics. Our proved reserves will decline as reserves are produced
unless we conduct successful exploration and development activities or
acquire
properties containing proved reserves, or both. Our future natural gas
and oil
production is, therefore, highly dependent on our level of success in finding
or
acquiring additional reserves. In
addition, we must find 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 may be unable to complete
our
desired exploratory activity, and our ability to maintain or expand our
asset
base of natural gas and oil reserved would be impaired.
NATURAL
GAS AND OIL PRICES ARE HIGHLY VOLATILE, AND LOWER PRICES WILL NEGATIVELY
AFFECT
OUR FINANCIAL RESULTS.
Prevailing
prices of natural gas and oil substantially affect 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.
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;
|
· |
domestic
and foreign governmental relations;
|
· |
the
price and availability of alternative fuels;
|
· |
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 on 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, particularly given our size, 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 that is appropriate for our activities, our business, financial
condition and results of operations could be materially adversely
affected.
WE
ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS AND ENVIRONMENTAL
RISKS.
Natural
gas and oil operations are subject to various federal, state and local
government regulations that may change from time to time. Matters subject
to
regulation include discharge permits for drilling operations, plug and
abandonment bonds, reports concerning operations, the spacing of wells,
unitization and pooling of properties and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on production
by
restricting the rate of flow of natural gas and oil wells below actual
production capacity in order to conserve supplies of natural gas and oil.
Other
federal, state and local laws and regulations relating primarily to the
protection of human health and the environment apply to the development,
production, handling, storage, transportation and disposal of natural gas
and
oil, by-products thereof and other substances and materials produced or
used in
connection with natural gas and oil operations. In addition, we may be
liable
for environmental damages caused by previous owners of property we purchase
or
lease. As a result, we may incur substantial liabilities to third parties
or
governmental entities and may be required to incur substantial remediation
costs. Further, we or our affiliates hold certain mineral leases in the
State of
Montana that require coalbed methane drilling permits, the issuance of
which has
been challenged in pending litigation. We may not be able to obtain new
permits
in an optimal time period or at all. We also are subject to changing and
extensive tax laws, the effects of which cannot be predicted. Compliance
with
existing, new or modified laws and regulations could have a material adverse
effect on our business, financial condition and results of
operations.
WE
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. While
we
intend to obtain and maintain appropriate insurance coverage for these
risks,
there can be no assurance that our operations will not expose us to liabilities
exceeding such insurance coverage or to liabilities not covered by
insurance.
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
of
December 31, 2004, a majority of the gross wells in which we had an interest
were operated by others. We
have
limited ability to exercise influence over, and control the risks associated
with, operations of the properties we do not operate.
The
failure of an operator of our wells to adequately perform operations, an
operator’s breach of the applicable agreements or an operator’s failure to act
in ways that are in our best interests could reduce our production and
revenues.
The success and timing of our drilling and development activities on properties
operated by others therefore depend on 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
|
THE
MARKETABILITY OF OUR 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 on the proximity of our
reserves
to, and the availability and capacity of, facilities and third party services,
including oil and natural gas gathering systems, pipelines, trucking or
terminal
facilities 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 those of our transportation agreements
that are
interruptible, the transportation of our natural 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.
The
unavailability or lack of capacity of third party services and facilities
could
result in the shut-in of our producing wells or the delay or discontinuance
of
development plans for properties, any of which could adversely affect our
revenues and financial condition.
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
economically unsuccessful acquisitions may have a material adverse effect
on our
financial condition and future results of operations. We have grown primarily
through exploratory activities rather than the acquisition of producing
properties. Our experience in acquisitions, therefore, has been limited,
which
could heighten this risk.
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
financial,
technical, operational and administrative 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;
|
· |
our
ability to maintain or enter into new relationships with project
partners
and independent contractors;
|
· |
the
results of our drilling program;
|
· |
hydrocarbon
prices; and
|
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.
WHEN
WE
HEDGE THE PRICE RISKS ASSOCIATED WITH OUR PRODUCTION, WE MAY BE REQUIRED
TO MAKE
CASH PAYMENTS OR PREVENTED 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.
Even
if
additional capital becomes available, it may not be on terms acceptable
to
us. 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 materially adversely affecting our business, financial
condition and results of operations.
Our
ability to raise additional capital will depend on the results of operations
and
the status of various capital and industry markets at the time such additional
capital is sought. Accordingly, capital may not become available to us
from any
particular source or at all. Even if additional capital becomes available,
it
may not be on terms acceptable to us.
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’s
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;
|
· |
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 on 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 above in “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.” Once
incurred, a write-down of natural gas and oil properties is not reversible
at a
later date.
Item
8. Financial Statements and Supplementary
Data
The
response to this item is included elsewhere in this report.
(a) DISCLOSURE
CONTROLS AND PROCEDURES. We maintain disclosure controls and procedures
that are
designed to provide reasonable assurance that information required to be
disclosed by us in the reports that we file or submit to the Securities
and
Exchange Commission under the Securities Exchange Act of 1934, as amended
(the
“Exchange Act”), is recorded, processed, summarized and reported within the time
periods specified by the Commission’s rules and forms, and that information is
accumulated and communicated to our management, including our Chief Executive
Officer and Chief Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
In
accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure
controls
and procedures as of the end of the period covered by this report. As described
below under Management’s Annual Report on Internal Control over Financial
Reporting, we identified material weaknesses in the Company’s internal control
over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)). As a result of these material weaknesses, our Chief Executive
Officer and Chief Financial Officer have concluded that, as of the end
of the
period covered by this Annual Report on Form 10-K/A, the Company’s disclosure
controls and procedures were not effective. The Company has outlined a
number of
initiatives, as discussed below under paragraph (b) of this Item
9A.
The
audit
report of Pannell Kerr Forster of Texas, P.C., dated March 15, 2005, which
was
included in the Form 10-K, expressed an unqualified opinion on our consolidated
financial statements, and its assessment of Management’s Annual Report on
Internal Control over Financial Reporting is included herein under paragraph
(d)
of this Item 9A.
(b) MANAGEMENT’S
ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING. Management,
including the Company’s Chief Executive Officer and Chief Financial Officer, has
the responsibility for establishing and maintaining adequate internal control
over financial reporting, as defined in Exchange Act Rule 13a-15(f). Internal
control over financial reporting is a process designed by, or under the
supervision of, the Company’s principal executive and principal financial
officers, or persons performing similar functions and effected by the Company’s
Board of Directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with accounting
principles generally accepted in the United States of America (“GAAP”). Because
of its inherent limitations, internal control over financial reporting
may not
prevent or detect misstatements. In addition, projections of any evaluation
of
effectiveness to future periods are subject to the risk that controls may
become
inadequate or insufficient because of changes in operating conditions,
or that
the degree of compliance with the policies or procedures may
deteriorate.
A
control
deficiency exists when the design or operation of a control does not allow
management or employees, in the ordinary course of performing their assigned
functions, to prevent or detect misstatements on a timely basis. A significant
deficiency is a control deficiency, or combination of control deficiencies,
that
adversely affects the Company’s ability to initiate, authorize, record, process,
or report external financial data reliably in accordance with GAAP, such
that
there is a more than remote likelihood that a misstatement of the Company’s
annual or interim financial statements that is more than inconsequential
will
not be prevented or detected. A material weakness is a control deficiency,
or
combination of control deficiencies, that results in more than a remote
likelihood that a material misstatement of the annual or interim financial
statements will not be prevented or detected.
Management
assessed internal control over financial reporting of the Company and its
subsidiary as of December 31, 2004. The Company’s management conducted its
assessment in accordance with the Internal Control -- Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
(“COSO”):
CLOSING
CYCLE
Upon
completion of the Company’s Sarbanes-Oxley Compliance assessment, the Company
identified the following control deficiencies present in its closing
cycle.
· |
The
accounting
system is a manually intensive system, requiring the extensive
use of
spreadsheets to accumulate data and prepare the underlying support
for
reconciliations, account analysis and routine journal entries,
all of
which increases the review time and chance for
error.
|
· |
The
current vacancy on the accounting staff for a financial reporting
director, partially remedied by reliance upon independent financial
reporting consultants for review of critical accounting areas and
disclosures and material non-standard
transactions.
|
As
described below, when considered in the aggregate, these deficiencies
constituted a material weakness over the effectiveness of detection and
monitoring controls over the financial statement close process. These
deficiencies ultimately affect the accuracy of our financial statement
reporting
and disclosures. As a result, management has concluded that our internal
controls over financial reporting were not effective as of December 31,
2004.
The Company had previously noted conditions related to the sufficiency
of review
applied to the financial statement closing process in connection with the
finalization of its 2003 financial statements.
