Item
1
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Business
General
Clayton
Williams Energy, Inc., incorporated in Delaware in 1991, is an independent oil
and gas company engaged in the exploration for and production of oil and natural
gas primarily in Texas, Louisiana and New Mexico. Unless the context
otherwise requires, references to the “Company”, “CWEI”, “we”, “us” or “our”
mean Clayton Williams Energy, Inc. and its consolidated
subsidiaries. On December 31, 2007, our estimated proved
reserves were 290.8 Bcfe, of which 76% were proved developed. We have
a balanced portfolio of oil and natural gas reserves, with approximately 42% of
our proved reserves at December 31, 2007 consisting of natural gas and
approximately 58% consisting of oil and natural gas liquids. During
2007, we added proved reserves of 34.9 Bcfe through extensions and
discoveries, had upward revisions of 20.9 Bcfe and had sales of
minerals-in-place of .6 Bcfe. We also achieved average net production
of 98.3 MMcfe per day in 2007, which implies a reserve life of
approximately 8.1 years. CWEI held interests in 6,694 gross
(918.0 net) producing oil and gas wells and owned leasehold interests in
approximately 1.3 million gross (784,000 net) undeveloped acres at
December 31, 2007.
Clayton W.
Williams, Jr. beneficially owns, either individually or through his affiliates,
approximately 20% of the outstanding shares of our common stock. In
addition, The Williams Children’s Partnership, Ltd. (“WCPL”), a limited
partnership of which Mr. Williams’ adult children are the limited partners,
owns an additional 27% of the outstanding shares of our common
stock. Mr. Williams is also our Chairman of the Board and Chief
Executive Officer. As a result, Mr. Williams has significant
influence in matters voted on by our shareholders, including the election of our
Board members. Mr. Williams actively participates in all facets of
our business and has a significant impact on both our business strategy and
daily operations.
Co
mpany
Profile
Business
Strategy
Our goal is
to grow oil and gas reserves and increase shareholder value utilizing a
flexible, opportunity-driven business strategy. We do not adhere to
rigid guidelines for resource allocations, risk profiles, product mixes,
financial measurements or other operating parameters. Instead, we try
to identify exploratory and developmental projects that offer us the best
possible opportunities for growth in oil and gas reserves and allocate our
available resources to those projects. Our direction is heavily
influenced by Mr. Williams based on his 50 years of experience and leadership in
the oil and gas industry. Our business strategy consists of an
aggressive exploration program, complimented by developmental drilling and
proved property acquisitions. From year to year, our allocation of
investment capital may vary between exploratory and developmental activities
depending on our analysis of all available growth opportunities, but our
long-term focus remains consistent with our goal of value enhancement for our
shareholders.
Domestic
Operations
We
conduct all of our drilling, exploration and production activities in the United
States. All of our oil and gas assets are located in the United
States, and all of our revenues are derived from sales to customers within the
United States.
Exploration
Program
Our
exploration program consists of generating exploratory prospects, leasing the
acreage applicable to the prospects, drilling exploratory wells on these
prospects to determine if recoverable oil and gas reserves exist, drilling
developmental wells on prospects, and producing and selling any resulting oil
and gas production.
To
generate a typical exploratory prospect, we first identify geographical areas
that we believe may contain undiscovered oil and gas reserves. We
then consider many other business factors related to those geographical areas,
including proximity to our other areas of operations, our technical knowledge
and experience in the area, the availability of acreage, and the overall
potential for finding reserves. Most of our current exploration
efforts are concentrated in regions that have been known to produce oil and
gas. These regions include some of the larger producing regions in
Texas and Louisiana.
In most
cases, we then obtain and process seismic data using sophisticated geophysical
technology to attempt to visualize underground structures and stratigraphic
traps that may hold recoverable reserves. Although this technology
increases our expectations of a successful discovery, it does not and cannot
assure us of success. Many factors are involved in the interpretation
of seismic data, including the field recording parameters of the data, the type
of processing, the extent of attribute analyses, the availability of subsurface
geological data, and the depth and complexity of the
subsurface. Significant judgment is required in the evaluation of
seismic data, and differences of opinion often exist between experienced
professionals. These interpretations may turn out to be invalid and
may result in unsuccessful drilling results.
Obtaining
oil and gas reserves through exploration activities involves a higher degree of
risk than through drilling developmental wells or purchasing proved
reserves. We often commit significant resources to identify a
prospect, lease the drilling rights and drill a test well before we know if a
well will be productive. To offset this risk, our typical exploratory
prospect is expected to offer a significantly higher reserve potential than a
typical lower-risk development prospect might offer. The reserve
potential is determined by estimating the aerial extent of the structural or
stratigraphic trap, the vertical thickness of the reservoir in the trap, and the
recovery factor of the hydrocarbons in the trap. The recovery factor
is affected by a combination of factors including (i) the reservoir drive
mechanism (water drive, depletion drive or a combination of both), (ii) the
permeability and porosity of the reservoir, and (iii) the bottom hole
pressure (in the case of gas reserves).
Due to
the higher risk/higher potential nature of oil and gas exploration, we expect to
spend money on prospects that are ultimately nonproductive. However,
over time, we believe our productive prospects will generate sufficient cash
flow to provide us with an acceptable rate of return on our entire investment,
both nonproductive and productive.
We are
presently concentrating our exploration efforts in East Texas, Louisiana and
Utah. Approximately 19% of our planned expenditures for 2008 relate
to exploratory prospects, as compared to approximately 51% of actual
expenditures in 2007 and 84% of actual expenditures in 2006. During
2007, we spent $118.6 million on exploratory prospects, including
$16.7 million on seismic and leasing activities and $101.9 million on
drilling activities.
Development
Program
Complimentary
to our higher risk/higher potential exploration program is our development
program. A developmental well is a well drilled within the proved
area of an oil and gas reservoir to a horizon known to be
productive. We have an inventory of developmental projects available
for drilling in the future, most of which are located in the Austin Chalk
(Trend), the Permian Basin and North Louisiana. Some of the
developmental wells in our inventory meet the engineering standards necessary to
be classified as proved reserves. Our estimates of oil and gas
reserves at December 31, 2007 include 93.6 Bcfe of proved reserves
attributable to developmental projects that will require us to spend
approximately $174.3 million over time to develop. In addition,
many of the developmental wells in our inventory do not meet the engineering
standards necessary to be defined as proved reserves and have not been included
in our estimates of proved reserves at December 31, 2007.
In most
cases, our leasehold interests in developmental projects are held by the
continuous production of other wells, meaning that our rights to drill these
projects are not subject to near-term expiration. This provides us
with a high degree of flexibility in the timing of developing these
reserves. Consistent with our business strategy, we have chosen, in
recent years, to limit our spending on developmental projects in order to
maximize our exploration efforts. Due in large part to record
high oil prices, we currently plan to spend approximately $208.1 million,
or 81% of our planned expenditures for 2008, on developmental projects, most of
which are in oil-prone areas. Approximately 37% of our developmental drilling in
2008 will be applicable to wells that have been assigned proved reserves at
December 31, 2007.
Acquisition
and Divestitures of Proved Properties
In
addition to our exploration and development activities, we are also engaged in
the business of acquiring proved reserves. Competition for the
purchase of proved reserves is intense. Sellers often utilize a bid
process to sell properties. This process usually intensifies the
competition and makes it extremely difficult for us to acquire reserves without
assuming significant price and production risks. We are actively
searching for opportunities to acquire proved oil and gas properties; however,
we did not acquire any proved properties in 2007, and we cannot give any
assurance that we will be successful in our efforts to acquire proved properties
in 2008.
From time
to time, we sell certain of our proved properties when we believe it is more
advantageous to dispose of the selected properties than to continue to hold
them. We consider many factors in deciding to sell properties,
including the need for liquidity, the risks associated with continuing to own
the properties, our expectations for future development on the property, the
fairness of the price offered, and other factors related to the condition and
location of the property. In 2007, we sold all of our leasehold
interests in producing and non-producing properties in Pecos County, Texas for
approximately $21 million, and recorded a gain on the sale of approximately
$12.5 million. The leases sold were part of an exploratory project
operated by an industry partner and were not integral to our other West Texas
activities.
Invest
ments
West
Coast Energy Properties, L.P.
