|
Item 1. Business
See pages 78 and 79 for
explanations of abbreviations and terms used herein.
General
Swift Energy Company is engaged in developing, exploring,
acquiring, and operating oil and natural gas properties, with a focus on oil
and natural gas reserves onshore and in the inland waters of Louisiana and
Texas. Swift Energy was founded in 1979 and is headquartered in Houston,
Texas. In December 2007, we agreed to sell the majority of our New Zealand
assets with an expected closing date towards the end of the first quarter of
2008. At year-end 2007, we had estimated proved reserves from our domestic
continuing operations of 133.8 MMBoe with a PV-10 of $3.8 billion, while our
total estimated proved reserves, both domestically and in New Zealand, were
150.1 MMBoe with a PV-10 Value of $3.9 billion (PV-10 is a non-GAAP measure,
see the section titled "Oil and Natural Gas Reserves" in our Property
section for a reconciliation of this non-GAAP measure to the closest GAAP
measure, the standardized measure). Our total proved reserves at year-end
2007 were comprised of approximately 43% crude oil, 44% natural gas, and 13%
NGLs; and 45% of our total proved reserves were proved developed. Our proved
reserves are concentrated with 59% of the total in Louisiana, 29% in Texas,
1% in other states, and 11% in New Zealand.
We currently focus primarily on development and
exploration of fields in three domestic regions:
• South Louisiana Region
Bay de Chene Area
Bayou Penchant Area
Bayou Sale Area
Cote Blanche Island Area
High Island Area
Horseshoe Bayou Area
Jeanerette Area
Lake Washington Area
• South Texas Region
AWP Olmos Area
Cotulla Area
• Toledo Bend Region
Brookeland Area
Masters Creek Area
South Bearhead Creek Area
Competitive Strengths and Business Strategy
Our competitive strengths, together with a balanced and
comprehensive business strategy, provide us with the flexibility and
capability to achieve our goals. Our primary strengths and strategies are
set forth below.
Demonstrated Ability to Grow Reserves and Production
We have grown our domestic proved reserves from 99.0
MMBoe to 133.8 MMBoe over the five-year period ended December 31, 2007. Over
the same period, our annual domestic production has grown from 5.7 MMBoe to
10.6 MMBoe. Our growth in reserves and production over this five-year period
has resulted primarily from drilling activities and acquisitions in our
three core domestic regions. During 2007, our domestic proved reserves
increased by 13%, due to acquisitions of properties in our South Texas
region and our 2007 drilling results. Based on our long-term historical
performance and our business strategy going forward, we believe that we have
the opportunities, experience, and knowledge to grow both our reserves and
production.
Balanced Approach to Growth
Our strategy is to increase our reserves and production
through both drilling and acquisitions, shifting the balance between the two
activities in response to market conditions and strategic opportunities. In
general, we focus on drilling in our anchor assets in each of our three
domestic regions when oil and natural gas prices are strong. When prices
weaken and the per unit cost of acquisitions becomes more attractive, or a
strategic opportunity exists, we also focus on acquisitions. We believe this
balanced approach has resulted in our ability to grow in a strategically
cost effective manner, and in 2007 we replaced 245% of our domestic 2007
production and over the last five years we have replaced 187% of our
domestic production.
For 2008, we are targeting total production from
continuing operations to increase 10% to 15% and proved reserves from
continuing operations to increase 5% to 9% over 2007 levels.
Our 2008 capital expenditures are currently budgeted at
$425 million to $475 million, net of minor non-core dispositions and
excluding any property acquisitions.
