Penn Virginia Corporation Announces Record Proved Reserves and Provides Operational Update
23.02.2011 | Business Wire
Highlights 2010 Proved Reserves and Capital Expenditures Equivalent Reserves (Bcfe) Natural Gas Reserves (Bcf) Condensate Reserves (MMBbls) 2010 reserve replacement ratio(2) 2010 reserve replacement cost ($ per Mcfe)(2) Standardized measure of discounted future net cash flows ($mil.)(1) Present value of future net cash flows before income taxes (1) (2) Production Three Months Ended Year Ended Region 2010 2009 2010 2010 2009 Note - Numbers may not add due to Capital Expenditures Operational Update Eagle Ford Shale ? In a separate news Mid-Continent ? We currently have two Marcellus Shale ? Our first horizontal Cotton Valley ? During the fourth quarter Selma Chalk ? During the fourth quarter of Explanation of Non-GAAP PV-10 Value Fourth Quarter and Full-Year 2010 Financial and Operational Results Penn Virginia Corporation (NYSE: PVA) is an independent natural gas For more information, please visit our website at www.pennvirginia.com.
Penn Virginia Corporation (NYSE: PVA) today announced record levels of
proved oil and gas reserves and pro forma production and provided an
update of its oil and gas operations, including full-year and fourth
quarter 2010 results.
Operational results for the year ended December 31, 2010 included the
following:
Record year-end proved oil and gas reserves of 942 billion cubic feet
of natural gas equivalent (Bcfe) as compared to 935 Bcfe at year-end
2009 (911 Bcfe, pro forma to exclude 24.0 Bcfe of Gulf Coast reserves
sold in January 2010);
Proved developed reserves increased to 53 percent from 46 percent;
Proved oil and natural gas liquid (NGL) reserves increased to 21
percent from 17 percent; and
PV-10 value (pre-tax present value of proved reserves, discounted at
10 percent, a non-GAAP measure) increased 28 percent to $878 million
from $688 million.
Operational results for the fourth quarter of 2010 included the
following:
Production of 13.1 Bcfe, or 142.5 million cubic feet of natural gas
equivalent (MMcfe) per day, a 27 percent increase as compared to 10.3
Bcfe, or 111.8 MMcfe per day, pro forma to exclude 1.0 Bcfe of
production from Gulf Coast assets sold in January 2010; and
Oil and NGL production increased to 21 percent of quarterly production
from 16 percent in the fourth quarter of 2009.
Proved reserves increased to 942 Bcfe at year-end 2010 from 935 Bcfe at
year-2009 (911 Bcfe, pro forma to exclude 24.0 Bcfe of Gulf Coast
reserves sold in January 2010). As compared to year-end 2009, proved
developed reserves increased to 53 percent from 46 percent, while proved
oil and NGL reserves increased to 21 percent from 17 percent. Excluding
45 Bcfe of negative revisions for proved undeveloped reserves associated
with locations that now are not anticipated to be drilled within a
five-year time period, in accordance with Securities and Exchange (SEC)
regulations, we replaced approximately 260 percent of our 2010
production by adding 122 Bcfe of proved reserves from extensions,
discoveries, additions and purchases of reserves, net of other
revisions. On a pro forma basis, over the previous five years, we grew
our reserve base at a compound annual growth rate of 23 percent.
The proved reserve increases were primarily attributable to our core
assets in the Haynesville Shale, Selma Chalk, horizontal Cotton Valley
and Granite Wash, with decreases in Appalachia and other, smaller
Mid-Continent fields. We did not report any proved reserves for the
Eagle Ford or Marcellus Shales at year-end 2010 since we are drilling
our first horizontal wells in these plays during 2011. The five-year
rule revisions resulted in the reclassification of approximately 37 Bcfe
of vertical Cotton Valley reserves and approximately eight Bcfe of
Appalachian reserves from proved undeveloped reserves to probable
reserves. The majority of Cotton Valley proved undeveloped reserves
remaining now consists of horizontal locations.
The year-over-year increase in SEC-assumed commodity prices, as well as
increases in the liquids percentage and the proved developed percentage,
contributed to a nearly 28 percent increase in the PV-10 value (present
value of proved reserves, discounted at 10 percent), which totaled $878
million at year-end 2010.