West
Coast Energy Properties, L.P. (“WCEP”) is a Texas limited partnership formed in
2006 to facilitate the acquisition of certain producing oil and gas assets in
California and Texas. We are the general partner of WCEP and an
affiliate of GE Energy Financial Services is the limited partner. Our
initial partnership interest is 5%, but our interest can increase to 37.63%, and
ultimately to 49%, upon the achievement of certain target rates of
return. During 2007, we contributed $336,000 of additional capital to
the partnership to finance our share of drilling activity. We account
for our interest in WCEP using the proportionate consolidation method, whereby
our share of WCEP's assets, liabilities, revenues and expenses are consolidated
with our other operations.
Larclay
JV
In April
2006, we formed a joint venture (“Larclay JV”) with Lariat Services, Inc.
(“Lariat”) to construct, own and operate 12 new drilling rigs. We and
Lariat each own a 50% interest in Larclay JV. A lender provided a $75
million secured term loan to Larclay JV to finance most of the cost of
constructing and initially equipping the rigs. The Larclay JV
agreements require us to make loans to Larclay JV as needed to finance any costs
to construct and initially equip the original 12 drilling rigs which are not
otherwise financed under the secured term loan. Construction on 11 of
the rigs is complete, and we loaned Larclay JV $4.6 million during the
fourth quarter of 2007 in compliance with the agreements. The loan to
Larclay JV is due on demand and bears interest, payable monthly, at the same
rate as the secured term loan. However, the loan is subject to a
subordination agreement with the secured lender that imposes restrictions on
payments of principal and interest on the note. All components of the
final Larclay JV drilling rig, a 2,000 horsepower rig designed primarily to
drill deep gas wells, have been purchased, but the final assembly of the rig has
been postponed while we evaluate the market for additional deep rigs in Larclay
JV’s areas of operations. Upon making a final determination, Larclay
JV will either proceed with the final assembly of the rig or it will sell the
rig components. If the rig is assembled for operation, we may be
required to make an additional subordinated loan to finance the costs to
assemble the rig, the amount of which is expected to be less than
$2 million.
Also in
April 2006, we entered into a three-year drilling contract with Larclay JV
assuring the availability of each rig for use in the ordinary course of our
exploration and development drilling program throughout the term of the drilling
contract. The provisions of the drilling contract provide that we
contract for each rig on a well-by-well basis at then current market
rates. If we do not need a rig at any time during the term of the
contract, Larclay JV may contract
with
other operators for the use of such rig, subject to certain
restrictions. If a rig is idle, we will pay Larclay JV an idle rig
rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses,
if applicable), depending on the size of the rig. Our maximum
potential obligation to pay idle rig rates over the term of this drilling
contract, excluding any crew labor expenses, totals approximately
$78.1 million at December 31, 2007.
E
xplora
tion and Development Activities
In 2007,
we spent $230.7 million on exploration and development activities which was
financed primarily by cash flow from operations. We presently plan to
spend approximately $256.5 million on exploration and development
activities during 2008, most of which will be financed by cash flow from
operations, and the balance will be financed by borrowings on our revolving
credit facility. We may increase or decrease our planned activities,
depending upon drilling results, product prices, the availability of capital
resources, and other factors affecting the economic viability of such
activities.
Permian
Basin
The
Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico
known for its large oil and gas deposits from the Permian geologic
period. Although many fields in the Permian Basin have been heavily
exploited in the past, higher product prices and improved technology (including
deep horizontal drilling) continue to encourage high levels of current drilling
and recompletion activities. We gained a significant position in the
Permian Basin in 2004 when we acquired Southwest Royalties, Inc. This
acquisition provided us with an inventory of potential drilling and recompletion
activities that we are beginning to exploit.
We spent
$34.2 million in the Permian Basin during 2007 on exploration and
development activities, of which $33.6 million was spent on drilling and
completion activities and $600,000 was spent on seismic and leasing
activities. We drilled 6 gross (5.0 net) operated wells in
the Permian Basin and conducted remedial operations on existing wells in
2007. In addition, we participated in the drilling of 25 gross (5.5
net) non-operated wells, with working interests ranging from 1% to
54%.
The
Permian Basin continues to be a significant source of cash flow for
us. We currently expect to spend $110.3 million on development
activities in the Permian Basin in 2008. Most of the drilling
activities relate to our War-Wink and Amacker-Tippett prospects in West
Texas. In the War-Wink area, we are presently drilling horizontal
wells targeting oil-prone sands in the Bone Spring formation, and have
identified at least 10 other possible locations to further exploit this
area. On the Amacker-Tippett prospect, we have identified 15 possible
locations on which to drill vertical wells. These wells will target
similar oil-prone sands in the Spraberry and Wolfcamp formations which are
encountered at depths ranging from 7,000 to 10,500 feet. We have also
identified several recompletion opportunities on existing vertical wells in the
area.
Austin
Chalk (Trend)
Prior to
1998, we concentrated our drilling activities in an oil-prone area we refer to
as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Milam and Leon
Counties, Texas. Most of our wells in this area were drilled as horizontal
wells, many with multiple laterals in different producing horizons, including
the Austin Chalk, Buda and Georgetown formations. The existing
spacing between some of our wells in this area affords us the opportunity to tap
additional oil and gas reserves by drilling new wells between existing
wells, a technique referred to as in-fill drilling. These in-fill
wells are considered lower risk as compared to exploratory wells and, with oil
prices at historic highs, the rates of return are now attractive. In
addition, we are conducting secondary water frac operations on existing
wells in the Austin Chalk (Trend) area to improve production rates and add new
reserves. We plan to spend $59.3 million on development activities
and leasing in this area during 2008.
South
Louisiana
Since
2000, we have been exploring for oil and gas reserves in South Louisiana and
have developed this area into one of our key sources of production and cash
flow. Most of the prospects we have generated in South Louisiana have
been identified based on 3-D seismic data and technology and have generally
consisted of multi-pay, Miocene-age sands.
Prior to
2007, we had drilled 67 gross (53.6 net) exploratory wells in South Louisiana,
of which 34 gross (25.9 net) were completed as producers. The
following table sets forth certain information about wells which were
significant to our drilling and completion activities in South Louisiana
subsequent to December 31, 2006.
|
|
|
|
|
Working
|
|
Current
|
|
Spud
Date
|
|
Well
Name (Prospect)
|
|
Interest
|
|
Status
|
|
January
2007
|
|
SL
195 QQ #7 (Floyd)
|
|
100%
|
|
Producing
|
|
February
2007
|
|
SL
195 QQ #10 (Floyd)
|
|
75%
|
|
Producing
|
|
February
2007
|
|
Orleans
Levee District #2 (American Bay)
|
|
45%
|
|
Producing
|
|
March
2007
|
|
Bowie
Lumber Co. #1 (Bayou Boeuf)
|
|
100%
|
|
Dry
|
|
April
2007
|
|
Pivach
Agency #1 (Elsa)
|
|
94%
|
|
Dry
|
|
June
2007
|
|
SL
195 QQ #12 (Floyd)
|
|
100%
|
|
Producing
|
|
June
2007
|
|
SL
16849 #2 (Dolly)
|
|
94%
|
|
Producing
|
We spent
$65.7 million in South Louisiana during 2007 on exploration and development
activities, of which $60.6 million was spent on drilling and completion
activities and $5.1 million was spent on seismic and leasing
activities. We currently plan to spend approximately
$13.4 million in South Louisiana in 2008 for drilling and leasing
activities.
We
completed development activities on our Floyd prospect in 2007, and do not
expect to spend any additional capital in 2008 on new drilling in this area due
primarily to lower than expected production performance and net downward reserve
revisions of 11.2 Bcfe from our prior fiscal year.
In late
2007, we entered into an agreement with an industry partner, in which they have
committed to drill five wells on certain of our prospects in South Louisiana
during 2008. The industry partner will operate the wells, and we will have a 15%
before casing point working interest and a 50% after casing point working
interest in each well drilled. We expect to spend approximately $2.9
million for our portion of drilling activities under this
agreement.
We
currently plan to spend an additional $10.5 million in South Louisiana in
2008 to generate and lease new exploratory prospects and to drill wells on
existing exploratory and developmental prospects not related to the five-well
agreement described above.
North
Louisiana
In 2005,
we began an exploration program in North Louisiana targeting the Cotton
Valley/Gray and Bossier formations. In this area, the Cotton
Valley/Gray formations are encountered at depths ranging from 8,000 to
12,000 feet, and the Bossier formation is encountered at depths ranging
from 11,000 to 15,500 feet. We believe that these tight
sandstone formations have become more economically viable due to higher product
prices, coupled with enhanced drilling and completion techniques.