The
manual year-end closing processes were performed substantially by our accounting
and finance staff, with some reliance on contract professionals and financial
reporting consultants. The combination of our manual, review intensive
accounting system and the absence of a financial reporting director placed
greater burdens of detailed reviews upon our middle and upper-level accounting
professionals which, in turn compromised the level of their qualitative
review
of the financial statements and disclosures in the time available. These
review
procedures are an important component of our controls surrounding the closing
process. As a result, we believe that the lack of a financial reporting
director, the greater demands on the time of our accounting staff and their
overall
workload
resulted in inadequate staffing, supervision and financial reporting expertise
in our accounting department, which constituted a material weakness in
our
internal controls as of December 31, 2004.
Accordingly,
in connection with its audit of our 2004 financial results, Pannell Kerr
Forster
of Texas, P.C. (“PKF”), our independent registered public accounting firm,
detected a number of errors and/or omissions, none of which were material,
individually or in aggregate, but were an indication that the aforementioned
material weakness was present at December 31, 2004, increasing the likelihood
to
more than remote that a material misstatement of the Company’s annual or interim
financial statements will not be prevented or detected. The most notable
of
these errors related to stock based compensation expense and related footnote
disclosures. Correcting adjustments were recorded by the Company prior
to the
finalization of its 2004 financial statements. The Company has implemented
procedures to prevent these specific errors from occurring in the future.
However, the additional initiatives (outline below), are needed to remediate
the
material weakness in our internal controls, and thus lower the risk level
to
remote of other potential material errors or omissions.
We
plan
to take the following initiatives in 2005: (1) increasing the level of
our
professional accounting staff, including the successful placement of a
financial
reporting professional (recruiting efforts were begun in the second half
of
2004), (2) expanding the use of independent reviews by outside financial
reporting experts during the vacancy of our financial reporting position,
and
(3) completing our transition to a new fully-integrated accounting software
system (data conversion began in 2004) to automate processes and improve
qualitative reviews. Until these initiatives are fully implemented, we
will
continue to rely on manual processes and require additional commitment
of
resources to the closing process to produce our financial records and reports.
We have discussed this material weakness and our remediation steps with
our
Audit Committee.
Subsequent
to management’s original annual report on internal controls over financial
reporting in the Company’s 10-K/A filed on May 2, 2005, management determined
that other material weaknesses existed as of December 31, 2004, as described
in
the following two paragraphs:
In
connection with the preparation of our consolidated financial statements
for the
year ended December 31, 2005, we completed a review of our documentation
practices underlying our derivative positions in 2004 and determined that
we
lacked sufficient contemporaneous documentation and did not timely designate
our
derivative positions at inception as cash flow hedges as required by Statement
of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative
Instruments and Hedging Activities” to account for these positions as cash flow
hedges. Under cash flow hedge accounting, the after-tax change in the fair
value
of the open derivative positions (“fair value change”) is reported as Other
Comprehensive Income in the equity section of the balance sheet. Alternatively,
if the derivative does not qualify as a cash flow hedge, mark-to-market
accounting requires that the fair value change be reported in earnings.
This
error came to management’s attention during the preparation of our Consolidated
Financial Statements for the year ended December 31, 2005 which ultimately
resulted in a restatement of our financial statements for 2004.
In
the
process of restating our financials to account for our derivatives on a
mark-to-market basis, we discovered certain computational errors in the
fair
value of the Company’s derivatives that was previously reported in other
comprehensive income in 2004. These errors resulted from the information
we had
relied upon to establish oil and gas prices used in connection with determining
the fair value of the derivatives. For all the periods covered by our
consolidated financial statements, we used a third-party website source
to
obtain New York Mercantile (“NYMEX”) oil and gas prices and then used those
prices to determine the fair value of the derivatives. However, we determined
in
the course of our evaluation that the use of Houston Ship Channel prices
was
instead required for this purpose which matched the index used within our
derivative agreements, furthermore we also determined that the information
from
the third party provider was not entirely reliable. As a result of the
restatement relating to our change in the treatment of our derivatives,
we no
longer report the change in fair value of our derivatives in other comprehensive
income but now record them as a change to earnings. Nevertheless, in marking
these derivatives to market, the gains and losses reflected in other income
and
expense have been based upon corrected amounts that were not based upon
the
information from the third party provider. These items constituted an additional
material weakness in our internal controls as of December 31, 2004. Additional
information relating to these items is included in Note 3 to the Company’s
consolidated financial statements.
PKF
has
issued its own attestation report on management’s assessment of the
effectiveness of internal control over financial reporting as of December
31,
2004, which is filed herewith.
(c) CHANGES
IN INTERNAL CONTROL OVER FINANCIAL REPORTING. There have not been any changes
in
the Company’s internal control over financial reporting during the fiscal
quarter ended December 31, 2004 that have materially affected, or are reasonably
likely to materially affect, the Company’s internal control over financial
reporting. As described above in paragraph (b) of this Item 9A under
Management’s Annual Report on Internal Control over Financial Reporting, the
Company identified a material weakness in the Company’s internal control over
financial reporting and has described a number of planned changes to its
internal control over financial reporting during 2005 designed to remediate
this
weakness.
(d) REPORT
OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM.
Board
of
Directors and Shareholders
Carrizo
Oil & Gas, Inc.
Houston,
Texas
We
have
audited management’s assessment, included in the accompanying Management’s
Annual Report on Internal Control Over Financial Reporting (Restated) appearing
under Item 9A, that Carrizo Oil & Gas, Inc. did not maintain effective
internal control over financial reporting as of December 31, 2004, because
of
the effect of the material weakness identified in management’s assessment, based
on criteria established in Internal Control--Integrated Framework issued
by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion
on
management’s assessment and an opinion on the effectiveness of the Company’s
internal control over financial reporting 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 effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control
over
financial reporting, evaluating management’s assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing
such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with accounting principles generally accepted in the United States of America.
A
company’s internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions
of the
assets of the company; (2) provide reasonable assurance that transactions
are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles in the United
States of
America, and that receipts and expenditures of the company are being made
only
in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection
of
unauthorized acquisition, use, or disposition of the company’s assets that could
have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting
may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may
become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
A
material weakness is a control deficiency, or combination of control
deficiencies, that results in more than a remote likelihood that a material
misstatement of the annual or interim financial statements will not be
prevented
or detected. In our report dated May 2, 2005, we expressed an unqualified
opinion on management’s assessment that the Company did not maintain effective
internal control over financial reporting and a qualified opinion on the
effectiveness of internal control over financial reporting. As previously
reported, a material weakness was identified and included in management’s
assessment of internal control over financial reporting. Management identified,
at that time, the following internal control deficiencies that constitute
a
material weakness:
· |
The
accounting system is a manually intensive system, requiring the
extensive
use of spreadsheets to accumulate data and prepare the underlying
support
for reconciliations, account analysis and routine journal entries,
all of
which increases the review time and chance for
error.
|
· |
The
current vacancy on the accounting staff for a financial reporting
director, partially remedied by reliance upon independent financial
reporting consultants for review of critical accounting areas and
disclosures and material non-standard
transactions.
|
As
described in the following paragraph, the Company subsequently identified
an
error in its 2004 annual financial statements and 2004 interim financial
statements, which caused such financial statements to be restated in April
2006.
Management subsequently revised its assessment due to the identification
of
additional material weaknesses, described in the following paragraph, which
resulted in the April 2006 financial statement restatements for 2004.
Accordingly, our opinion on the effectiveness of the Company’s internal control
over financial reporting as of December 31, 2004 expressed herein is different
from that expressed in our initial report dated May 2, 2005.
Additional
material weaknesses have been identified and included in management’s assessment
regarding the fact that management did not design and maintain adequate
controls
over the accounting for derivative instruments in accordance with Statement
of
Financial Accounting Standards No. 133, “Accounting
for Derivative Instruments and Hedge Activities.”
Management concluded that
derivatives
entered into during 2004 lacked sufficient documentation to be accounted
for as
cash flow hedges. Furthermore, these hedges were not properly fair valued
during
these periods due to the failure to use the appropriate market index. These
material weaknesses have caused the restatement of the consolidated financial
statements for the year ended December 31, 2004 and for the three, six
and nine
month periods included in the quarterly reports on Form 10-Q for the periods
ended March 31, June 30 and September 30, 2004. These material weaknesses
were
considered in determining the nature, timing, and extent of audit tests
applied
in our audit of the consolidated financial statements as of and for the
year
ended December 31, 2004 (as restated) and this report does not affect our
report
on such restated financial statements.
In
our
opinion, management’s revised assessment that Carrizo Oil & Gas, Inc. did
not maintain effective internal control over financial reporting as of
December
31, 2004, is fairly stated, in all material respects, based on the criteria
established in Internal
Control - Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway Commission.
Also in
our opinion, because of the effect of the material weakness described above
on
the achievement of the objectives of the control criteria, Carrizo Oil
&
Gas, Inc. has not maintained effective internal control over financial
reporting
as of December 31, 2004, based on the criteria established in Internal
Control - Integrated Framework
issued
by the Committee of Sponsoring Organizations of the Treadway
Commission.