During 2010, capital expenditures were $450 million, or $5.77 per Mcfe
of proved reserves added. Excluding five-year rule revisions, the
reserve replacement cost was $3.67 per Mcfe. Capital expenditures,
excluding unproved and proved leasehold acquisition costs of $139
million, were $311 million, or $4.17 per Mcfe of proved reserves added,
excluding purchased reserves. Excluding five-year rule revisions and
leasehold acquisition costs, reserve replacement costs were $2.61 per
Mcfe of proved reserves added, excluding purchased reserves.
Proved Reserves at December 31, 2010(1)
(in Bcfe)
Natural Gas
Oil and
Proved reserves at December 31, 2009
935.0
776.7
26.4
2010 production
(47.2
)
(38.9
)
(1.4
)
2010 extensions, discoveries and other additions
114.9
90.4
4.1
2010 revisions ? price
11.6
9.7
0.3
2010 revisions ? SEC five-year rule
(44.5
)
(43.3
)
(0.2
)
2010 revisions ? other
(7.3
)
(37.9
)
5.1
2010 purchases (sales) of reserves in place, net
(20.7
)
(11.8
)
(1.5
)
Proved reserves at December 31, 2010 941.8
745.0
32.8
Percentage of equivalent reserves
100.0
%
79.1
%
20.9
%
Proved developed reserves at December 31, 2010
501.5
412.6
14.8
Percentage of proved reserves
53.3
%
55.4
%
45.2
%
Including all revisions
165.2
%
Excluding five-year rule revisions
259.5
%
2010 oil and gas capital expenditures ($mil.)
All costs
$449.8
Excluding proved and unproved leasehold acquisition costs
$311.0
Including all costs and all revisions
$5.77
Excluding five-year rule revisions
$3.67
Excluding proved and unproved leasehold acquisition costs and
purchased
reserves
$4.17
Excluding proved and unproved leasehold acquisition costs,
purchased
reserves and five-year rule revisions
$2.61
$641.4
($mil.)(1)
$878.1
The estimated reserves, standardized measure and present value
were based on pricing assumptions for Henry Hub natural gas of
$4.38 per million British thermal units (MMBtu) and West Texas
Intermediate crude oil of $79.43 per barrel. These compare to
prices of $3.87 per MMBtu and $61.18 per barrel, respectively, at
December 31, 2009. Both prices exclude the effects of hedged
production and six Mcfe is assumed to equal one barrel equivalent
of liquids. MMBbls is defined as one million barrels.
Reserve replacement ratio is defined as the sum of reserve
additions (reserve extensions, discoveries and other additions
plus revisions plus reserve purchases) divided by production for
the year. Reserve replacement cost per Mcfe is defined as capital
expenditures divided by reserve additions.
During 2010, oil and gas production was 46.9 Bcfe, pro forma to exclude
Gulf Coast reserves sold in January 2010, as compared to pro forma
production of 45.2 Bcfe in 2009. Including Gulf Coast production prior
to its divestiture, full-year 2010 production was 47.2 Bcfe.
As shown in the table below, production in the fourth quarter of 2010
was 13.1 Bcfe, or 142.5 MMcfe per day, up 16 percent as compared to 11.3
Bcfe, or 123.1 MMcfe per day, in the fourth quarter of 2009 and down
slightly from the 13.3 Bcfe, or 144.3 MMcfe per day, in the third
quarter of 2010. Adjusted for the divestiture of our Gulf Coast assets,
production in the fourth quarter of 2010 was 27 percent higher than the
pro forma 10.3 Bcfe, or 111.8 MMcfe per day, in the fourth quarter of
2009.
Production for the
Production for the
Dec. 31,
Dec. 31,
Sept. 30,
Dec. 31,
Dec. 31,
(in Bcfe)
(in Bcfe)
Mid-Continent
4.2
3.1
4.5
15.3
12.8
East Texas
4.3
2.7
4.0
13.5
13.1
Mississippi
2.1
1.7
2.1
7.6
7.8
Appalachia
2.5
2.7
2.7
10.4
11.5
Gulf Coast (1)
---
1.0
---
0.3
5.8
Totals 13.1
11.3
13.3 47.2
51.0 Pro Forma Totals(2) 13.1
10.3
13.3 46.9
45.2 (1) We sold our Gulf Coast assets in January 2010.