The
following table sets forth certain information about wells which were
significant to our drilling and completion activities in North Louisiana
subsequent to December 31, 2006. This table does not include
21 gross (2.0 net) non-operated wells in which our working interests
range from 1% to 29%.
|
|
|
|
|
Working
|
|
Current
|
|
Spud
Date
|
|
Well
Name (Prospect)
|
|
Interest
|
|
Status
|
|
October
2006
|
|
P.
Benoit #1 (Sarepta)
|
|
91%
|
|
Dry
|
|
January
2007
|
|
J.L.
Hood #1 (Terryville)
|
|
86%
|
|
Producing
|
|
February
2007
|
|
J.
Huey #1 (Terryville)
|
|
86%
|
|
Producing
|
|
March
2007
|
|
David
Barton #1 (Winnsboro)
|
|
100%
|
|
Dry
|
|
March
2007
|
|
George
Staton #1 (Sarepta)
|
|
68%
|
|
Producing
|
|
April
2007
|
|
C.M.
Bice #1 (Terryville)
|
|
86%
|
|
Producing
|
|
May
2007
|
|
C.
Dugdale #1 (Choudrant)
|
|
99%
|
|
Dry
|
|
June
2007
|
|
Stephenson
#1 (Terryville)
|
|
86%
|
|
Producing
|
|
June
2007
|
|
John
Warren #1 (Terryville)
|
|
86%
|
|
Producing
|
|
July
2007
|
|
Burks
#1 (Terryville)
|
|
86%
|
|
Producing
|
|
July
2007
|
|
Henry
#2 (Terryville)
|
|
86%
|
|
Dry
|
|
July
2007
|
|
Allen
Estate #1 (Terryville)
|
|
100%
|
|
Producing
|
|
August
2007
|
|
McCrary
#1 (Terryville)
|
|
86%
|
|
Producing
|
|
August
2007
|
|
Henry
#1 (Terryville)
|
|
86%
|
|
Producing
|
|
September
2007
|
|
LA
Minerals #1 (Ruston)
|
|
66%
|
|
Producing
|
|
October
2007
|
|
Barnett
#1 (Terryville)
|
|
86%
|
|
Producing
|
|
November
2007
|
|
A.
Lewis Estate #2 (Terryville)
|
|
86%
|
|
Producing
|
|
January
2008
|
|
Henry
#3 (Terryville)
|
|
86%
|
|
Producing
|
|
February
2008
|
|
J.G.
Mitchell #1 (Ruston)
|
|
74%
|
|
Drilling
|
We spent
$74.3 million in North Louisiana during 2007 on exploration and development
activities, of which $69.9 million was spent on drilling and completion
activities and $4.4 million was spent on seismic and leasing
activities. Our drilling activities in North Louisiana resulted in
the addition of approximately 19.1 Bcfe of proved reserves in 2007, most of
which came from our Terryville prospect in Lincoln Parish.
To date, we
have completed thirteen wells on the Terryville prospect as
producers. These wells are currently producing at combined rates of
approximately 10,730 Mcf of gas per day and 310 barrels of oil per day, net to
the Company’s interest. We expect to drill five more development
wells on our Terryville prospect in 2008.
Our first
exploratory well on the Sarepta prospect in Webster Parish, the P. Benoit #1,
targeted a hydrocarbon formation in the Gray sand, but that zone was
non-productive and we recorded a pre-tax charge of $4.9 million related to the
abandonment of this well. We also drilled the George Staton #1, a
12,200-foot exploratory well in the Sarepta prospect, which is currently
producing.
We drilled
the C. Dugdale #1 on our Choudrant prospect in Lincoln Parish to the Cotton
Valley interval which was deemed non-commercial, thus resulting in a pre-tax
charge of $7.1 million for the abandonment of this well. We do not
plan to drill any additional wells on this prospect in 2008. Also in
Lincoln Parish, on our Ruston prospect, we have drilled the LA Minerals #1 which
is producing from the Gray sand. We are currently drilling the J.G.
Mitchell #1 and plan to drill another 3 wells on this prospect in
2008.
We
temporarily abandoned the David Barton #1, an exploratory well in the Winnsboro
prospect in Richland Parish, prior to reaching the pressured Bossier
interval. We recorded a pre-tax charge of $8.6 million related to the
abandonment of this well in the second quarter of 2007. We may drill
an offset to the Barton well in 2008 in order to test the pressured Bossier
interval in this area.
We
currently have approximately 170,000 net acres leased for Bossier drilling in
North Louisiana. In 2007, we recorded a $9.3 million provision for
impairment of certain acreage in the area in order to reduce the carrying value
to its estimated fair value.
In 2008,
we currently plan to spend approximately $47.9 million in North Louisiana in
2008 primarily to drill developmental wells on the Terryville and Choudrant
prospects.
East
Texas Bossier
We
currently have approximately 142,000 net acres under lease in East Texas
targeting the prolific deep Bossier sands which are encountered at depths
ranging from 14,000 to 22,000 feet in this area. Of this
acreage, approximately 70,000 net acres are held by production from existing
Austin Chalk (Trend) wells. Exploration for deep Bossier gas sands in
this area is in its early stages and involves a high degree of
risk. The geological structures are complex, and limited drilling
activity offers minimal subsurface control. Deep Bossier wells are
expensive to drill, with completed wells costing approximately $18 million
each. Although seismic data is helpful in identifying possible sand
accumulations, the only way to determine if the deep Bossier sand will be
commercially productive is to drill wells to the targeted
structures.
During
2007, we drilled two wells in this area targeting the deep Bossier, the Big Bill
Simpson #1, a 19,000-foot exploratory well in Leon County (70% working
interest), and the Margarita #1, a 20,000-foot exploratory well in Robertson
County (100% working interest). These wells were in progress at
December 31, 2007 and were completed during the first quarter of
2008. The Big Bill Simpson well encountered a thick section of lower
and middle Bossier sands, but these sands had limited porosity. The
Margarita #1 well only encountered the upper Bossier sand.
The Big
Bill Simpson #1 is currently producing approximately 500 gross (263 net) Mcf of
gas per day. The Margarita #1 is waiting on completion of pipeline facilities to
begin production, but is expected to initially produce approximately 750 gross
(563 net) Mcf of gas per day, based on well test data. We have not
assigned any proved reserves to these wells since we do not have sufficient
production history to permit us to make a reasonable estimate at this
time. However, it appears to be unlikely that we will recover the $28
million of drilling and completion costs we incurred on these wells through
future production from only these wells. Depending on our evaluations
of these wells and our results of drilling activities in our deep Bossier play,
we may record impairments of proved properties related to these wells in future
periods.
We
currently plan to spend approximately $17.2 million in the East Texas Bossier
area related primarily to leasing and seismic activities. Despite the
disappointing results of the Big Bill Simpson #1 and the Margarita #1, we are
optimistic that our acreage position in this area is prospective for potentially
significant deep Bossier discoveries. As more wells are drilled and
more subsurface control data is obtained, we believe our prospects for
discoveries improve. We have begun a 3-D seismic shoot in Leon
County, Texas over the Big Bill Simpson prospect in an attempt to high grade our
next well’s position on this acreage. In addition, we are considering
a proprietary 3-D shoot in Burleson County, Texas to help us select potential
drill sites on other deep Bossier prospects in this area.
Other
Exploration and Development Activities
In Utah,
we plan to participate in the drilling of a 12,000-foot exploratory well, the
Lamb #1 in the Overthrust prospect (33% working interest) in Sanpete County,
Utah. The well will target the oil-prone Navajo sandstone
formation.
M
arketing
Arrangements
We sell
substantially all of our oil production under short-term contracts based on
prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas
Intermediate contracts, less agreed-upon deductions which vary by grade of crude
oil. The majority of our gas production is sold under short-term
contracts based on pricing formulas which are generally market
responsive. From time to time, we may also sell a portion of our gas
production under short-term contracts at fixed prices. We believe
that the loss of any of our oil and gas purchasers would not have a material
adverse effect on our results of operations due to the availability of other
purchasers.
N
atural
Gas Services
We own an
interest in and operate natural gas service facilities in the states of Texas,
Louisiana, Mississippi and New Mexico. These natural gas service facilities
consist of interests in approximately 94 miles of pipeline, three treating
plants, one dehydration facility, three compressor stations, and four wellhead
type treating and/or compression facilities. Most of our operated gas
gathering and treating activities exist to facilitate the transportation and
marketing of our operated oil and gas production.