We
have
also audited, in accordance with the Standards of the Public Company Accounting
Oversight Board (United States), the Consolidated Balance Sheet and the
related
Consolidated Statements of Income, Cash Flows, and Stockholders’ Equity of
Carrizo Oil & Gas, Inc. as of and for the year ended December 31, 2004. Our
report dated March 15, 2005 (April 10, 2006 as to the effects of the restatement
discussed in Note 3) expressed an unqualified opinion on those financial
statements and included an explanatory paragraph relating to the restatement
described in Note 3 to the financial statements.
We
do not
express an opinion or any level of assurance on management’s statement referring
to the effectiveness of the process instituted to remediate the material
weaknesses.
/s/
Pannell Kerr Forster of Texas, P.C.
Houston,
Texas
Described
in Management’s Report on Internal Control over Financial Reporting (Restated)
May 2, 2005 (April 10, 2006 as to the effects of the additional material
weaknesses)
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.
(A)(3)
EXHIBITS
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). |
EXHIBIT
NUMBER
|
|
DESCRIPTION
|
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). |
EXHIBIT
NUMBER
|
|
DESCRIPTION
|
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). |
EXHIBIT
NUMBER
|
|
DESCRIPTION
|
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). |
EXHIBIT
NUMBER
|
|
DESCRIPTION
|
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. |
|
|
|
__________
*
Previously filed.
**
Filed
herewith.
+
Compensatory plan, contract or arrangement.
CARRIZO
OIL & GAS, INC.
INDEX
TO CONSOLIDATED FINANCIAL STATEMENTS
|
PAGE
|
|
|
Carrizo
Oil & Gas, Inc. —
|
F-2
|
|
F-4
|
|
F-5
|
|
F-6
|
|
F-8
|
|
F-9
|
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 (restated) and the related consolidated statements
of operations, shareholders’ equity and cash flows for the year ended December
31, 2004 (restated). 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 (restated), and the consolidated results of its
operations and its cash flows for the year then ended (restated), in conformity
with U.S. generally accepted accounting principles.
As
referred to in Note 3, management of the Company determined that derivatives
entered into during 2004 lacked sufficient documentation to be accounted
for as
cash flow hedges. As a result, the Company has restated its consolidated
financial statements as of and for the year ended December 31,
2004.
/s/PANNELL
KERR FORSTER OF TEXAS, P.C.
Houston,
Texas
March
15,
2005
(Except
for Note 3 for which the date
is
April
10, 2006)
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.
/s/Ernst
& Young LLP
Houston,
Texas
March
25,
2004
CARRIZO
OIL & GAS, INC.
|
|
As
of December 31,
|
|
ASSETS
|
|
2003
|
|
2004
|
|
|
|
|
|
(Restated)
|
|
|
|
(In
thousands)
|
|
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
|
|
|
1,924
|
|
|
|
|
|
|
|
|
|
Total
current assets
|
|
|
14,325
|
|
|
21,944
|
|
|
|
|
|
|
|
|
|
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
|
|
$
|
234,345
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT
LIABILITIES:
|
|
|
|
|
|
|
|
Accounts
payable, trade
|
|
$
|
19,515
|
|
$
|
21,359
|
|
Accrued
liabilities
|
|
|
1,057
|
|
|
7,624
|
|
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
|
|
|
30,881
|
|
|
|
|
|
|
|
|
|
LONG-TERM
DEBT
|
|
|
34,113
|
|
|
62,884
|
|
ASSET
RETIREMENT OBLIGATION
|
|
|
883
|
|
|
1,407
|
|
DEFERRED
INCOME TAXES
|
|
|
12,479
|
|
|
18,113
|
|
COMMITMENTS
AND CONTINGENCIES (Note 11)
|
|
|
|
|
|
|
|
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
10)
|
|
|
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
|
|
|
20,993
|
|
Accumulated
other comprehensive income (loss)
|
|
|
(186
|
)
|
|
-
|
|
Total
shareholders' equity
|
|
|
76,072
|
|
|
121,060
|
|
|
|
$
|
156,803
|
|
$
|
234,345
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CARRIZO
OIL & GAS, INC.
CONSOLIDATED
STATEMENTS
OF OPERATIONS
|
|
For
the Year Ended December 31,
|
|
|
|
2002
|
|
2003
|
|
2004
|
|
|
|
|
|
|
|
(Restated)
|
|
|
|
(In
thousands except for per share amounts)
|
|
|
|
|
|
|
|
|
|
OIL
AND NATURAL GAS REVENUES
|
|
$
|
26,802
|
|
$
|
38,508
|
|
$
|
52,397
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
20,263
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER
INCOME AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
loss on derivatives, net
|
|
|
-
|
|
|
-
|
|
|
(625
|
)
|
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
|
|
|
18,123
|
|
INCOME
TAXES (Note 7)
|
|
|
2,809
|
|
|
5,063
|
|
|
7,009
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME
BEFORE CUMULATIVE EFFECT OF
|
|
|
|
|
|
|
|
|
|
|
CHANGE
IN ACCOUNTING PRINCIPLE
|
|
|
4,790
|
|
|
8,040
|
|
|
11,114
|
|
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
|
|
|
10,764
|
|
CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE,
|
|
|
|
|
|
|
|
|
|
|
NET
OF INCOME TAXES
|
|
|
-
|
|
|
(128
|
)
|
|
-
|
|
NET
INCOME AVAILABLE TO COMMON SHAREHOLDERS
|
|
$
|
4,202
|
|
$
|
7,171
|
|
$
|
10,764
|
|
|
|
|
|
|
|
|
|
|
|
|
BASIC
EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
|
|
|
|
|
|
|
|
|
|
|
EFFECT
OF CHANGE IN ACCOUNTING PRINCIPLE
|
|
$
|
0.30
|
|
$
|
0.51
|
|
$
|
0.54
|
|
CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING
|
|
|
|
|
|
|
|
|
|
|
PRINCIPLE,
NET OF INCOME TAXES
|
|
|
-
|
|
|
(0.01
|
)
|
|
-
|
|
BASIC
EARNINGS PER COMMON SHARE
|
|
$
|
0.30
|
|
$
|
0.50
|
|
$
|
0.54
|
|
DILUTED
EARNINGS PER COMMON SHARE BEFORE CUMULATIVE
|
|
|
|
|
|
|
|
|
|
|
EFFECT
OF CHANGE IN ACCOUNTING PRINCIPLE
|
|
$
|
0.26
|
|
$
|
0.44
|
|
$
|
0.49
|
|
CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING
|
|
|
|
|
|
|
|
|
|
|
PRINCIPLE,
NET OF INCOME TAXES
|
|
|
-
|
|
|
(0.01
|
)
|
|
-
|
|
DILUTED
EARNINGS PER COMMON SHARE
|
|
$
|
0.26
|
|
$
|
0.43
|
|
$
|
0.49
|
|
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.
CARRIZO
OIL & GAS, INC.
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS’
EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
Warrants
|
|
Common
Stock
|
|
|
|
Number
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
|
(Dollars
in thousands)
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivative
financial 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 (Restated)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Net
change in fair value of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivative
financial instruments (Restated)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income (Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 (Restated)
|
|
|
334,210
|
|
$
|
80
|
|
|
22,161,457
|
|
$
|
221
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivative
financial 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 (Restated)
|
|
|
-
|
|
$
|
11,114
|
|
|
11,114
|
|
|
-
|
|
|
11,114
|
|
Net
change in fair value of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
derivative
financial instruments
|
|
|
-
|
|
|
186
|
|
|
-
|
|
|
186
|
|
|
186
|
|
(Restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income (Restated)
|
|
|
|
|
$
|
11,300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 (Restated)
|
|
$
|
99,766
|
|
|
|
|
$
|
20,993
|
|
|
-
|
|
$
|
121,060
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
CARRIZO
OIL & GAS, INC.
CONSOLIDATED
STATEMENTS
OF CASH
FLOWS
|
|
For
the Year Ended December 31,
|
|
|
|
2002
|
|
2003
|
|
2004
|
|
|
|
|
|
|
|
(Restated)
|
|
|
|
(In
thousands)
|
|
CASH
FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
Income
before cumulative effect of change
|
|
|
|
|
|
|
|
in
accounting principle
|
|
$
|
4,790
|
|
$
|
8,040
|
|
$
|
11,114
|
|
Adjustments
to reconcile net income to net
|
|
|
|
|
|
|
|
|
|
|
cash
provided by operating activities -
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
10,574
|
|
|
11,868
|
|
|
15,464
|
|
Fair
value (gain) loss on derivative financial instruments
|
|
|
-
|
|
|
-
|
|
|
(400
|
)
|
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
|
|
|
6,818
|
|
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.
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.
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.
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.