(2) Pro forma to exclude divested Gulf Coast assets.
rounding.
The year-over-year increase in pro forma production was due to increased
drilling and completion activity in the Granite Wash, Haynesville Shale,
horizontal Cotton Valley and Selma Chalk plays. Production in the fourth
quarter of 2010 was in the upper half of the previously announced
guidance range of 12.4 to 13.4 Bcfe, but down slightly from third
quarter 2010 volumes, due primarily to production declines and the
previously announced shift of drilling rigs to the Eagle Ford and
Marcellus Shales from the Cotton Valley and Selma Chalk.
During the fourth quarter, oil and gas capital expenditures were
approximately $108 million, as compared to $147 million in the third
quarter of 2010, and consisted of:
$86 million for drilling and completion activities;
$20 million for leasehold acquisition, field projects and other; and
$2 million for seismic, pipeline, gathering and facilities.
release dated February 23, 2011, we announced our initial drilling
success and the acquisition of additional acreage in the Eagle Ford
Shale, as well as a plan to accelerate drilling in this play during 2011.
operated rigs drilling in Oklahoma, along with two non-operated rigs
drilling on acreage in the South Clinton Field. Due to the promising
early production results from our first well in the Eagle Ford Shale,
along with what we expect will be higher returns as compared to our
remaining operated undeveloped locations in the Granite Wash, one of the
two operated rigs in the Mid-Continent will be moved to the Eagle Ford
Shale late in the second quarter.
During the fourth quarter of 2010, 11 (5.0 net) Granite Wash development
and exploratory wells were drilled, ten (4.5 net) of which were
successful and one (0.5 net) of which is under evaluation. Since October
2010, 10 (3.9 net) Granite Wash development wells have been completed in
the South Clinton Field with initial production (IP) rates ranging
between 5.2 and 14.9 MMcfe per day (9.0 MMcfe per day average; oil
comprised approximately 45 percent of the wellhead volumes), excluding
processed NGLs which typically add an additional 20 to 25 percent to
equivalent production volumes.
After completion, the results of exploratory wells drilled in our Powell
prospect during both the third and fourth quarters have been either
marginal or unsuccessful due to high formation water production, most
likely as the result of frac extension into water saturated intervals
within the overall Granite Wash formation. In addition, the completion
results from the East Sayre prospect did not meet our expectations. For
this reason, primarily all drilling in 2011 in the Granite Wash will be
focused in South Clinton Field, where we expect to drill 23 (7.1 net)
development wells, the majority of which will be outside-operated. Other
Mid-Continent drilling planned in 2011 is associated with an exploration
program of six (4.0 net) wells in new internally-generated prospects in
various horizontal unconventional and resource play types.
Marcellus Shale well (Risser #A-1H) has been drilled and the second is
being drilled from the same pad in Potter County, Pennsylvania. Once the
second well is drilled, we plan to complete both wells and expect to
place them on line by mid-year 2011. We expect to drill up to 14
(13.0 net) horizontal wells in 2011 in Potter and Tioga Counties,
Pennsylvania. We currently have over 56,000 net acres in the Marcellus
Shale, primarily in Potter and Tioga Counties, where we have in excess
of 35,000 net acres and estimate we have over 200 gross drilling
locations.
of 2010, we drilled two (1.7 net) horizontal Cotton Valley wells, both
of which were successful. During 2010, we completed seven (6.5 net)
horizontal Cotton Valley wells with IP rates ranging between 0.8 and 4.1
MMcfe per day (average of 3.0 MMcfe per day; oil comprised approximately
11 percent of the wellhead volumes), excluding processed NGLs which
typically add approximately 20 percent to equivalent production volumes.
We are encouraged with the initial results of our horizontal Cotton
Valley program with initial decline rates that have been less than we
anticipated and oil volumes from wells drilled horizontally in the Davis
Sand portion of the Cotton Valley that have been higher than we
expected. As a result, we expect selectively drilled Davis Sand Cotton
Valley horizontal wells will generate attractive rates of return with
today′s natural gas and liquids prices.