C
ompeti
tion and Markets
Competition
in all areas of our operations is intense. We experience competition
from major and independent oil and gas companies and oil and gas syndicates in
bidding for desirable oil and gas properties, as well as in acquiring the
equipment, data and labor required to operate and develop such properties. A
number of our competitors have financial resources and acquisition, exploration
and development budgets that are substantially greater than ours, which may
adversely affect our ability to compete with these companies. Competitors may be
able to pay more for productive oil and gas properties and exploratory prospects
and to define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. Our ability
to increase reserves in the future will depend on our success at selecting and
acquiring suitable producing properties and prospects for future development and
exploration activities.
In
addition, the oil and gas industry as a whole also competes with other
industries in supplying the energy and fuel requirements of industrial,
commercial and individual consumers. The price and availability of
alternative energy sources could adversely affect our revenue.
The
market for our oil, gas and natural gas liquids production depends on factors
beyond our control, including domestic and foreign political conditions, the
overall level of supply of and demand for oil, gas and natural gas liquids, the
price of imports of oil and gas, weather conditions, the price and availability
of alternative fuels, the proximity and capacity of gas pipelines and other
transportation facilities and overall economic conditions.
R
egula
tion
Generally.
Our oil
and gas exploration, production and related operations and activities are
subject to extensive rules and regulations promulgated by federal, state and
local agencies. Failure to comply with such rules and regulations can result in
substantial penalties. Because such rules and regulations are frequently amended
or reinterpreted, we are unable to predict the future cost or impact of
complying with such laws. Although the regulatory burden on the oil and gas
industry increases our cost of doing business and, consequently, affects our
profitability,
these burdens generally do not affect us any differently or to any greater or
lesser extent than they affect others in our industry with similar types,
quantities and locations of production.
Regulations affecting
production.
All of the states in which we operate generally
require permits for drilling operations, require drilling bonds and reports
concerning operations and impose other requirements relating to the exploration
and production of oil and gas. Such states also have statutes or
regulations addressing conservation matters, including provisions for the
unitization or pooling of oil and gas properties, the establishment of maximum
rates of production from oil and gas wells, the spacing, plugging and
abandonment of such wells, restrictions on venting or flaring natural gas and
requirements regarding the ratability of production.
These
laws and regulations may limit the amount of oil and natural gas we can produce
from our wells and may limit the number of wells or the locations at which we
can drill. Moreover, many states impose a production or severance tax with
respect to the production and sale of oil and natural gas within their
jurisdiction. States do not generally regulate wellhead prices or engage in
other, similar direct economic regulation of production, but there can be no
assurance they will not do so in the future.
In the
event we conduct operations on federal, state or Indian oil and natural gas
leases, our operations may be required to comply with additional regulatory
restrictions, including various nondiscrimination statutes, royalty and related
valuation requirements, and on-site security regulations and other appropriate
permits issued by the Bureau of Land Management (“BLM”) or other relevant
federal or state agencies.
Regulations affecting
sales.
The sales prices of oil, natural gas liquids and
natural gas are not presently regulated, but rather are set by the
market. We cannot predict, however, whether new legislation to
regulate the price of energy commodities might be proposed, what proposals, if
any, might actually be enacted by Congress or the various state legislatures,
and what effect, if any, the proposals might have on the operations of the
underlying properties.
Under the
Energy Policy Act of 2005, the Federal Energy Regulatory Commission (“FERC”)
possesses regulatory oversight over natural gas markets, including the purchase,
sale and transportation of natural gas by “any entity.” The Commodity Futures
Trading Commission (“CFTC”) also holds authority to monitor certain segments of
the physical and futures energy commodities market pursuant to the Commodity
Exchange Act. With regard to our physical purchases and sales of
natural gas, natural gas liquids and crude oil, our gathering of these energy
commodities, and any related hedging activities that we undertake, we are
required to observe these anti-market manipulation laws and related regulations
enforced by FERC and/or the CFTC. These agencies hold substantial
enforcement authority, including the ability to assess civil penalties of up to
$1 million per day per violation, to order disgorgement of profits and to
recommend criminal penalties. Should we violate the anti-market
manipulation laws and regulations, we could also be subject to related third
party damage claims by, among others, sellers, royalty owners and taxing
authorities.
The price
we receive from the sale of oil and natural gas liquids is affected by the cost
of transporting those products to market. The FERC regulates
interstate natural gas transportation rates and service conditions, which affect
the marketing of gas we produce, as well as the revenues we receive for sales of
such production. The price and terms of access to pipeline
transportation are subject to extensive federal and state
regulation. The FERC is continually proposing and implementing new
rules and regulations affecting interstate
transportation. These initiatives also may affect the
intrastate transportation of natural gas under certain
circumstances. The stated purpose of many of these regulatory changes
is to promote competition among the various sectors of the natural gas industry.
We do not believe that we will be affected by any such FERC action in a manner
materially differently than other natural gas producers in our areas of
operation.
Interstate
transportation rates for oil, natural gas liquids and other products is also
regulated by the FERC. The FERC has established an indexing system
for such transportation, which allows such pipelines to take an annual
inflation-based rate increase. We are not able to predict with any
certainty what effect, if any, these regulations will have on us, but, other
factors being equal, the regulations may, over time, tend to increase
transportation costs which may have the effect of reducing wellhead prices for
oil and natural gas liquids.
Gathering
regulations
. Section 1(b) of the NGA exempts natural gas
gathering facilities from the jurisdiction of the FERC under the
NGA. We own certain natural gas pipelines that we believe meet the
traditional tests that the FERC has used to establish a pipeline’s status as a
gatherer not subject to FERC jurisdiction. The distinction between
FERC-regulated transmission facilities and federally unregulated gathering
facilities is, however, the
subject
of substantial, on-going litigation, so the classification and regulation of our
gathering lines may be subject to change based on future determinations by the
FERC, the courts or the U.S. Congress.
State
regulation of gathering facilities generally includes various safety,
environmental and, in some circumstances, nondiscriminatory take requirements
and in some instances complaint-based rate regulation. Our gathering
operations are also subject to state ratable take and common purchaser statutes,
designed to prohibit discrimination in favor of one producer over another or one
source of supply over another.
E
nvironment
al Matters
Our
operations pertaining to oil and gas exploration, production and related
activities are subject to numerous and constantly changing federal, state and
local laws governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and
regulations may require the acquisition of certain permits prior to or in
connection with our operations, restrict or prohibit the types, quantities and
concentration of substances that we can release into the environment, restrict
or prohibit activities that could impact wetlands, endangered or threatened
species or other protected areas or natural resources, require some degree of
remedial action to mitigate pollution from former operations, such as pit
cleanups and plugging abandoned wells, and impose substantial liabilities for
pollution resulting from our operations. Such laws and regulations
may substantially increase the cost of our operations and may prevent or delay
the commencement or continuation of a given project and thus generally could
have a material adverse effect upon our capital expenditures, earnings, or
competitive position. Violation of these laws and regulations could
result in significant fines or penalties. We have experienced
accidental spills, leaks and other discharges of contaminants at some of our
properties, as have other similarly situated oil and gas companies, and some of
the properties that we have acquired, operated or sold, or in which we may hold
an interest but not operational control, may have past or ongoing contamination
for which we may be held responsible. Some of our operations are
located in environmentally sensitive environments, such as coastal waters,
wetlands and other protected areas. Some of our properties are
located in areas particularly susceptible to hurricanes and other destructive
storms, which may damage facilities and cause the release of pollutants. Our
environmental insurance coverage may not fully insure all of these risks.
Although the costs of remedying such conditions may be significant, we do not
believe these costs would have a material adverse impact on our financial
condition and operations.
We
believe that we are in substantial compliance with current applicable
environmental laws and regulations, and the cost of compliance with such laws
and regulations has not been material and is not expected to be material during
2008. We do not believe that we will be required to incur any
material capital expenditures to comply with existing environmental
requirements. Nevertheless, changes in existing environmental laws
and regulations or in the interpretations thereof could have a significant
impact on our operations, as well as the oil and gas industry in
general. For instance, any changes in environmental laws and
regulations that result in more stringent and costly waste handling, storage,
transport, disposal or clean-up requirements could have a material adverse
impact on our operations.
Hazardous
Substances.