Replacement of Reserves
Historically we have added proved reserves through both
our drilling and acquisition activities. We believe that this strategy will
continue to add reserves for us over the long-term; however, external
factors beyond our control, such as adverse weather conditions, commodity
market factors, and governmental regulations, could limit our ability to
drill wells and acquire proved properties in the future. We have included
below a listing of the vintages of our proved undeveloped reserves in the
table titled "Proved Undeveloped Reserves" and believe this table will
provide an understanding of the time horizon required to convert proved
undeveloped reserves to oil and natural gas production. Our reserves
additions for each year are estimates. Reserves volumes can change over time
and therefore cannot be absolutely known or verified until all volumes have
been produced and a cumulative production total for a well or field can be
calculated. Many factors will impact our ability to access these reserves,
such as availability of capital, commodity prices, new and existing
government regulations, adverse weather conditions, competition within our
industry, the requirement of new or upgraded infrastructure at the
production site, and technological advances.
Concentrated Focus on Regions with Operational Control
The concentration of our operations in three domestic
regions allows us to leverage our drilling unit and workforce synergies
while minimizing the continued escalation of drilling and completion costs.
Our average lease operating costs for continuing operations, excluding
taxes, were $6.68, $5.29, and $4.87 per Boe in 2007, 2006, and 2005,
respectively. Each of our three regions includes at least one anchor asset,
previously termed a core area, and several diversity properties that are
targeted for future growth. This concentration allows us to utilize the
experience and knowledge we gain in these areas to continually improve our
operations and guide us in developing our future activities and in operating
similar type assets. The value of this concentration is enhanced by our
operational control of 96% of our proved oil and natural gas reserves base
as of December 31, 2007. Retaining operational control allows us to more
effectively manage production, control operating costs, allocate capital,
and time field development.
Develop Under-Exploited Properties
We are focused on applying advanced technologies and
recovery methods to areas with known hydrocarbon resources to optimize our
exploration and exploitation of such properties as illustrated in our three
domestic regions. For instance, the Lake Washington field was discovered in
the 1930s. We acquired our properties in this area for $30.5 million in
2001. Since that time, we have increased our average daily net production
from less than 700 Boe to 15,900 Boe for the quarter ended December 31,
2007. We have also increased our proved reserves in the area from 7.7
million Boe to approximately 36.4 million Boe as of December 31, 2007. When
we first acquired our interests in AWP Olmos, Brookeland, and Masters Creek,
these areas also had significant additional development potential. In
December 2004, we acquired our Bay de Chene and Cote Blanche Island fields,
which hold mainly proved undeveloped reserves, and we began our initial
development activities of these properties in 2006. In November 2005, we
acquired our South Bearhead Creek field and then in October 2006, we
acquired interests in five fields in South Louisiana which have significant
development potential. In October 2007, we acquired interests in three South
Texas properties in the Maverick Basin that total approximately 82,000
acres. These properties are located in the Sun TSH area in La Salle County,
the Briscoe Ranch area primarily in Dimmitt County, and the Las Tiendas area
in Webb County. We intend to continue acquiring large acreage positions
where we can grow production by applying advanced technologies and recovery
methods using our experience and knowledge developed in our three domestic
regions.
Maintain Financial Flexibility and Disciplined Capital
Structure
We practice a disciplined approach to financial
management and have historically maintained a disciplined capital structure
to provide us with the ability to execute our business plan. As of December
31, 2007, our debt to capitalization was approximately 41%, while our debt
to domestic proved reserves ratio was $4.39 per Boe, and our debt to
domestic PV-10 ratio was 15%. We plan to maintain a capital structure that
provides financial flexibility through the prudent use of capital, aligning
our capital expenditures to our cash flows, and maintaining a strategic
hedging program. The combination of hedging with collars, floors, and
forward sales will provide for a more stable cash flow for the periods
covered as described in the "Commodity Risk" section of this report.
Experienced Technical Team and Technology Utilization
We employ 61 oil and gas professionals, including
geophysicists, petrophysicists, geologists, petroleum engineers, and
production and reservoir engineers, who have an average of approximately 24
years of experience in their technical fields and have been employed by us
for an average of over five years. In addition, we engage experienced and
qualified consultants to perform various comprehensive seismic acquisitions,
processing, reprocessing, interpretation, and other related services. We
continually apply our extensive in-house experience and current technologies
to benefit our drilling and production operations.