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
|
|
$
|
10,764
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
$
|
10,877
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
available to common shareholders
|
|
|
|
|
|
|
|
|
|
|
before
cumulative effect of change in accounting
|
|
|
|
|
|
|
|
|
|
|
principle
per common share, as reported:
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.30
|
|
$
|
0.51
|
|
$
|
0.54
|
|
Diluted
|
|
|
0.26
|
|
|
0.44
|
|
|
0.49
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
$
|
0.54
|
|
Diluted
|
|
|
0.21
|
|
|
0.40
|
|
|
0.50
|
|
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 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 12).
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
The
Company uses derivatives to manage the price risk underlying its oil and
gas
production.
Upon
entering into a derivative contract, the Company must either designate the
derivative instrument as a hedge of the variability of cash flow to be received
(cash flow hedge) or the derivative must be accounted for as a non-designated
derivative. The Company 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 designed cash flow hedges to forecasted transactions.
The
Company also assesses whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in cash flows of
hedged
transactions. The cash flow hedges are marked-to-market each reporting period
and are recorded as either an asset or as a liability on the balance sheet
with
the corresponding amount recorded as other comprehensive income, net of tax,
within equity. 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 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. However, in
connection with the preparation of the Company’s financial statements for the
year ended December 31, 2005, the Company determined that it had not timely
designated its derivative instruments as cash flow hedges and lacked certain
documentation for the derivatives entered into during 2004 to qualify for
cash
flow hedge accounting treatment. Alternatively, the Company must account
for its
non-designated derivative activities by marking the instruments to market
and
record the unrealized gains and/or loss to earnings. As a result, the Company
is
restating in this Form 10-K/A the consolidated financial statements for 2004
and
the quarterly financial data for all periods in 2004. See Note 3 of the notes
to
the consolidated financial statements for further discussion of this financial
restatement.
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 14 with respect to the Company’s
positions with an affiliate of Enron Corp.
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:
|
|
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
|
|
$
|
10,764
|
|
|
14,158,438
|
|
|
14,311,820
|
|
|
19,958,452
|
|
$
|
0.30
|
|
$
|
0.51
|
|
$
|
0.54
|
|
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
|
|
$
|
10,764
|
|
|
16,148,443
|
|
|
16,744,296
|
|
|
21,818,065
|
|
$
|
0.26
|
|
$
|
0.44
|
|
$
|
0.49
|
|
|
|
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
|
|
|
|
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
|
|
$
|
10,764
|
|
|
14,158,438
|
|
|
14,311,820
|
|
|
19,958,452
|
|
$
|
0.30
|
|
$
|
0.50
|
|
$
|
0.54
|
|
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
|
|
$
|
10,764
|
|
|
16,148,443
|
|
|
16,744,296
|
|
|
21,818,065
|
|
$
|
0.26
|
|
$
|
0.43
|
|
$
|
0.49
|
|
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:
|
|
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.
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. FINANCIAL
RESTATEMENT
In
connection with the preparation of the Company’s consolidated financial
statements for the year ended December 31, 2005, the Company reviewed its
accounting policy used to account for its derivatives on interest rate swaps
on
the Second Lien Credit Facility and for oil and natural gas prices on its
proved
producing properties (“Derivatives”) and determined that these the derivatives
entered into in 2004 had not been timely designated and lacked sufficient
documentation to be accounted for as cash flow hedges and should have been
accounted for as non-designated derivatives instead of cash flow hedges in
accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133,
“Accounting for Derivative Instruments and Hedging Activities.” Accordingly, as
a result of the changes in accounting for the Company’s derivatives for interest
rate swaps and the oil and natural gas hedges the Company has restated its
consolidated financial statements for the year ended December 31, 2004, as
presented in this Form 10-K/A. All such derivatives in this restatement,
including oil and gas derivatives and interest rate swaps, are now classified
as
non-designated derivatives and are marked-to-market, with realized and
unrealized gains and losses being reflected as “mark-to-market gains (losses) on
derivatives, net” within the other income and expense section of the Statement
of Operations. In addition to the financial statements for the year ended
December 31, 2004, these changes in accounting affect the four quarterly
periods of 2004. Restatements of unaudited quarterly statements of operations
are also presented in the table below.
Under
cash flow hedge accounting, the after-tax change in the fair value of the
open
derivative positions (“fair value change”) is reported as Other Comprehensive
Income in the equity section of the balance sheet. Alternatively, if the
derivative does not qualify as a cash flow hedge, mark-to-market accounting
requires that the fair value change be reported in earnings. For the Company’s
cash flow commodity hedges, the Company had accounted for the realized gains
and
losses on these hedging activities in earnings within oil and natural gas
revenues when the forecasted transaction occurred. The Company’s derivative
instruments had previously been accounted for as cash flow hedges.
In
the
process of restating its financials to account for its derivatives on a
mark-to-market basis, the Company discovered certain computational errors
in the
fair value of the Company’s derivatives that was previously reported in Other
Comprehensive Income. These errors resulted from the information the Company
had
relied upon to establish oil and gas prices in connection with determining
the
fair value of the derivatives. For all the periods covered by the Company’s
consolidated financial statements, the Company used a third-party website
source
to obtain oil and gas market prices and to calculate the fair value of the
derivatives. However, the Company determined in the course of its evaluation
that the information from the third party provider was not entirely reliable
and
that Houston Ship Channel market prices should have been used in the fair
value
computation in place of New York Mercantile (“NYMEX”) index prices.
Nevertheless, in marking these derivatives to market, the gains and losses
reflected in the other income and expense have been based upon corrected
fair
valuations and were not based upon the information from the third party
provider.
A
comparison of the previously reported and restated amounts from the Company’s
financial statements follows:
|
|
For
the Year Ended December 31,
2004
|
|
|
|
As
Reported
|
|
As
Restated
|
|
Statement
of Operations:
|
|
|
|
Oil
and natural gas revenues
|
|
$
|
51,374
|
|
$
|
52,397
|
|
Operating
income
|
|
|
19,240
|
|
|
20,263
|
|
Mark-to-market
loss on derivatives, net
|
|
|
-
|
|
|
(625
|
)
|
Income
before income taxes
|
|
|
17,725
|
|
|
18,123
|
|
Income
tax expense
|
|
|
6,871
|
|
|
7,009
|
|
Net
income
|
|
$
|
10,854
|
|
$
|
11,114
|
|
Net
income available to common shareholders
|
|
|
10,504
|
|
|
10,764
|
|
Earnings
per common share:
|
|
|
|
|
|
|
|
Basic
earnings per common share
|
|
$
|
0.53
|
|
$
|
0.54
|
|
Diluted
earnings per common share
|
|
$
|
0.48
|
|
$
|
0.49
|
|
|
|
For
the Year Ended December 31,
2004
|
|
|
|
As
Reported
|
|
As
Restated
|
|
Cash
Flow Statement:
|
|
|
|
Net
income
|
|
$
|
10,854
|
|
$
|
11,114
|
|
Fair
value (gain) on derivative financial instrument
|
|
|
-
|
|
|
(400
|
)
|
Deferred
income taxes
|
|
|
6,678
|
|
|
6,818
|
|
Net
cash provided by operating activities
|
|
|
32,501
|
|
|
32,501
|
|
|
|
For
the Year Ended December 31,
2004
|
|
|
|
As
Reported
|
|
As
Restated
|
|
Statement
of Shareholders’ Equity:
|
|
|
|
Net
income
|
|
$
|
10,854
|
|
$
|
11,114
|
|
Accumulated
other comprehensive income
|
|
|
59
|
|
|
-
|
|
Comprehensive
income
|
|
|
11,099
|
|
|
11,300
|
|
|
|
As
of December 31, 2004
|
|
|
|
As
Reported
|
|
As
Restated
|
|
Balance
Sheet:
|
|
|
|
Other
current assets
|
|
$
|
1,614
|
|
$
|
1,924
|
|
Total
current assets
|
|
|
21,634
|
|
|
21,944
|
|
Other
Assets |
|
|
57 |
|
|
57 |
|
Total
Assets
|
|
|
234,035
|
|
|
234,345
|
|
Accrued
liabilities
|
|
|
7,516
|
|
|
7,624
|
|
Total
current liabilities
|
|
|
30,772
|
|
|
30,881
|
|
Deferred
income taxes
|
|
|
18,113
|
|
|
18,113
|
|
Retained
earnings
|
|
|
20,733
|
|
|
20,993
|
|
Accumulated
other comprehensive income
|
|
|
59
|
|
|
-
|
|
Total
Liabilities and Shareholders’ Equity
|
|
|
234,035
|
|
|
234,345
|
|
Quarterly
Statements of Operations Data (Restated) (Unaudited)
|
|
For
the Quarters Ended
|
|
|
|
March
31, 2004
|
|
June
30, 2004
|
|
September
30, 2004
|
|
December
31, 2004
|
|
|
|
As
Reported
|
|
As
Restated
|
|
As
Reported
|
|
As
Restated
|
|
As
Reported
|
|
As
Restated
|
|
As
Reported
|
|
As
Restated
|
|
Statement
of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and Natural Gas Revenues
|
|
$
|
10,873
|
|
$
|
10,861
|
|
$
|
11,959
|
|
$
|
11,935
|
|
$
|
12,274
|
|
$
|
13,041
|
|
$
|
16,268
|
|
$
|
16,560
|
|
Operating
Income
|
|
|
3,801
|
|
|
3,789
|
|
|
3,907
|
|
|
3,883
|
|
|
5,274
|
|
|
6,041
|
|
|
6,258
|
|
|
6,550
|
|
Mark-to-market
gain (loss) on derivatives, net
|
|
|
-
|
|
|
(972
|
)
|
|
-
|
|
|
460
|
|
|
-
|
|
|
(1,296
|
)
|
|
-
|
|
|
1,183
|
|
Income
Before Income Taxes
|
|
|
3,536
|
|
|
2,552
|
|
|
3,526
|
|
|
3,962
|
|
|
5,469
|
|
|
4,940
|
|
|
5,194
|
|
|
6,669
|
|
Income
tax expense
|
|
|
1,353
|
|
|
1,008
|
|
|
1,388
|
|
|
1,539
|
|
|
2,079
|
|
|
1,893
|
|
|
2,051
|
|
|
2,569
|
|
Net
Income
|
|
|
2,183
|
|
|
1,544
|
|
|
2,138
|
|
|
2,423
|
|
|
3,390
|
|
|
3,047
|
|
|
3,143
|
|
|
4,100
|
|
Net
Income Available to Common Shareholders
|
|
|
1,985
|
|
|
1,346
|
|
|
1,986
|
|
|
2,271
|
|
|
3,390
|
|
|
3,047
|
|
|
3,143
|
|
|
4,100
|
|
Earnings
per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per common share
|
|
$
|
0.12
|
|
$
|
0.08
|
|
$
|
0.10
|
|
$
|
0.12
|
|
$
|
0.15
|
|
$
|
0.14
|
|
$
|
0.16
|
|
$
|
0.19
|
|
Diluted
earnings per common share
|
|
$
|
0.10
|
|
$
|
0.07
|
|
$
|
0.09
|
|
$
|
0.10
|
|
$
|
0.15
|
|
$
|
0.13
|
|
$
|
0.14
|
|
$
|
0.18
|
|
In
conjunction with the restatement of the quarterly information above, the
respective Form 10-Qs as previously filed for the quarterly periods ended
March
31, 2004, June 30, 2004, and September 30, 2004 should no longer be relied
upon.