The Comprehensive Environmental Response,
Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law,
imposes liability, without regard to fault or the legality of the original
conduct, on certain classes of persons that are considered to have contributed
to the release of a “hazardous substance” into the environment. These
persons include the owner or operator of the disposal site or the site where the
release occurred and companies that disposed or arranged for the disposal of the
hazardous substances at the site where the release occurred. Under
CERCLA, such persons may be subject to joint and several liability for the costs
of cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, 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. We are able to control directly the operation
of only those wells with respect to which we act as
operator. Notwithstanding our lack of direct control over wells
operated by others, the failure of an operator other than us to comply with
applicable environmental regulations may, in certain circumstances, be
attributed to us. We are not aware of any liabilities for which we
may be held responsible that would materially and adversely affect
us.
Waste
Handling.
The Resource Conservation and Recovery Act (“RCRA”),
and analogous state laws, impose detailed requirements for the handling,
storage, treatment and disposal of hazardous and solid wastes. RCRA
specifically excludes drilling fluids, produced waters, and other wastes
associated with the exploration, development, or production of crude oil,
natural gas or geothermal energy from regulation as hazardous
wastes. However, these wastes may be regulated by the U.S.
Environmental Protection Agency (“EPA”) or state agencies as solid
wastes. Moreover, many ordinary industrial wastes, such as paint
wastes, waste solvents, laboratory wastes
and waste
compressor oils, are regulated as hazardous wastes. Although the
costs of managing hazardous waste may be significant, we do not believe that our
costs in this regard are materially more burdensome than those for similarly
situated companies.
Air Emissions.
The
Federal Clean Air Act and comparable state laws and regulations impose
restrictions on emissions of air pollutants from various industrial sources,
including compressor stations and natural gas processing facilities, and also
impose various monitoring and reporting requirements. Such laws and
regulations may require that we obtain pre-approval for the construction or
modification of certain projects or facilities expected to produce air emissions
or result in the increase of existing air emissions, obtain and strictly comply
with air permits containing various emissions and operational limits, or utilize
specific emission control technologies to limit emissions. Our
failure to comply with these requirements could subject us to monetary
penalties, injunctions, conditions or restrictions on operations, and
potentially criminal enforcement actions. Capital expenditures for
air pollution equipment may be required in connection with maintaining or
obtaining operating permits and approvals relating to air emissions at
facilities owned or operated by us. We do not believe that our operations will
be materially adversely affected by any such requirements.
Water
Discharges.
The Federal Water Pollution Control Act (“Clean
Water Act”) and analogous state laws impose restrictions and strict controls
with respect to the discharge of pollutants, including spills and leaks of oil
and other substances, into waters of the United States. The discharge
of pollutants into regulated waters is prohibited, except in accordance with the
terms of a permit issued by EPA or an analogous state agency. Federal
and state regulatory agencies can impose administrative, civil and criminal
penalties for non-compliance with discharge permits or other requirements of the
Clean Water Act and analogous state laws and regulations. In
addition, the United States Oil Pollution Act of 1990 (“OPA”) and similar
legislation enacted in Texas, Louisiana and other coastal states impose oil
spill prevention and control requirements and significantly expand liability for
damages resulting from oil spills. OPA imposes strict and, with
limited exceptions, joint and several liabilities upon each responsible party
for oil spill response and removal costs and a variety of public and private
damages.
Global Warming and Climate
Change.
In response to recent studies suggesting that
emissions of carbon dioxide and certain other gases may be contributing to
warming of the Earth’s atmosphere, the current session of the U.S. Congress is
considering adoption of climate change-related legislation that would restrict
emissions of “greenhouse gases.” One bill recently approved by the
Senate Committee on Environment and Public Works would require a 70% reduction
in emissions of greenhouse gases from sources within the United States between
2012 and 2050. In addition, at least 20 states have already taken
legal measures to reduce emissions of greenhouse gases, primarily through the
planned development of greenhouse gas emission inventories and/or regional
greenhouse gas cap and trade programs. In California, for example,
the California Global Warming Solutions Act of 2006 requires the California Air
Resources Board to adopt regulations by 2012 that will achieve an overall
reduction in greenhouse gas emissions from all sources in California of 25% by
2020. Also, as a result of the U.S. Supreme Court’s decision on April
2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate
carbon dioxide and other greenhouse gas emissions from mobile sources (e.g.,
cars and trucks) even if Congress does not adopt new legislation specifically
addressing emissions of greenhouse gases.
Depending
on the legislation or regulatory program that may be adopted to address
emissions of greenhouse gases, we could be required to reduce greenhouse gas
emissions resulting from our operations or we could be required to purchase and
surrender allowances for greenhouse gas emissions associated with our operations
or the oil and gas we produce. Although we would not be impacted to a
greater degree than other similarly situated producers of oil and gas, a
stringent greenhouse gas control program could have an adverse effect on our
cost of doing business and could reduce demand for the oil and gas we
produce.
Pipeline
Safety.
Some of our pipelines are subject to regulation by the
U.S. Department of Transportation (“DOT”) under the Pipeline Safety Improvement
Act of 2002, which was reauthorized and amended by the Pipeline Inspection,
Protection, Enforcement and Safety Act of 2006. The DOT, through the Pipeline
and Hazardous Materials Safety Administration (“PHMSA”), has established a
series of rules that require pipeline operators to develop and implement
integrity management programs for gas, natural gas liquids (“NGLs”) and
condensate transmission pipelines that, in the event of a failure, could affect
“high consequence areas.” “High consequence areas” are currently defined to
include areas with specified population densities, buildings containing
populations with limited mobility, areas where people may gather along the route
of a pipeline (such as athletic fields or campgrounds), environmentally
sensitive areas, and commercially navigable waterways. Under the DOT’s
regulations, integrity management programs are required to include baseline
assessments to identify potential threats to each pipeline segment,
implementation of mitigation measures to reduce the risk of pipeline failure,
periodic reassessments, reporting and recordkeeping. The DOT also is required by
the Pipeline Inspections, Protection,
Enforcement,
and Safety Act of 2006 to issue new regulations that set forth safety standards
and reporting requirements applicable to low stress pipelines and gathering
lines transporting hazardous liquids, including oil, NGLs and condensate. A
final rule addressing safety standards for hazardous liquid low-stress pipelines
and gathering lines is anticipated to be issued by PHMSA in 2008. Such new
hazardous liquid pipeline safety standards may include applicable integrity
management program requirements.
OSHA and Other Laws and
Regulation.
We are subject to the requirements of the federal
Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These
laws and the implementing regulations strictly govern the protection of the
health and safety of employees. The OSHA hazard communication standard, EPA
community right-to-know regulations under the Title III of CERCLA and similar
state statutes require that we organize and/or disclose information about
hazardous materials used or produced in our operations. We believe that we are
in substantial compliance with these applicable requirements and with other OSHA
and comparable requirements.
Claims
are sometimes made or threatened against companies engaged in oil and gas
exploration, production and related activities by owners of surface estates,
adjoining properties or others alleging damages resulting from environmental
contamination and other incidents of operations. We have been named as a
defendant in a number of such lawsuits. While some jurisdictions in which we
operate limit damages in such cases to the value of land that has been impaired,
in other jurisdictions in which we operate, courts have allowed damage claims in
excess of land value, including claims for the cost of remediation of
contaminated properties. However, we do not believe that resolution of these
claims will have a material adverse impact on our financial condition and
operations.
Title to Properties
As is
customary in the oil and gas industry, we perform a minimal title investigation
before acquiring undeveloped properties. A title opinion is obtained
prior to the commencement of drilling operations on such
properties. We have obtained title opinions on substantially all of
our producing properties and believe that we have satisfactory title to such
properties in accordance with standards generally accepted in the oil and gas
industry. These title investigations and title opinions, while
consistent with industry standards, may not reveal existing or potential title
defects, encumbrances or adverse claims as we are subject from time to time to
claims or disputes regarding title to properties. Our properties are
subject to customary royalty interests, liens incident to operating agreements,
liens for current taxes and other burdens that we believe do not materially
interfere with the use of or affect the value of such properties. Substantially
all of our oil and gas properties are currently mortgaged to secure borrowings
under our revolving credit facility and may be mortgaged under any future credit
facilities entered into by us.
O
peratio
nal Hazards and Insurance
Our
operations are subject to the usual hazards incident to the drilling and
production of oil and gas, such as blowouts, cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fires and pollution and other
environmental risks. These hazards can cause personal injury and loss
of life, severe damage to and destruction of property and equipment, pollution
or environmental damage and suspension of operation. In addition, the
presence of unanticipated pressures or irregularities in formations,
miscalculations, or accidents may cause our drilling activities to be
unsuccessful and result in a total loss of our investment.