We increasingly use seismic technology to enhance the
results of our drilling and production efforts, including two- and
three-dimensional seismic acquisition, pre-stack image enhancement
reprocessing, amplitude versus offset datasets, coherency cubes, and
detailed field reservoir depletion planning. In 2004, we completed our 3-D
seismic survey covering our Lake Washington area. In 2007 we utilized this
seismic data to drill all of our exploratory and development wells. In 2005,
we began a seismic program that encompasses 77 square miles in our Cote
Blanche Island area, which was completed in 2006, and have used this data to
drill new wells in that area. We now have seismic data covering over 4,000
square miles in South Louisiana that has been merged into two data sets,
inclusive of data covering five fields we acquired in 2006 that will form
the base dataset for our regional exploration and development program. This
data will be analyzed over the next several years, feeding our acquisition
and organic growth led strategies.
We use various recovery techniques, including gas lift,
water flooding, pressure maintenance, and acid treatments to enhance crude
oil and natural gas production. We also fracture reservoir rock through the
injection of high-pressure fluid, install gravel packs, and insert
coiled-tubing velocity strings to enhance and maintain production. We
believe that the application of fracturing and coiled-tubing technology has
resulted in significant increases in production and decreases in completion
and operating costs, particularly in our AWP Olmos area.
We also employ measurement-while-drilling techniques
extensively in our South Louisiana region, which allows us to guide the
drill bit during the drilling process. This technology allows the well bore
path to be steered parallel to the salt face and to intersect multiple
targeted sands in a single well bore.
Item 2. Properties
Domestic Operating Areas (Continuing Operations)
The following table sets forth information regarding our
2007 year-end proved reserves from continuing operations of 133.8 MMBoe and
production of 10.6 MMBoe by area:
|
Area
|
Developed
(MMBoe)
|
|
Undeveloped
(MMBoe)
|
|
Total
(MMBoe)
|
|
%
of Domestic Reserves
|
|
%
of Domestic Production
|
|
%
Oil and NGLs
|
|
Lake
Washington
|
18.5
|
|
17.9
|
|
36.4
|
|
27.2%
|
|
62.0%
|
|
92.1%
|
|
Bay
de Chene
|
2.3
|
|
2.4
|
|
4.7
|
|
3.5%
|
|
5.7%
|
|
39.9%
|
|
Other
South Louisiana
|
7.3
|
|
25.2
|
|
32.5
|
|
24.3%
|
|
9.1%
|
|
40.1%
|
|
Total
South Louisiana
|
28.1
|
|
45.5
|
|
73.6
|
|
55.0%
|
|
76.8%
|
|
65.8%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AWP
|
16.3
|
|
6.1
|
|
22.4
|
|
16.8%
|
|
10.7%
|
|
29.1%
|
|
Cotulla
|
9.5
|
|
6.9
|
|
16.4
|
|
12.2%
|
|
2.8%
|
|
51.5%
|
|
Other
South Texas
|
0.3
|
|
0.1
|
|
0.4
|
|
0.3%
|
|
0.8%
|
|
5.8%
|
|
Total
South Texas
|
26.1
|
|
13.1
|
|
39.2
|
|
29.3%
|
|
14.3%
|
|
38.2%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Austin
Chalk
|
4.7
|
|
7.9
|
|
12.6
|
|
9.4%
|
|
4.9%
|
|
64.3%
|
|
South
Bearhead Creek
|
4.1
|
|
2.7
|
|
6.8
|
|
5.1%
|
|
3.3%
|
|
67.5%
|
|
Total
Toledo Bend
|
8.8
|
|
10.6
|
|
19.4
|
|
14.5%
|
|
8.2%
|
|
65.4%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
63.0
|
|
69.2
|
|
132.2
|
|
98.8%
|
|
99.2%
|
|
57.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Louisiana
|
34.6
|
|
53.5
|
|
88.1
|
|
65.9%
|
|
82.1%
|
|
66.2%
|
|
Total
Texas
|
28.4
|
|
15.7
|
|
44.1
|
|
32.9%
|
|
17.1%
|
|
40.2%
|
Domestic Regional Focus Areas
Our domestic regions consist of three main regions
located in South Louisiana, South Texas and Toledo Bend, which straddles the
Texas and Louisiana border. South Texas is the oldest of our core regions,
with our operations being established in the AWP Olmos area in 1989 and the
acquisition of the Sun TSH, Briscoe Ranch, and Las Tiendas fields during
2007, which comprise our Cotulla area. In mid-1998, we acquired the Masters
Creek and Brookeland areas in the Toledo Bend region, with South Bearhead
Creek being our most recent acquisition in this region during late 2005. In
South Louisiana, we established our operations when we acquired majority
interests in producing properties in the Lake Washington field in early
2001, adding Bay de Chene and Cote Blanche Island in December 2004, and
adding five fields in 2006: Bayou Sale, Bayou Penchant, High Island,
Horseshoe Bayou, and Jeanerette.