4. 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.
5. 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 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/A.
6. 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.
7. 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
|
|
$
|
6,343
|
|
Preferred
dividend on Pinnacle
|
|
|
-
|
|
|
108
|
|
|
405
|
|
Increase
in valuation allowance
|
|
|
|
|
|
|
|
|
|
|
for
equity in loss of Pinnacle
|
|
|
-
|
|
|
189
|
|
|
70
|
|
State
taxes
|
|
|
149
|
|
|
180
|
|
|
191
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
tax provision
|
|
$
|
2,809
|
|
$
|
5,063
|
|
$
|
7,009
|
|
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
|
|
|
14,935
|
|
Capitalized
interest
|
|
|
4,683
|
|
|
5,697
|
|
Hedge
valuation
|
|
|
-
|
|
|
140
|
|
|
|
|
14,227
|
|
|
20,772
|
|
|
|
|
|
|
|
|
|
Net
deferred income tax liability
|
|
$
|
12,379
|
|
$
|
18,253
|
|
The
net
deferred income tax liability is classified as follows:
|
|
As
of December 31,
|
|
|
|
2003
|
|
2004
|
|
|
|
(In
thousands)
|
|
|
|
Other
current assets
|
|
$
|
100
|
|
$
|
-
|
|
Accrued
liabilities
|
|
|
-
|
|
|
140
|
|
Deferred
income tax liability
|
|
|
12,479
|
|
|
18,113
|
|
|
|
|
|
|
|
|
|
Deferred
income tax liability, net
|
|
$
|
12,379
|
|
$
|
18,253
|
|
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.
8. 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.
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 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 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.
9. 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.
10. 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, 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.
11. 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:
Year
ended
|
|
|
|
December
31,
|
|
Amount
|
|
|
|
(In
thousands)
|
|
|
|
|
|
2005
|
|
$
|
222
|
|
2006
|
|
|
477
|
|
2007
|
|
|
477
|
|
2008
|
|
|
477
|
|
2009
|
|
|
477
|
|
Remainder
|
|
|
1,056
|
|
|
|
|
|
|
|
|
$
|
3,186
|
|
12. 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
|
|
|
|
|
|
|
|
|
|
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.
13. 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 entities were
performed at prevailing market rates.
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
5, 8 and 10 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.
14. 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 financial instruments.
As
of
December 31, 2003 and 2004, the unrealized gain/(loss), net of tax, on oil
and
gas derivative instruments related to the mark-
to-market
valuation was $0.2 million and $0.4 million, respectively, which are presented
as mark-to-market gain(loss) on derivatives, net in the other income and
expense
section of our restated Statement of Operations.
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 other income and expense.
At
December 31, 2003 and 2004 the Company had the following outstanding derivative
positions:
As
of 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
|
|
As
of 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,
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.
15. 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.
16.
|
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:
|
|
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
|
|
__________
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
|
|
|
|
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:
|
|
For
the 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:
|
|
For
The Year Ended December 31,
|
|
|
|
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, extensions
and discoveries, purchases of minerals in place and the changes due to revisions
in standardized variables are reported on a pretax discounted basis, while
the
accretion of discount is presented on an after-tax basis.
17.
|
SUPPLEMENTAL
QUARTERLY FINANCIAL DATA
(UNAUDITED)
|
2004
(Restated - Note 3)
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
|
|
(In
thousands except per share amounts)
|
|
Revenues
|
|
$
|
10,861
|
|
$
|
11,935
|
|
$
|
13,041
|
|
$
|
16,560
|
|
Costs
and expenses, net
|
|
|
9,317
|
|
|
9,512
|
|
|
9,994
|
|
|
12,460
|
|
Net
income
|
|
|
1,544
|
|
|
2,423
|
|
|
3,047
|
|
|
4,100
|
|
Dividends
and accretion
|
|
|
198
|
|
|
152
|
|
|
-
|
|
|
-
|
|
Net
income available to common
|
|
|
|
|
|
|
|
|
|
|
|
|
|
shareholders
|
|
$
|
1,346
|
|
$
|
2,271
|
|
$
|
3,047
|
|
$
|
4,100
|
|
Basic
net income per share (1)
|
|
$
|
0.08
|
|
$
|
0.12
|
|
$
|
0.14
|
|
$
|
0.19
|
|
Diluted
net income per share (1)
|
|
$
|
0.07
|
|
$
|
0.10
|
|
$
|
0.13
|
|
$
|
0.18
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
of
change in accounting principle
|
|
$
|
2,789
|
|
$
|
1,779
|
|
$
|
1,892
|
|
$
|
838
|
|
Cumulative
effect of change 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.
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:
June 12, 2006
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). |
EXHIBIT
NUMBER
|
|
DESCRIPTION
|
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). |
EXHIBIT
NUMBER
|
|
DESCRIPTION
|
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). |
EXHIBIT
NUMBER
|
|
DESCRIPTION
|
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. |
|
|
|
__________
*
Previously filed.
**
Filed
herewith.
+
Compensatory plan, contract or arrangement.
EX-23.1
2
exh231.htm
EXHIBIT 23.1 - PKF
Exhibit 23.1 - PKF
Exhibit
23.1
Consent
of Independent Registered Public Accounting Firm
We
consent to the incorporation by reference in the Registration Statements on
Forms S-8 No. 333-35245, No. 333-55838 and No. 333-116528 pertaining to the
Incentive Plan of Carrizo Oil & Gas, Inc. of our report dated March 15, 2005
(except for Note 3 for which the date is April 10, 2006), with respect to the
consolidated financial statements as of and for the year ended December 31,
2004
and our report dated May 2, 2005 (April 10, 2006 as to the effects of the
additional material weaknesses described in Management’s Report on Internal
Control over Financial Reporting (Restated)) with respect to management’s
assessment of the effectiveness of internal controls over financial reporting,
of
Carrizo Oil & Gas, Inc. included in the Annual Report on Form 10-K/A for the
year ended December 31, 2004.
/s/
Pannell Kerr Forster of Texas, P.C.
Houston,
Texas
June
7,
2006
EX-23.2
3
exh232ernstandyoung.htm
EXHIBIT 23.2 - ERNST & YOUNG CONSENT
Exhibit 23.2 - Ernst & Young Consent
EXHIBIT
23.2
CONSENT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The
Board
of Directors and Stockholders
Carrizo
Oil & Gas, Inc.