We
maintain insurance of various types to cover our operations with policy limits
and retention liability customary in the industry. We believe the
coverage and types of insurance are adequate. The occurrence of a
significant adverse event, the risks of which are not fully covered by
insurance, could have a material adverse effect on our financial condition and
results of operations. We cannot give any assurances that we will be
able to maintain adequate insurance in the future at rates we consider
reasonable.
Executive Officers
The
following is a list, as of March 14, 2008 of the name, age and position with the
Company of each person who is an executive officer of the Company:
CLAYTON
W. WILLIAMS, JR., age 76, is Chairman of the Board, President, Chief Executive
Officer and a director of the Company, having served in such capacities since
September 1991. For more than the past five years, Mr. Williams
has also been the chief executive officer and a director of certain entities
which are controlled directly or indirectly by Mr. Williams.
L. PAUL
LATHAM, age 56, is Executive Vice President, Chief Operating Officer and a
director of the Company, having served in such capacities since September
1991. Mr. Latham is the sole general partner of The Williams
Children’s Partnership, Ltd. (“WCPL”), a limited partnership in which the adult
children of Clayton W. Williams, Jr. are the limited partners. WCPL
holds approximately 27% of the outstanding shares of our common
stock. As the sole general partner, Mr. Latham has the power to vote
or direct the voting of the shares of our common stock held by
WCPL. Mr. Latham also serves as an officer and director of
certain entities which are controlled directly or indirectly by Mr.
Williams.
MEL G.
RIGGS, age 53, is Senior Vice President and Chief Financial Officer of the
Company, having served in such capacities since September 1991. Mr.
Riggs has served as a director of the Company since May 1994.
PATRICK
C. REESBY, age 55, is Vice President – New Ventures of the Company, having
served in such capacity since 1993.
ROBERT C.
LYON, age 71, is Vice President – Gas Gathering and Marketing of the Company,
having served in such capacity since 1993.
MICHAEL
L. POLLARD, age 58, is Vice President – Accounting of the Company, having served
in such capacity since 2003. Prior to that, Mr. Pollard had served as
Controller of the Company since 1993.
T. MARK
TISDALE, age 51, is Vice President and General Counsel of the Company, having
served in such capacity since 1993.
GREGORY
S. WELBORN, age 34, is Vice President – Land of the Company, having served in
such capacity since 2006.
Employ
ees
At
December 31, 2007, we had 186 full-time employees, none of whom is subject to a
collective bargaining agreement. In our opinion, our relations with
employees are good.
Website Address
The
Company maintains an internet website at www.claytonwilliams.com. The
Company makes available, free of charge, on its website, its 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 providing
such reports to the SEC. The information contained in or incorporated
in our website is not part of this report.
Item
1A
-
Risk
Factors
There are
many factors that affect our business, some of which are beyond our
control. Our business, financial condition and results of operations
could be materially adversely affected by any of these risks. The
risks described below are not the only ones facing our
company. Additional risks not presently known to us or that we
currently deem immaterial individually or in the aggregate may also impair our
business operations.
Our
exploration activities subject us to greater risks than development
activities.
As a
general rule, our oil and gas exploration activities pose a higher economic risk
to us than our development activities. Exploration activities involve the
drilling of wells in areas where there is little or no known production.
Development activities relate to increasing oil or natural gas production from
an area that is known to be productive by drilling additional wells, working
over and recompleting existing wells and other production enhancement
techniques. Exploration projects are identified through subjective analysis of
geological and geophysical data, including the use of 3-D seismic and other
available technology. By comparison, the identification of development prospects
is significantly based upon existing production surrounding or adjacent to the
proposed drilling site.
For 2008,
approximately 19% of our planned exploration and development activities relate
to exploratory prospects, as compared to 51% in 2007. Although we
currently plan to spend a much lesser portion of our investment capital on
exploration activities in 2008 than in recent years, our on-going business
strategy includes a heavy commitment to oil and gas exploration. To
the extent we engage in exploration activities, we have a greater risk of
drilling dry holes or not finding oil and natural gas that can be produced
economically. The seismic data and other technology we use does not allow us to
know with certainty prior to drilling a well whether oil or natural gas is
present or can be produced economically. We charged to expense
$68.9 million in 2007 for abandonment and impairment, most of which was
related to unsuccessful exploratory drilling activities in North and South
Louisiana. We cannot assure you that any of our future exploration
efforts will be successful. If these activities are unsuccessful, it will have a
significant adverse affect on our results of operations, cash flow and capital
resources.
If
we do not replace reserves we produce, our financial results will
suffer.
In
general, the volume of production from an oil and gas property declines as
reserves related to that property are depleted. The decline rates depend upon
reservoir characteristics. Historically, our oil and gas properties have had
steep rates of decline and short estimated productive lives. The implied life of
our proved reserves at December 31, 2007 is approximately 8.1 years, based
on 2007 production levels.
Our oil
and gas reserves will decline as they are produced unless we are able to conduct
successful exploration and development activities or acquire properties with
proved reserves. Because we are engaged to a large extent in exploration
activities, our ability to replace produced reserves is subject to a higher
level of risk and is less predictable than it might be if we limited our efforts
to developmental drilling activities.
Volatility
of oil and gas prices significantly affects our cash flow and capital resources
and our ability to produce oil and gas economically.
Historically,
the markets for oil and gas have been volatile, and we believe that they are
likely to continue to be volatile. Significant changes in oil and gas prices may
result from relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and other factors that are beyond our control.
We cannot predict, with any degree of certainty, future oil and natural gas
prices. Changes in oil and natural gas prices significantly affect our revenues,
operating results, profitability and the value of our oil and gas reserves.
Those prices also affect the amount of cash flow available for capital
expenditures, our ability to borrow money or raise additional capital and the
amount of oil and natural gas that we can produce economically. The amount we
can borrow under our revolving credit facility is subject to periodic
redeterminations based in part on current prices for oil and natural gas at the
time of the redetermination.
Changes
in oil and gas prices impact both our estimated future net revenue and the
estimated quantity of proved reserves. Price increases may permit additional
quantities of reserves to be produced economically, and price decreases may
render uneconomic the production of reserves previously classified as proved.
Thus, we may experience material increases and decreases in reserve quantities
solely as a result of price changes and not as a result of drilling or well
performance. We attempt to optimize the price we receive for our oil and gas
production while maintaining a prudent hedging program to mitigate our exposure
to declining product prices. Our management may elect to enter into and
terminate hedges based on expectations of future market conditions. If prices
continue to rise while our hedges are in place, we will forego revenue we would
have otherwise received. If we terminate a hedge because we anticipate an
increase in product prices that we would not realize with the hedge in place,
and product prices do not increase as anticipated, we may be exposed to downside
risk that would not have existed otherwise.
Our
liquidity, including the availability of capital resources, is
uncertain.
Our cash
flow forecasts indicate that the amount of funds available to us under our
revolving credit facility, when combined with our anticipated operating cash
flow, will be sufficient to finance our capital expenditures and will provide us
with adequate liquidity at least through 2008. Although we believe
the assumptions and estimates made in our forecasts are reasonable,
uncertainties exist which could cause the borrowing base to be less than
expected, cash flow to be less than expected, or capital expenditures to be more
than expected. Below is a discussion of uncertainties that are likely
to have a material effect on our liquidity and capital resources if such
uncertainties occur.
Our liquidity will suffer if our
exploration activities are not successful.
For 2008,
approximately 19% of our planned capital expenditures relate to exploratory
prospects, where we have a greater risk of drilling dry holes or not finding oil
and natural gas that can be produced economically. Several of our
exploratory prospects target deep formations, including the Bossier formation in
East Texas. Wells on these prospects are very expensive to drill and
involve a very high degree of risk. If these exploratory wells are
unsuccessful, our cash flow from operations and our liquidity will be adversely
affected.
Adverse changes in reserve estimates
or commodity prices could reduce the borrowing base under our revolving credit
facility.
The lenders under our revolving credit facility
establish the borrowing base under such facility at least twice annually by
preparing a reserve report using price-risk assumptions they believe are proper
under the circumstances. Any adverse changes in estimated quantities
of reserves, the pricing parameters being used, or the risk factors being
applied, since the date of the last borrowing base determination, could lower
the borrowing base under our revolving credit facility.
Failure to comply with covenants
under our debt agreements could adversely impact our financial condition and
results of operations.