South Louisiana
Lake Washington Area. As of December 31, 2007, we owned
drilling and production rights in 32,075 net acres in the Lake Washington
area located in Plaquemines Parish in South Louisiana. Approximately 92% of
our proved reserves of 36.4 MMBoe in this area at December 31, 2007, were
oil and NGLs. To date, we have primarily produced from multiple Miocene
sands ranging in depth from greater than 2,000 feet to 13,000 feet. The
field is located on a salt dome and has produced over 300 million Boe since
its discovery in the 1930s. The area around the dome is heavily faulted,
thereby creating a large number of potential traps. Oil and natural gas from
approximately 141 producing wells and 35 shut-in wells is gathered to three
platforms located in water depths from two to 12 feet, with drilling and
workover operations performed with rigs on barges.
In 2007, we drilled 22 development wells, of which 18
wells were completed. At year-end 2007, we had 113 proved undeveloped
locations in this field. Our planned 2008 capital expenditures in this area
will focus on drilling from 23 to 27 wells, along with the construction of a
facility on the west side of the field, which is expected to be commissioned
in the first half of 2008, to further improve the deliverability and
efficiency in this area.
Bay de Chene Area. Bay de Chene is located in
Jefferson Parish and Lafourche Parish in South Louisiana in close proximity
to Lake Washington. As of December 31, 2007, we owned drilling and
production rights in 18,546 net acres in Bay de Chene, and successfully
drilled two development wells in this field. At year-end 2007, we had seven
proved undeveloped locations in the Bay de Chene field. During 2008, we plan
to drill up to five wells in Bay de Chene. Production in the Bay de Chene
area is currently constrained by the market capacity, and alternative
outlets are being pursued by the Company.
Other South Louisiana Areas. Cote Blanche Island
is in St. Mary Parish which is in South Louisiana. This field holds
predominately undeveloped reserves. As of December 31, 2007, we owned
drilling and production rights in 15,498 net acres in the Cote Blanche
Island field, along with options covering another 8,817 acres. At year-end
2007, we had 25 proved undeveloped locations in the Cote Blanche Island
field. During 2008, we plan to drill up to two wells in this area along with
processing the 3-D seismic data covering this area that was shot in 2006. In
October 2006, we acquired interests in five fields located in five primarily
onshore South Louisiana fields: Bayou Sale, Horseshoe Bayou and Jeanerette
fields (all located in St. Mary Parish), High Island Field in Cameron Parish
and Bayou Penchant Field in Terrebonne Parish. Bayou Sale and Horseshoe
Bayou fields are adjacent to each other and located 13 miles southeast of
our Cote Blanche Island field. Production in these fields is from formations
at depths ranging from 10,000 to 14,000 feet. The Bayou Penchant field was
discovered in the 1930s and produces from a number of Middle Miocene sands
at depths of 7,000 to 10,000 feet. Bayou Penchant is located approximately
44 miles southeast of Cote Blanche Island and is a non-operated field with
Swift holding an average 50% working interest. The High Island field is
located 65 miles west of Cote Blanche Island and was discovered in 1983. The
Jeanerette field is positioned on the flank of a large salt dome and
approximately 12 miles north of Cote Blanche Island. Jeanerette Field
produces from the Planulina sands in the 10,000 feet to 15,000 feet depth
range. We plan to initiate an exploration and development program in 2008 to
drill proved undeveloped and probable locations, recomplete several wells,
enhance facilities and improve per unit operating costs in these five
fields. During 2008, we plan to drill up to five wells in these areas.