We
consent to the incorporation by reference in the Registration Statements (Forms
S-8 Nos. 333-35245, 333-55838 and 333-116528) pertaining to the Incentive Plan
of Carrizo Oil & Gas, Inc. of our report dated March 25, 2004, with respect
to the consolidated financial statements of Carrizo Oil & Gas, Inc. included
in the Annual Report (Form 10-K/A) for the year ended December 31,
2004.
/s/Ernst
& Young LLP
Houston,
Texas
June
7,
2006
EX-23.3
4
exh233ryderscott.htm
EXHIBIT 23.3 - RYDER SCOTT CONSENT
Exhibit 23.3 - Ryder Scott Consent
Exhibit
23.3
CONSENT
OF INDEPENDENT PETROLEUM ENGINEERS
We
hereby consent to the incorporation by reference in the Registration Statements
on Form S-8 (Registration Nos. 333-35245, 333-55838 and 333-116528); (the
“Registration Statements”) of Carrizo Oil & Gas, Inc., a Texas corporation
(the “Company”), relating to the 1997 Incentive Plan of the Company of
information contained in our reserve report that is summarized as of December
31, 2004 in our summary letter dated March 29, 2005, relating to the oil and
gas
reserves and revenue, as of December 31, 2004, of certain interests of the
Company.
We
hereby consent to all references to such reports, letters and/or to this firm
in
each of the Registration Statement and the Prospectus to which the Registration
Statement relates, and further consent to our being named as an expert in each
of the Registration Statement and the Prospectus to which the Registration
Statement relates.
/s/RYDER
SCOTT COMPANY, L.P.
Houston,
Texas
May
29,
2006
EX-23.4
5
exh234fairchildwells.htm
EXHIBIT 23.4 - FAIRCHILD AND WELLS
Exhibit 23.4 - Fairchild and Wells
Exhibit
23.4
CONSENT
OF INDEPENDENT PETROLEUM ENGINEERS
We
hereby
consent to the incorporation by reference in the Registration Statement on
Form
S-8 (Registration No. 333-35245 and 333-55838; the “Registration Statement”) of
Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), relating to
the 1997 Incentive Plan of the Company of information contained in our reserve
report that is summarized as in our summary letter dated February 7, 2005,
relating to the oil and gas reserves and revenue, as of December 31, 2004,
of
certain interests of the Company.
We
hereby
consent to all references to such reports, letters and/or to this firm in
each
of the Registration Statement and the Prospectus to which the Registration
Statement relates, and further consent to our being named as an expert in
each
of the Registration Statement and the Prospectus to which the Registration
Statement relates.
/s/
Fairchild and Wells, Inc.
Fairchild
and Wells, Inc.
Houston,
Texas
May
26,
2006
EX-23.5
6
exhibit235degolyermac.htm
EXHIBIT 23.5 - DEGOLYER AND MACNAUGHTON CONSENT
Exhibit 23.5 - DeGolyer and MacNaughton Consent
Exhibit
23.5
DeGolyer
and MacNaughton
5001
Spring Valley Road
Suite
800
East
Dallas,
Texas 75244
May
30, 2006
Carrizo
Oil & Gas, Inc.
1000
Louisiana Street
Suite
1500
Houston,
Texas 77002
Ladies
and Gentlemen:
We
consent to the use of the name DeGolyer and MacNaughton, to references
to
DeGolyer and MacNaughton, to the inclusion by reference of our “Appraisal Report
as of December 31, 2004 on Certain Properties owned by Carrizo Oil & Gas,
Inc.” (our Report), in the Registration Statements on Form S-8 (Registration
Nos. 333-35245, 333-55838, and 333-116528) (the Registration Statements) of
Carrizo Oil & Gas, Inc., a Texas corporation (the Company), relating to the
1997 Incentive Plan of the Company, and in the sections “Oil and Gas Reserves”
and “Oil and Natural Gas Reserve Estimates” in the Company’s Annual Report on
Form 10-K/A for the year ended December 31, 2004, provided, however, that
we
were necessarily unable to verify the estimates from our Report, since these
estimates were combined with those of other firms for other properties and
reported in total.
We
further consent to the incorporation of the text of our Report in the Company’s
Annual Report on Form 10-K/A for the year ended December 31, 2004 as exhibit
99.3.
Very
truly yours,
/s/DeGOLYER
and MacNAUGHTON
DeGOLYER
and MacNAUGHTON
EX-31.1
7
exhibit311.htm
EXHIBIT 31.1 - CEO CERTIFICATION
Exhibit 31.1 - CEO Certification
Exhibit
31.1
CERTIFICATIONS
PRINCIPAL
EXECUTIVE OFFICER
I,
S.P.
Johnson, IV, certify that:
1. I
have
reviewed this Annual Report on Form 10-K/A of Carrizo Oil & Gas,
Inc.;
2. Based
on
my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made,
in
light of the circumstances under which such statements were made, not misleading
with respect to the period covered by this report;
3. Based
on
my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The
registrant’s other certifying officer(s) and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange
Act
Rules 13a-15(e) and 15d-15(e)) and
internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the registrant, including
its
consolidated subsidiaries, is made known to us by others within
those
entities, particularly during the period in which this report is
being
prepared;
|
|
(b)
|
Designed
such internal control over financial reporting, or caused such
internal
control over financial reporting to be designed under our supervision,
to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness
of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
(d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely
to
materially affect, the registrant’s internal control over financial
reporting; and
|
5. The
registrant’s other certifying officer(s) and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
|
(a)
|
All
significant deficiencies and material weaknesses in the design
or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
(b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
|
|
Date: June
12, 2006 |
By: |
/s/
S. P. JOHNSON IV |
|
S.P. Johnson IV |
|
President
and
Chief Executive Officer |
EX-31.2
8
exhibit312.htm
EXHIBIT 31.2 - CFO CERTIFICATION
Exhibit 31.2 - CFO Certification
Exhibit
31.2
CERTIFICATIONS
PRINCIPAL
FINANCIAL OFFICER
I,
Paul
F. Boling, certify that:
1. I
have
reviewed this Annual Report on Form 10-K/A of Carrizo Oil & Gas,
Inc.;
2. Based
on
my knowledge, this report does not contain any untrue statement of a material
fact or omit to state a material fact necessary to make the statements made,
in
light of the circumstances under which such statements were made, not misleading
with respect to the period covered by this report;
3. Based
on
my knowledge, the financial statements, and other financial information included
in this report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the
periods presented in this report;
4. The
registrant’s other certifying officer(s) and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange
Act
Rules 13a-15(e) and 15d-15(e)) and
internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
(a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the registrant, including
its
consolidated subsidiaries, is made known to us by others within
those
entities, particularly during the period in which this report is
being
prepared;
|
|
(b)
|
Designed
such internal control over financial reporting, or caused such
internal
control over financial reporting to be designed under our supervision,
to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
(c)
|
Evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness
of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
(d)
|
Disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely
to
materially affect, the registrant’s internal control over financial
reporting; and
|
5. The
registrant’s other certifying officer(s) and I have disclosed, based on our most
recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of
directors (or persons performing the equivalent functions):
|
(a)
|
All
significant deficiencies and material weaknesses in the design
or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
(b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
|
|
Date: June
12, 2006 |
By: |
/s/PAUL
F.
BOLING |
|
Paul F. Boling |
|
Chief
Financial Officer |
EX-32.1
9
exhibit321.htm
EXHIBIT 32.1 - CEO CERTIFICATION
Exhibit 32.1 - CEO Certification
Exhibit
32.1
Certification
Pursuant to
Section
906 of the Sarbanes-Oxley Act of 2002
(Subsections
(a) and (b) of Section 1350, Chapter 63 of Title 18, United States
Code)
Pursuant
to section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of
Section 1350, Chapter 63 of Title 18, United States Code), I, S.P. Johnson,
IV,
President and Chief Executive Officer of Carrizo Oil & Gas, Inc., a Texas
corporation (the “Company”), hereby certify, to my knowledge, that:
|
(1)
|
the
Company’s Annual Report on Form 10-K/A for the year ended December 31,
2004 (the “Report”) fully complies with the requirements of Section 13(a)
or 15(d) of the Securities Exchange Act of 1934;
and
|
|
(2)
|
information
contained in the Report fairly presents, in all material respects,
the
financial condition and results of operations of the
Company.
|
Dated: June
12, 2006
|
/s/S.P.
Johnson, IV
Name:
S.P. Johnson, IV
President
and Chief Executive Officer
|
The
foregoing certification is being furnished solely pursuant to Section 906 of
the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter
63
of Title 18, United States Code) and is not being filed as part of the Report
or
as a separate disclosure document.
A
signed
original of this written statement required by Section 906 has been provided
to
Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc.
and furnished to the Securities and Exchange Commission or its staff upon
request.