Our revolving credit facility contains
financial covenants that require us to, among other things maintain
positive working capital in accordance with computational guidelines contained
in the related loan agreement and to maintain a ratio of indebtedness to
cash flow of no more than 3 to 1. Although we are in compliance with
these covenants at December 31, 2007, adverse changes in our leverage or
liquidity could cause us to fail to comply with one or more of these
covenants. If we fail to meet any of these loan covenant, the lenders
under the revolving credit facility could accelerate the indebtedness and seek
to foreclose on the pledged assets.
Adverse changes in reserve estimates
or commodity prices could reduce our cash flow from operating
activities
. We rely on estimates of reserves to forecast our
cash flow from operating activities. If the production from those
reserves is delayed or is lower than expected, our cash flow from operating
activities may be lower than
we
anticipated. Commodity prices also impact our cash flow from
operating activities. Based on December 31, 2007 reserve estimates,
we project that a $1 drop in oil price and a $.50 drop in gas price would reduce
our gross revenues in 2008 by approximately $2.7 million and
$9.7 million, respectively.
Adverse changes in the borrowing base
under our revolving credit facility may cause outstanding debt to equal or
exceed the borrowing base
. If the borrowing base under our
revolving credit facility is reduced due to adverse changes in reserve estimates
or commodity prices or otherwise, the outstanding debt under our revolving
credit facility may equal or exceed our borrowing base. In this
event, we will not be able to borrow any additional funds, and we will be
required to repay the excess or convert the debt to a term
note. Without availability under our revolving credit facility, we
may be unable to meet our obligations as they mature.
Delays in bringing successful wells
on production may reduce our liquidity
. As a general rule, we
experience a significant lag time between the initial cash outlay on a prospect
and the inclusion of any value for such prospect in the borrowing base under our
revolving credit facility. Until a well is on production, the lenders
under our revolving credit facility may assign only a minimal borrowing base
value to the well, and cash flows from the well are not available to fund our
operating expense. Delays in bringing wells on production may reduce
the borrowing base significantly, depending on the amounts borrowed and the
length of the delays.
Commitments under long-term drilling
contracts may reduce our cash flow from operating
activities.
We have entered into long-term drilling contracts
to ensure the availability of the drilling rigs we need to conduct our drilling
program. If we contract for a rig and do not need the rig due to
changes in our drilling program, we will be required to pay a daily rate
specified in the contract while the rig is idle during the contract
term. Long-term drilling commitments may also influence us to drill a
well in 2008 that we may otherwise choose to defer until a later period in order
to avoid paying for an idle rig. Our cash flow from operations may be
less than expected and/or our capital expenditures may be more than expected if
commitments on long-term drilling contracts result in the payment of idle rig
costs and/or an increase in drilling costs related to wells not currently
included in our drilling schedule.
Hedging
transactions may limit our potential gains and involve other risks.
From time
to time, we use commodity derivatives, consisting of "swaps," "collars" and
"floors," to attempt to optimize the price we receive for the sale of our oil
and natural gas production. When using swaps to hedge our oil and
natural gas production, we receive a fixed price for the hedged commodity and
pay a floating market price as defined in each contract (generally NYMEX futures
prices), resulting in a net amount due to or from the counterparty at the
settlement date. Collars are a combination of options that provide us
with a put option (fixed floor price) in exchange for a call option (fixed
ceiling price). If the market price for the hedged commodity exceeds
the fixed ceiling price or falls below the fixed floor price, then we receive
the fixed price and pay the market price. If the market price is
between the fixed floor and the fixed ceiling prices, then no payments are due
from either party. In addition, we may purchase put options in which
we pay the counterparty the fair value of the option at the purchase date and
receive from the counterparty the excess, if any, of the fixed floor price over
the floating market price.
We are
also required to comply with anti-market manipulation laws and regulations
enforced by the FERC and the CFTC. In the event of our failure to
comply with such laws and regulations, we could face civil and criminal
penalties and other liabilities.
Information
concerning our reserves and future net revenues estimates is inherently
uncertain.
The
accuracy of proved reserves estimates and estimated future net revenues from
such reserves is a function of the quality of available geological, geophysical,
engineering and economic data and is subject to various assumptions, including
assumptions required by the SEC relating to oil and gas prices, drilling and
operating expenses, and other matters. Although we believe that our
estimated proved reserves represent reserves that we are reasonably certain to
recover, actual future production, oil and gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and gas reserves will most likely vary from the assumptions and estimates used
to determine proved reserves. Any significant variance could
materially affect the estimated quantities and value of our oil and gas
reserves, which in turn could adversely affect our cash flow, results of
operations and the availability of capital resources. In addition, we
may adjust estimates of proved reserves to reflect production history, results
of exploration and development, prevailing oil and gas prices and other factors,
many of which are beyond our control. Downward adjustments to our
estimated proved reserves could require us to
write
down the carrying value of our oil and gas properties, which would reduce our
earnings and our stockholders' equity.
The
present value of proved reserves will not necessarily equal the current fair
market value of our estimated oil and gas reserves. In accordance
with the reserve reporting requirements of the SEC, the estimated discounted
future net cash flows from proved reserves are generally based on prices and
costs as of the date of the estimate. Actual future prices and costs
may be materially higher or lower than those as of the date of the
estimate. The timing of both the production and the expenses with
respect to the development and production of oil and gas properties will affect
the timing of future net cash flows from proved reserves and their present
value.
The
estimated proved reserve information is based upon reserve reports prepared by
independent engineers. From time to time, estimates of our reserves
are also made by the lenders under our revolving credit facility in establishing
the borrowing base under such credit facility and by our engineers for use in
developing business plans and making various decisions. Such
estimates may vary significantly from those of the independent engineers and
have a material effect upon our business decisions and available capital
resources.
Acquisitions
are subject to the risks and uncertainties of evaluating reserves and potential
liabilities and may be disruptive and difficult to integrate into our
business.
Our
on-going business strategy includes growing our reserves and drilling inventory
through acquisitions. Acquired properties can be subject to
significant unknown liabilities. Prior to completing an acquisition, it is
generally not feasible to conduct a detailed review of each individual property
to be acquired in an acquisition. Even a detailed review or
inspection of each property may not reveal all existing or potential liabilities
associated with owning or operating the property. Moreover, some potential
liabilities, such as environmental liabilities related to groundwater
contamination, may not be discovered even when a review or inspection is
performed.
Our
initial reserve estimates for acquired properties may be inaccurate. Downward
adjustments to our estimated proved reserves, including reserves added through
acquisitions, could require us to write down the carrying value of our oil and
gas properties, which would reduce our earnings and our stockholders'
equity.
Our
failure to integrate acquired businesses successfully into our existing business
could result in our incurring unanticipated expenses and losses. In
addition, we may have to assume cleanup or reclamation obligations or other
unanticipated liabilities in connection with these acquisitions. The
scope and cost of these obligations may ultimately be materially greater than
estimated at the time of the acquisition.
The
process of integrating acquired operations into our existing operations may
result in unforeseen operating difficulties and may require significant
management attention and financial resources that would otherwise be available
for the ongoing development or expansion of existing operations.
Drilling
oil and natural gas wells is a high-risk activity and subjects us to a variety
of factors that we cannot control.
Drilling
oil and natural gas wells, including development wells, involves numerous risks,
including the risk that we may not encounter commercially productive oil or
natural gas reservoirs. We may not recover all or any portion of our investment
in new wells. The presence of unanticipated pressures or irregularities in
formations, miscalculations or accidents may cause our drilling activities to be
unsuccessful and result in a total loss of our investment. In addition, we often
are uncertain as to the future cost or timing of drilling, completing and
operating wells. Further, our drilling operations may be curtailed, delayed or
canceled as a result of a variety of factors, including:
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unexpected
drilling conditions;
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pressure
or irregularities in formations;
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equipment
failures or accidents;
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adverse
weather conditions;
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compliance
with environmental and other governmental requirements, which may increase
our costs or restrict our activities;
and
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costs
of, or shortages or delays in the availability of, drilling rigs, tubular
materials and equipment and
services.
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We
may not be insured against all of the operating hazards to which our business is
exposed.
Our
operations are subject to the usual hazards incident to the drilling and
production of oil and gas, such as windstorms, blowouts, cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fires, severe weather and
pollution and other environmental risks. These hazards can cause personal injury
and loss of life, severe damage to and destruction of property and equipment,
pollution or environmental damage, clean-up responsibilities, regulatory
investigation and penalties, and suspension of operation, operations which could
result in substantial loss. We maintain insurance against some, but not all, of
the risks described above. Such insurance may not be adequate to cover losses or
liabilities. Also, we cannot assure you of the continued availability of
insurance at premium levels that justify its purchase.