In 2007, we successfully drilled one well in the Bayou
Sale field.
South Texas
AWP Olmos Area. As of December 31, 2007, we owned
drilling and production rights in 29,107 net acres in the AWP Olmos Area in
South Texas. We have extensive experience with low-permeability, tight-sand
formations typical of this area, having acquired our first acreage there in
1988. These reserves are approximately 71% natural gas. At year-end 2007, we
owned interests in and operated 536 wells in this area producing oil and
natural gas from the Olmos sand formation at depths of approximately 9,000
to 11,500 feet. We own nearly 100% of the working interests in all these
operated wells.
In 2007, we completed 21 development wells in this area
and performed 16 fracture enhancements. At year-end 2007, we had 98 proved
undeveloped locations. Our planned 2008 capital expenditures will focus on
drilling 10 to 15 wells in this area.
Cotulla Area. In October 2007, we acquired
interests in three South Texas properties in the Maverick Basin. These
properties are located in the Sun TSH area in La Salle County, the Briscoe
Ranch area primarily in Dimmitt County, and the Las Tiendas area in Webb
County.
As of December 31, 2007, we owned drilling and production
rights in 81,986 net acres in the Cotulla area, owned interests in and
operated 205 wells, and had 89 proved undeveloped locations. In 2007, we
drilled seven development wells in this area, of which six were completed.
Our planned 2008 capital expenditures will focus on drilling 30 to 36 wells
in this area.
Toledo Bend
Brookeland Area. As of December 31, 2007, we owned
drilling and production rights in 79,308 net acres and 3,500 fee mineral
acres in the Brookeland area. This area is located in East Texas near the
border of Louisiana in Jasper and Newton counties. We primarily drill
horizontal wells and produce from the Austin Chalk formation in this area.
The reserves are approximately 57% oil and natural gas liquids. At year-end
2007, we had ten proved undeveloped locations.
Masters Creek Area. As of December 31, 2007, we
owned drilling and production rights in 40,509 net acres and 91,534 fee
mineral acres in the Masters Creek area. This area is located in Central
Louisiana near the Texas-Louisiana border in the two parishes of Vernon and
Rapides. It contains horizontal wells producing both oil and natural gas
from the Austin Chalk formation. The reserves are approximately 69% oil and
NGLs. At year-end 2007, we had nine proved undeveloped locations. We plan on
drilling one to two wells in the Austin chalk area in 2008.
South Bearhead Creek Area. In November and
December 2005, and then in December 2006, we acquired interests in the South
Bearhead Creek field, which is located in the Toledo Bend region
approximately 50 miles south of our Masters Creek field and 30 miles north
of Lake Charles, Louisiana. Oil and natural gas are produced in this area
predominantly from the upper and lower Wilcox sands at depths ranging from
approximately 10,600 to 14,100 feet. The field also has production in the
Cockfield sands at approximately 8,000 to 8,500 feet. South Bearhead Creek
field was discovered in 1958 by a major oil company. It is a large east-west
trending anticlinal closure and has had cumulative production of over 4
million Boe.
In 2007, we drilled 11 development wells in the area, all
of which were successful. As of December 31, 2007, we owned drilling and
production rights in 7,176 net acres in the South Bearhead Creek area. At
year-end 2007, we had 18 proved undeveloped locations in this field. Our
2008 plans for this area include drilling up to four wells.