EX-32.2
10
exhibit322.htm
EXHIBIT 32.2- CFO CERTIFICATION
Exhibit 32.2- CFO Certification
Exhibit
32.2
Certification
Pursuant to
Section
906 of the Sarbanes-Oxley Act of 2002
(Subsections
(a) and (b) of Section 1350, Chapter 63 of Title 18, United States
Code)
Pursuant
to section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of
Section 1350, Chapter 63 of Title 18, United States Code), I, Paul Boling,
Vice
President and Chief Financial Officer of Carrizo Oil & Gas, Inc., a Texas
corporation (the “Company”), hereby certify, to my knowledge, that:
|
(1)
|
the
Company’s Annual Report on Form 10-K/A for the year ended December 31,
2004 (the “Report”) fully complies with the requirements of Section 13(a)
or 15(d) of the Securities Exchange Act of 1934;
and
|
|
(2)
|
information
contained in the Report fairly presents, in all material respects,
the
financial condition and results of operations of the
Company.
|
Dated: June
12, 2006
|
/s/Paul
F. Boling
Name:
Paul F. Boling
Vice
President and
Chief
Financial Officer
|
The
foregoing certification is being furnished solely pursuant to Section 906 of
the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter
63
of Title 18, United States Code) and is not being filed as part of the Report
or
as a separate disclosure document.
A
signed
original of this written statement required by Section 906 has been provided
to
Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc.
and furnished to the Securities and Exchange Commission or its staff upon
request.
GRAPHIC
11
carrizo_logo.jpg
begin 644 carrizo_logo.jpg
M_]C_X``02D9)1@`!`0$!+`$L``#_VP!#``8$!08%!`8&!08'!P8("A`*"@D)
M"A0.#PP0%Q08&!<4%A8:'24?&ALC'!86("P@(R8G*2HI&1\M,"TH,"4H*2C_
MVP!#`0<'!PH("A,*"A,H&A8:*"@H*"@H*"@H*"@H*"@H*"@H*"@H*"@H*"@H
M*"@H*"@H*"@H*"@H*"@H*"@H*"@H*"C_P@`1"`!N`8$#`2(``A$!`Q$!_\0`
M'``!``(#`0$!``````````````4&`P0'`@$(_\0`&@$!`0`#`0$`````````
M``````$"`P0%!O_:``P#`0`"$`,0```!ZH`````\U^;;$Y[#X>AUIQKW-O8G
M'1V)QT=B<='8G'=NX]7?/NSQP``````````````!3YNM-*IF'3]#G]V70QZL
MS9E,^.*\R>6ZX9-$A4T(5-"%NVC8LN`,_.`````````````/%+\^F?GE=DS?`(XD6IM@!7LY-`$(3:!G
M3Z`B]XS`(7`6%K[`-8V59LAZ!\U-S5EAWR%U96C/6MVZ]G6SQ#9,8HCV\$_1"B.2C)/G`>]?GDM,W4^H6V,2`-;924
M:E=NQ<_+Q*T;=)YN+H%-U+SEGJ1N.66W2W/W>D-`N^T-NL>?ZN
M6ML@QY!CQ;(`\XLXUMD`-;9!Y]#3^[8`:VR-;9````!&2:8\IKO>(/DXJ'(Z
MM>4X7/@]O.T_G:?SM/YVG\[3^=I_.T_BJKI6(Z^.OH#%&E[AV"L
M265,S+P%5L\],.:N'-Z]K89[6PSVMAGM;#/:V&>UL,]K89[6PRMF76)9[W<]ZM6MY[1O/:-Y[1O/:-Y[1O/
M:-XFZR<_\]VS75QZR.WPA7F6W5
ME,59"T/GW5=@K5$L^2VJ(B1N*^6];UO7#5@JI,)8&%P:U2"7W5=BYAL"X.<2
MXXWU;N49:G'-Y,.Y82H`3<:9/60KE(9X_P"-%K8%S5(GK(U889*G!.0$5@?I
MZQL)CRGZ="Q7T=,^C9<3EJ$+`Q;=[H[=)"["?%W6UB^5]>6Q916BFIF]_C1S&O+CJ"D700Z*-.:G
M$]'PY[$6>])"4+\.\C:A)FRO;B6U;7R-W\L\YWXAO!;D(L#0YZR5)%R'4LAU
MG3.K`O/6%AV@)JVH4^CB_"VXZM+VZ;IBJ!800UV[_BV+V:WIM$;[]T`:-J+\
M]KB/]]?<6+/AHM-D<90ZA`L/@L?F)4A:>UM[0MU.AK_7(?H.`1XMT6L87*O,
M9)BDK=ECDT4[$9!L(,!.O9ZW%JH90>$Y#B6M2U%%2$N9@%.7X_:(`PEQ,<":
M@.`]:7#J7$HZG$8ACW(`9RYBN&,N)1C./BKYI8&M\F7"?`@"#_`4<"P?I-ZR
M4=PD$LPS7L%WQ6-:5/:%G`@V:@HI+W1`[':ISSS5<\Q;/,6SS%LA.)(_2.)!
M;B]4G6X1M"K:DFJ_@S/557&S2]23-5U;O/6UV>MKLK:\"N_J2"@71J90F$Z?UDJ%C/1M
MYZ1O!4;'=CK48_\`'__$`#(1``$#`0,*!0,%``````````$``@,1!!(A!1,4
M%2(Q0$%AD3)14V.A(",P0E+1X?#_V@`(`0,!`3\!^F.&27!@JF9'M#M^"U,1
MXI`M4#U0M4#U0M4#U0G9*:T5,HX&"SR3NNQA6;)$<>U-B?A">_LV88>?+^T^
M9KS=QD/3`?"N$;[..X5/8;W"I[#>X5/8;W"ML@\&;#3TQ_/%!),:1BJL^1OU
M3E:39X!FXL>@3V/FVK4;K?+^5,X.;]S8C^2I\H.?L1;+>##RW0M.
MO[W5_P!U6LI6#Q$!#*C]XKPI%=ZDLC7>'!'.0%59+T*YT?@[S39RW
M"5"1IW%7QYH.!X,@.%"I+'S8B7,V9`F24P:[NL3R:MK]H43:"I'#&SQGDM$C
M6B1\#__$`"H1``(!`04(`04````````````!`A$#$R$Q0`02,D%14F&!%"`B
M,)&A_]H`"`$"`0$_`?IK0O$7A>>"\\%YX-_QH6Z#M*Y%.X2]'L]GL]D?SMT'
M:=#=D\6+#A%_11ZZ1VD%F*UAR8YQ69>09&<9<.FGL\7D??9,K&T\,YTE@Q6N
M[A:&_'J;R*IZ-JN9/9NT;E'":(SIPO\`9B^2,>U%G&BRTSL8/D?&@?&AH?_$
M`$(0``(!`@($"`L&!@(#``````$"`P`1!!(A,4%1$!,B(S-289(@,C108G%R
MD:&BT044-5.!P21"0X*QX3!@8_#Q_]H`"`$!``8_`O/=V(`WFM#&0^A7,PJ/
M:-ZZ7+ZA6B:9O435\N)/Z&O$Q7N:O$Q7N:O$Q7N:O$Q7N:O$Q7N:O$Q7N:O$
MQ7N:D1_O"*3I8W%`#4/,.>5PJ]M9<(G]S5>:1F]=6A0MV[*_CL3RORXZ_AL$
M#Z4AKFX$MV(:Z,=PUT?R5T?R5T?R5T?R5T?R5T?R5T?R4'Q-@[:;6M8>8--%
M,-:1^ML%9YG+&@J`LQV"N.^TG]48KBL,O$Q:@J:S7&8QN+7J[:M"@=AU1?XU
MS6$9OUK1]GR?'Z5^'2_'Z5^'2_'Z5^'2_'Z5^'2_'Z5^'2_'Z5^'2_'Z4$?!