Our
business depends on oil and natural gas transportation facilities, most of which
are owned by others.
The
marketability of our oil and natural gas production depends in large part on the
availability, proximity and capacity of pipeline systems owned by third parties.
The unavailability of or lack of available capacity on these systems and
facilities could result in the shut-in of producing wells or the delay or
discontinuance of drilling plans for properties. Although we have some
contractual control over the transportation of our product, material changes in
these business relationships could materially affect our operations. Federal and
state regulation of oil and natural gas production and transportation, tax and
energy policies, changes in supply and demand, pipeline pressures, damage to or
destruction of pipelines, maintenance and repair and general economic conditions
could adversely affect our ability to produce, gather and transport oil and
natural gas.
A
shortage of available drilling rigs, equipment and personnel may delay or
restrict our operations.
The oil
and natural gas industry is cyclical and, from time to time, there is a shortage
of drilling rigs, equipment, supplies or personnel. During these periods, the
costs and delivery times of drilling rigs, equipment and supplies are
substantially greater. In addition, demand for, and wage rates of, qualified
drilling rig crews rise with increases in the number of active rigs in service.
Shortages of drilling rigs, equipment, supplies or personnel may increase
drilling costs or delay or restrict our exploration and development operations,
which in turn could impair our financial condition and results of
operations.
Our
industry is highly competitive.
Competition
in all areas of our operations is intense. We experience competition from major
and independent oil and gas companies and oil and gas syndicates in bidding for
desirable oil and gas properties, as well as in acquiring the equipment, data
and labor required to operate and develop such properties. A number of our
competitors have financial resources and acquisition, exploration and
development budgets that are substantially greater than ours, which may
adversely affect our ability to compete with these companies. Competitors may be
able to pay more for productive oil and gas properties and exploratory prospects
and to define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. Our ability to increase
reserves in the future will depend on our success at selecting and acquiring
suitable producing properties and prospects for future development and
exploration activities.
In
addition, the oil and gas industry as a whole competes with other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers. The price and availability of alternative energy sources
could adversely affect our revenue.
The
market for our oil, gas and natural gas liquids production depends on factors
beyond our control, including domestic and foreign political conditions, the
overall level of supply of and demand for oil, gas and natural gas liquids, the
price of imports of oil and gas, weather conditions, the price and availability
of alternative fuels, the proximity and capacity of gas pipelines and other
transportation facilities and overall economic conditions.
Our
success depends on key members of our management and our ability to attract and
retain experienced technical and other professional personnel.
Our
success is highly dependent on our senior management personnel, none of whom are
currently subject to an employment contract. The loss of one or more of these
individuals could have a material adverse effect on our business. Furthermore,
competition for experienced technical and other professional personnel is
intense. If we cannot retain our current personnel or attract additional
experienced personnel, our ability to compete could be adversely
affected.
We
are primarily controlled by Clayton W. Williams, Jr. and his family limited
partnership.
Clayton
W. Williams, Jr. beneficially owns, either individually or through his
affiliates, approximately 20% of the outstanding shares of our common stock. Mr.
Williams is also our Chairman of the Board and Chief Executive
Officer. As a result, Mr. Williams has significant influence over
matters voted on by our shareholders, including the election of our Board
members, and in all other facets of our business, including both our business
strategy and daily operations.
WCPL, a
limited partnership in which Mr. Williams’ adult children are the limited
partners, owns an additional 27% of the outstanding shares of our common
stock. L. Paul Latham, our Executive Vice President and Chief
Operating Officer, is the sole general partner of WCPL and has the power to vote
or direct the voting of the shares held by WCPL. In voting these
shares, Mr. Latham will not be acting in his capacity as an officer and director
of the Company and will consider the interests of WCPL and Mr. Williams’
children. They may have interests that differ from the interests of
our other shareholders.
The
retirement, incapacity or death of Mr. Williams, or any change in the power to
vote shares beneficially owned by Mr. Williams or held by WCPL, could result in
negative market or industry perception and could have a material adverse effect
on our business.
By
extending credit to our customers, we are exposed to potential economic
loss.
We sell
our oil and natural gas production to various customers, serve as operator in
the drilling, completion and operation of oil and gas wells, and enter into
derivatives with various counterparties. As appropriate, we obtain letters of
credit to secure amounts due from our principal oil and gas purchasers and
follow other procedures to monitor credit risk from joint owners and derivatives
counterparties. We cannot assure you that we will not suffer any economic loss
related to credit risks in the future.
Compliance
with laws and regulations governing our activities could be costly and could
negatively impact production.
Our oil
and gas exploration, production and related operations are subject to extensive
rules and regulations promulgated by federal, state and local agencies. Failure
to comply with such rules and regulations can result in substantial penalties.
The regulatory burden on the oil and gas industry increases our cost of doing
business and affects our profitability. Because such rules and regulations are
frequently amended or reinterpreted, we are unable to predict the future cost or
impact of complying with such laws.
All of
the states in which we operate generally require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from oil and gas wells and the
spacing, plugging and abandonment of such wells. The statutes and regulations of
certain states also limit the rate at which oil and gas can be produced from our
properties.
The FERC
regulates interstate natural gas transportation rates and service conditions,
which affect the marketing of gas we produce, as well as the revenues we receive
for sales of such production. Since the mid-1980s, the FERC has issued various
orders that have significantly altered the marketing and transportation of gas.
These orders resulted in a fundamental restructuring of interstate pipeline
sales and transportation services, including the unbundling by interstate
pipelines of the sales, transportation, storage and other components of the
city-gate sales services such pipelines previously performed. These FERC actions
were designed to increase competition within all phases of the gas industry. The
interstate regulatory framework may enhance our ability to market and transport
our
gas,
although it may also subject us to greater competition and to the more
restrictive pipeline imbalance tolerances and greater associated penalties for
violation of such tolerances.
Our sales
of oil and natural gas liquids are not presently regulated and are made at
market prices. The price we receive from the sale of those products
is affected by the cost of transporting the products to market. The FERC has
implemented regulations establishing an indexing system for transportation rates
for oil pipelines, which, generally, would index such rate to inflation, subject
to certain conditions and limitations. We are not able to predict with any
certainty what effect, if any, these regulations will have on us, but, other
factors being equal, the regulations may, over time, tend to increase
transportation costs which may have the effect of reducing wellhead prices for
oil and natural gas liquids.
Our
oil and gas exploration and production, and related activities are subject to
extensive environmental regulations, and to laws that can give rise to
substantial liabilities from environmental contamination.
Our
operations are subject to extensive federal, state and local environmental laws
and regulations, which impose limitations on the discharge of pollutants into
the environment, establish standards for the management, treatment, storage,
transportation and disposal of hazardous materials and of solid and hazardous
wastes, and impose obligations to investigate and remediate contamination in
certain circumstances. Liabilities to investigate or remediate
contamination, as well as other liabilities concerning hazardous materials or
contamination such as claims for personal injury or property damage, may arise
at many locations, including properties in which we have an ownership interest
but no operational control, properties we formerly owned or operated and sites
where our wastes have been treated or disposed of, as well as at properties that
we currently own or operate. Such liabilities may arise even where
the contamination does not result from any noncompliance with applicable
environmental laws. Under a number of environmental laws, such
liabilities may also be joint and several, meaning that we could be held
responsible for more than our share of the liability involved, or even the
entire share. Environmental requirements generally have become more
stringent in recent years, and compliance with those requirements more
expensive.
We have
incurred expenses in connection with environmental compliance, and we anticipate
that we will continue to do so in the future. Failure to comply with
extensive applicable environmental laws and regulations could result in
significant civil or criminal penalties and remediation costs. Some
of our properties, including properties in which we have an ownership interest
but no operating control, may be affected by environmental contamination that
may require investigation or remediation. Some of our operations are
located in environmentally sensitive environments, such as coastal waters,
wetlands and other protected areas. Some of our operations are in
areas particularly susceptible to damage by hurricanes or other destructive
storms, which could result in damage to facilities and discharge of
pollutants. In addition, claims are sometimes made or threatened
against companies engaged in oil and gas exploration and production by owners of
surface estates, adjoining properties or others alleging damage resulting from
environmental contamination and other incidents of operation, and such claims
have been asserted against us as well as companies we have
acquired. Compliance with, and liabilities for remediation under,
these laws and regulations, and liabilities concerning contamination or
hazardous materials, may adversely affect our business, financial condition and
results of operations.