Domestic Dispositions. In April 2006, we sold our
minority interest in the natural gas processing plant and related
infrastructure that serves the Brookeland and the Masters Creek areas within
our Toledo Bend region. In December 2006, we sold our interest in wells in
the Garcia Ranch area within the South Texas region.
New Zealand Areas (Discontinued Operations)
In December 2007, Swift agreed to sell substantially all
of our New Zealand assets for approximately $87.8 million. Accordingly, the
New Zealand operations have been classified as discontinued operations in
the consolidated statements of income and cash flows and the assets and
associated liabilities have been classified as held for sale in the
consolidated balance sheets. We began a strategic review of our New Zealand
assets in the second quarter of 2007 which culminated in the agreement to
sell the majority of these assets in the fourth quarter of 2007, with an
expected closing towards the end of the first quarter of 2008. The remaining
assets are expected to be sold in the later part of 2008. Proceeds from the
New Zealand assets sale will most likely be used to pay down a portion of
our credit facility.
Oil and Natural Gas Reserves
The
following tables present
information regarding proved
reserves of oil and natural
gas attributable to our
interests in producing
properties both domestically
and in New Zealand as of
December 31, 2007, 2006, and
2005. The information set
forth in the tables
regarding reserves is based
on proved reserves reports
prepared by us. H.J. Gruy
and Associates, Inc.,
Houston, Texas, independent
petroleum engineers, has
audited 100% of our domestic
proved reserves in each of
the last three years and
100% of our New Zealand
proved reserves for 2006 and
2005. The audit by H.J. Gruy
and Associates, Inc. was
conducted according to the
Standards Pertaining to
the Estimating and Auditing
of Oil and Gas Reserve
Information approved by
the Board of Directors of
the Society of Petroleum
Engineers, Inc. Based on its
investigations, it is the
judgment of H.J. Gruy and
Associates, Inc. that Swift
used appropriate
engineering, geologic, and
evaluation principles and
methods that are consistent
with practices generally
accepted in the petroleum
industry. Reserves estimates
are based on extrapolation
of established performance
trends, material balance
calculations, volumetric
calculations, analogy with
the performance of
comparable wells, or a
combination of these
methods. The classification
and definitions of all
proved reserves estimates
are in accordance with Rule
4-10 of Regulation S-X and
the auditing process as
described in the Society of
Petroleum Engineers document
Standards Pertaining to
the Estimating and Auditing
of Oil and Gas Reserves
Information.
A
reserves audit and a
financial audit are separate
activities with unique and
different processes and
results. These two
activities should not be
confused. As currently
defined by the Society of
Petroleum Engineers, a
reserves audit should be of
sufficient rigor to
determine the appropriate
reserve classification for
all reserves in the property
set evaluated and to clearly
state the reserves
classification system being
utilized. A financial audit
includes examining, on a
test basis, evidence
supporting the amounts and
disclosures in the financial
statements. A financial
audit also includes
assessing the accounting
principles used and
significant estimates made
by management, as well as
evaluating the overall
financial statement
presentation.
Estimates
of future net revenues from
our proved reserves and
their PV-10 Value are made
using oil and natural gas
sales prices in effect as of
the dates of such estimates
excluding the effects of
hedging and are held
constant, for that year’s
reserves calculation,
throughout the life of the
properties, except where
such guidelines permit
alternate treatment,
including, in the case of
natural gas contracts, the
use of fixed and
determinable contractual
price escalations. We have
interests in certain tracts
that are estimated to have
additional hydrocarbon
reserves that cannot be
classified as proved and are
not reflected in the
following tables. Our hedges
at year-end 2007 consisted
of oil and natural gas price
floors with strike prices
lower than the period-end
price and did not affect
prices used in these
calculations. The weighted
averages of such year-end
2007 prices domestically
were $6.65 per Mcf of
natural gas, $93.24 per
barrel of oil, and $56.28
per barrel of NGL, compared
to $5.84, $60.07, and $31.54
at year-end 2006 and $10.36,
$60.00, and $33.28 at
year-end 2005, respectively.