MM$NUFOY@(+9Y.JM68Y8^H.#D#+'MCJJV;BTW+5D4L>RM*<6-[U?%3"63JC
MZ5Q>$7BDW[:SOS<>V2311CP'.2G7*PKC<3F5#K)UM02)0JC9X&5\4M_1!;_%
M9L-*L@&[P%^\S+'FU7K/AY`Z7M<>!Y5'05,5$6.R]O`:.3$HKKH(JPQ<7ZFU
M7!N#PA,1,L;$7L:62)LR-J/"T4>JP_:KR/,Y])Z\1CZVK1`GZZ:LDKH-RA1^UKQPJ#O.GP4P<1MF&9[;MU+-B6?/(+KEV"DE?)Q6D-
M9M8X2S&R@7)K$3+T<:DCL45BH=Q##AQ,G5C-JMCY#'#;6*XG[+XR9#XMQIJ-
M&-V50">$OB&RQ22YG/9>HU^S)));^->L/'-?.!I!V:>&4=0!:@BZB`<,F*Q<
MDW&2$D*&&DT4PZV3:Q_E%1P(;A!:_!)CR4
M89?UX>0T?ZK_`+K1AXI!Z!JTN&L=U[5RXG'JTUR,1&AW.AK-",+,/1-?Q&$M
MVU_+'[27'^:SQQP8A/\`Q&LL\;Q'WUGB8,N\>`N)L3$RY;[C28>.&TRID#W^
M-'$8V67BK616V]O",'&>7)I?U5*8(.9G3E'1I6LGYB$?OPN/S&"_O^U8A\2I
M(6P6QM428=B%$^4'LOPXF3=&;48YP3&J%CIJ2+"E@J6MIU:*3.;M;3P]DL_P
MOPS3VOD%[5QV*8L3NV#LI,/AL`5&KI-9]W"Z=86I6ECY<1TJ=M108>!@H-\H
MTDFA&_2L(QX%WB1CO*U;969(HP=
MX7AM(JL.T5:-54=@K,(H\VN^7ALP!&XUS<:+ZA:KM%&3O*^!=8HP=X7ARN`P
MW&N@B[HJXACO[(\#GHHY/:6]40]\5Y1#WQ6:-@R[P?,O.KRMC#719>.TJ]FNK,"K#?65B)4W/IKG\(8SOCKDXF1?7_\`*\M^=:\M'?6O
M+1WUHRPN9,PT-YJM(BL.T5H5D]DUS<_O6N3)$??7]/O5_3[U+QN0)?38T%70
M!_U#_\0`*A`!``$"!`4$`P$!`0```````1$`(3%!46$0<8&1H2#!T?!0L?$P
M8.'_V@`(`0$``3\A_-MSO%("I$-Y"3OA4H`ZI^D5H1H94Q-B]M0>&^_P:JJJ
MJJJBPP98,\:'!1!^!5BV:K%^CR*GD=UCD5O[F`G2JMEWULN^MEWULN^MEWULN^MEWU@+@&P?@%`J@,5J,/T+>N:P\#D95:
M+@!*T1(:NZZ;]*$,LA'8]JU6Y.5.[E3^ZI0^WT*Q)\J/XE7\2K^)5_$J_B
M5?Q*HT56`CN?@+21O/72F706#UUX#6X:'IK2X(+KC\#:@UU0&7+0HFH_PFAO
M4NTJX6YNK1K9S;I0P(,`(_"J27%(*ETT5G=\5,F1M]W&MLBB6H!W4CQC5GZW
MB>3WK1!MK;(K!-KIAYQJ+$*+9T/O6ICI3X=\U@+"'H81/&`[AICB8E5I9[16,<[3&,UB/)YKK+*]J?!7<=WTB)WZKN`\'Q0^\:0&5SUJ%;"[)
M#3G'$9S2,`*(M@IY;O/FI6.#N8C^CC<&%/-%O-!IOKCSD8-3$AS$'/(M6Y;E
M$,>"P2X5/NX'$4FH=>;.>06*`,,<1)(=GC$#(7VG]K5I(5^8<<NQGJ\`9(!*U(IH4UHY$U%IA`-P_%,(7)972>//!G*L9R[?NDDB<
MU?&-+Q1QE7DKS'CX5TL#>9BM((J_SS3F#W(=[E:M-WO$O%#(=Q5DZ-_%9.87
M`<\_%%$[,GT&8C1+!DU!2G"R"+-:G?*1^+3CA%EC+3U?UO3@\0#8'6Y9J[FW
M5S_P\;GW\G0T+YS=>?:G(\R+NOTXW>AZTD'FA4$!#,#]U*86L20X]:)"`,M6
M.-JXR?KMQL"<9,2Y>:;HRY9L:*F%$&9,W,\;L1++22D"S"P@B6>39J&(0V]=
M*:`,J,G3IZ>3H%SDTZ93I]&M!73@\G.M^)Q43.%F$?!K-AO`G?)TH@9R5ALY
ME$\(QQU_%38W,FIV1E]N?)Q4D6R"1J(Y7@']>A,RY):`0!DBC`7@`3B0"F8)
MI@E70B@@0;`F=>+1[Q"1I8HN*='#WB!6@@@L<21W@`3BX2<0D>`0`,7$M>@@
M##"*/>C$,<8I]O\`!\O9$UKI$]^C5J&B$)6!1:@4R["=1S4QDR#E2(I;7/UO
M3-PL$#R]'4;"4?A8]8:(5`&/+NLIFOD:"*;\.)^8[,\
MS.I'LOV5H5X(2LFL1_MC1CUYEO:K\CI9'>@$AZAQ::L0"1$C:/Q6U2]]]^\\\\\\\\\\\\\\YBZA.'=U\XT\_
M\XQ\]\WT\P\R`>1*<\_U\PW[L<"R\>X9]<\L-\>3
MD+4AR;H88HU$C5$CLW?-&E.;V_`,8P0!JCD)+G%/G=AR4UH$W1BX=SXU08!P
ML7/-I:E2.68F9S6Y#JIS,V4P6J!A4VLA3;=`)$YD>WNB7F4QX6,&=-!H,8M"
M8AL.Z%M+F.BF.ZQ+H6K('`V1I=O>*[3547E2&8WV%3(&JP6JD`+IT\','3P>#GX&PN%;/(^4&F!CV
M/H3.@N#O_$#0-HF_A\J6`$W7?5(!#%5G3+HB:_5`1>:I]#__Q``H$0`"`0($
M!00#`````````````1$0(3%!89$@0%%QT3"AL?"!P?'_V@`(`0(!`3\0X6F)
MC20>"9W#N'<%-Q+D4I+'V%QNWD8E-D]R9S[$Z]B=>Q.O83.9]=%S9EJ>2#*Q
M)?42':_P$J]SI'##I!%(I#K%&X0YMCNARR"]+[&5O]Z&,**J0Q50Z.F-%P-)
MJ&7VU^PU&P^!?4I^"6\"X/SY'V$/KDQ,NDW-86$9-9XY?H(6$E$]W_`AOEK^
MF1HL]/(FY/L1_"7!HGIRK4V9C(;>HD//D?_$`"H0`0`!`@4$`@,!``,!````
M``$1`"$Q05%A<1"!D:'!\"!0L=$P8.'Q_]H`"`$!``$_$/W8?!D`&ZV*4LD8
MDYQ#A:0P'#EWBQY:E@*Z.[PONA4YQBO"J/.*R,!$EYX
M>RT0#&"->XO]H21M0_SV;-FS9LS(_4`,`AE6+3JY?H`!+``
MB0GR_P#H>"C$CC(+X(YEWHJW0,#@/TN"T(RY6U"DG#$-W;N&BRK:=2>5Z-J/
M,V[%)`KJI[^E0-YN`:)%\H=*:P$B@X@>F71*,9BN7FZC(#%/A)'
5J8!M*.U7IC-C6)ZXF/&G$PP;].L>W)7!1.B)VZO"*$A70G%V+T#%3!
M\_GNFCO*+)8(EDWZ(XJZ$GD:;M3"28??'K&$D'
M.>PHB(&&=H$:DX94GEQFEF"Y!S0B^5Z:\U;,2/8
MF\R:!&U@L8`"I@$Q#,Z$%JJ!A*KWZ%::1@!BU,IM\H)749EJFD0\X>DFX`"$
MYX`>58!DQ"='1V?
MPFOD@7>"1$G&^E+%OTS$B,V&$Q-[EJ%0U:
M_P#%A*@D;0X.E25HDU@#X\W6,8!_9Z56@51"%.,;>](TD40Q2$3)N8/6#H(6
M\]@I>*4FL!)?&7:F&8DUIQBL\JC^+GFRE\SUW=G.')['\]33880=`+HHHB8!
M`),)D`3%F]V69;^"`+@2W(Q?X@ZSPS!M03[I/Y?KU6#!1N&%8=[/'@4``%\J
MNCB-%9%`"Y@`YES_`!MK""[[`[-'LXD\K8;G<>:VHF]T+#AHV)9Y^J$#Z$(]
MST(A1HL2I-!`@0!8-(J<0]SPBR$EGK$U`,
MCJ"8WIN(0-75`QJ$C$6)3=$S-YZVYWAYBXV:%(\)B:*%:8YSB+J2VH"``@`@
M#JFUY1C9"3K$)N#B,DC9N5]&^*?5H`*,$8_#`UJ.X08K!+..Y0/^#%=&(<[.
M]2S8RP<^/#?=IZ22A&B.%(TBXAX=39M5A$/"'_@'O%2IAM;Z0O@^J/!P(L
MT,ULC&&$
MMC^ECO`CV7F;,E-HWDJ/SG))QT!@4F)2OQI_HIM5]QJM3K`_PU<#L^'T:T(!-T\)7W_XK[_\
M4QJ$GIRS`7M?;]5M=]IQ)2RAXJ!X@.Q253LC^@?RFV*WG^J:@BU%\T^@_P`J
2)`6<&\$8Q1R1G0`0!V_ZA__9
`
end
-----END PRIVACY-ENHANCED MESSAGE-----