The weighted averages of
such year-end 2007 prices
for New Zealand were $3.08
per Mcf of natural gas,
$93.20 per barrel of oil,
and $36.98 per barrel of NGL,
compared to $3.59, $63.51,
and $26.84 in 2006 and
$3.79, $60.98, and $19.20 in
2005, respectively. The
weighted averages of such
year-end 2007 prices for all
our reserves, both
domestically and in New
Zealand, were $6.19 per Mcf
of natural gas, $93.24 per
barrel of oil, and $54.63
per barrel of NGL, compared
to $5.46, $60.41, and $30.93
in 2006 and $8.94, $60.12,
and $31.40 in 2005,
respectively.
The
following tables set forth
estimates of future net
revenues presented on the
basis of unescalated prices
and costs in accordance with
criteria prescribed by the
SEC and their PV-10 Value as
of December 31, 2007, 2006,
and 2005. Operating costs,
development costs, asset
retirement obligation costs,
and certain
production-related taxes
were deducted in arriving at
the estimated future net
revenues. No provision was
made for income taxes. The
estimates of future net
revenues and their present
value differ in this respect
from the standardized
measure of discounted future
net cash flows set forth in
supplemental information to
our consolidated financial
statements, which is
calculated after provision
for future income taxes. We
combine NGL volumes with oil
volumes solely for reserves
volumes reporting purposes.
We apply oil prices to
proved oil reserves volumes
and apply NGL prices to
proved NGL reserves volumes
in determining both the
PV-10 and standardized
measure values. PV-10 is a
non-GAAP measure; see the
reconciliation of this non-GAAP
measure to the closest GAAP
measure, the standardized
measure, in the section
below this table.
|
|
|
As
of December 31, 2007
|
|
|
|
|
Total
|
|
|
Domestic
|
|
|
Discontinued
Operations
|
|
|
Estimated
Proved Oil and Natural Gas Reserves
|
|
|
|
|
|
|
|
|
|
|
Natural
gas reserves (MMcf):
|
|
|
|
|
|
|
|
|
|
|
Proved
developed
|
|
|
187,152 |
|
|
|
172,974 |
|
|
|
14,178 |
|
|
Proved
undeveloped
|
|
|
206,862 |
|
|
|
170,824 |
|
|
|
36,038 |
|
|
Total
|
|
|
394,014 |
|
|
|
343,798 |
|
|
|
50,216 |
|
|
Oil
reserves (MBbl):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
developed
|
|
|
36,753 |
|
|
|
35,548 |
|
|
|
1,205 |
|
|
Proved
undeveloped
|
|
|
47,702 |
|
|
|
40,934 |
|
|
|
6,768 |
|
|
Total
|
|
|
84,455 |
|
|
|
76,482 |
|
|
|
7,973 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Estimated Reserves (MBoe)
|
|
|
150,124 |
|
|
|
133,781 |
|
|
|
16,343 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Discounted Present Value of Proved Reserves (In millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
developed
|
|
$ |
2,071 |
|
|
$ |
1,999 |
|
|
$ |
73 |
|
|
Proved
undeveloped
|
|
|
1,823 |
|
|
|
1,790 |
|
|
|
32 |
|
|
PV-10
Value
|
|
$ |
3,894 |
|
|
$ |
3,789 |
|
|
$ |
105 |
|
|
|
|
As
of December 31, 2006
|
|
|
|
|
Total
|
|
|
Domestic
|
|
|
Discontinued
Operations
|
|
|
Estimated
Proved Oil and Natural Gas Reserves
|
|
|
|
|
|
|
|
|
|
|
Natural
gas reserves (MMcf):
|
|
|
|
|
|
|
|
|
|
|
Proved
developed
|
|
|
151,276 |
|
|
|
133,815 |
|
|
|
17,462 |
|
|
Proved
undeveloped
|
|
|
172,855 |
|
|
|
135,846 |
|
|
|
37,009 |
|
|
Total
|
|
|
324,131 |
|
|
|
269,661 |
|
|
|
54,471 |
| |