2010, we drilled two (2.0 net) horizontal Selma Chalk wells, both of
which were successful. During the fourth quarter of 2010, we completed
three (3.0 net) horizontal Selma Chalk wells with IP rates between 1.3
and 2.2 MMcfe per day. The rig that had been drilling Selma Chalk wells
has been moved to Pennsylvania and is dedicated to the Marcellus Shale
drilling program for 2011. Further drilling in the Selma Chalk has been
discontinued until natural gas prices recover.
PV-10 Value is a non-GAAP financial measure under SEC regulations and
differs from the Standardized Measure of Discounted Future Net Cash
Flows (Standardized Measure) in that PV-10 Value is a pre-tax value,
while the Standardized Measure includes the effect of estimated future
income taxes, discounted at 10 percent. We believe that the PV-10 Value
is an important measure that can be used to evaluate the relative
significance of our oil and natural gas properties and that PV-10 Value
is widely used by security analysts and investors when evaluating oil
and gas companies. Because many factors that are unique to each
individual company impact the amount of future income taxes to be paid,
the use of a pre-tax measure enhances comparability of assets when
evaluating companies. The Standardized Measure at year-end 2010 of
$641.4 million, plus $236.7 million of present value of future income
tax discounted at 10 percent, is equal to the PV-10 Value of $878.1
million.
Conference Call
A conference call and webcast, during which management will discuss
fourth quarter and full-year 2010 financial and operational results, is
scheduled for Thursday, February 24, 2011 at 10:00 a.m. ET. Prepared
remarks by A. James Dearlove, Chief Executive Officer, will be followed
by a question and answer period. Investors and analysts may participate
via phone by dialing 1-866-823-5017 five to ten minutes before the
scheduled start of the conference call (use the passcode 9013804), or
via webcast by logging on to our website, www.pennvirginia.com,
at least 15 minutes prior to the scheduled start of the call to download
and install any necessary audio software. A telephonic replay will be
available for two weeks beginning approximately 24 hours after the call.
The replay can be accessed by dialing toll free 888-203-1112
(international: 719-457-0820) and using the replay code 9013804. In
addition, an on-demand replay of the webcast will also be available for
two weeks at our website beginning approximately 24 hours after the
webcast.
and oil company focused on the exploration, acquisition, development and
production of reserves in onshore regions of the U.S., including
Oklahoma, Texas, the Appalachian Basin and Mississippi.
Certain statements contained herein that are not descriptions of
historical facts are 'forward-looking? statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E
of the Securities Exchange Act of 1934, as amended. Because such
statements include risks, uncertainties and contingencies, actual
results may differ materially from those expressed or implied by such
forward-looking statements. These risks, uncertainties and contingencies
include, but are not limited to, the following: the volatility of
commodity prices for natural gas, NGLs and oil; our ability to develop,
explore for, acquire and replace oil and gas reserves and sustain
production; any impairments, write-downs or write-offs of our reserves
or assets; the projected demand for and supply of natural gas, NGLs and
oil; reductions in the borrowing base under our revolving credit
facility; our ability to contract for drilling rigs, supplies and
services at reasonable costs; our ability to obtain adequate pipeline
transportation capacity for our oil and gas production at reasonable
cost and to sell the production at, or at reasonable discounts to,
market prices; the uncertainties inherent in projecting future rates of
production for our wells and the extent to which actual production
differs from estimated proved oil and gas reserves; drilling and
operating risks; our ability to compete effectively against other
independent and major oil and natural gas companies; uncertainties
related to expected benefits from acquisitions of oil and natural gas
properties; environmental liabilities that are not covered by an
effective indemnity or insurance; the timing of receipt of necessary
regulatory permits; the effect of commodity and financial derivative
arrangements; our ability to maintain adequate financial liquidity and
to access adequate levels of capital on reasonable terms; the occurrence
of unusual weather or operating conditions, including force majeure
events; our ability to retain or attract senior management and key
technical employees; counterparty risk related to their ability to meet
their future obligations; changes in governmental regulation or
enforcement practices, especially with respect to environmental, health
and safety matters; uncertainties relating to general domestic and
international economic and political conditions; and other risks set
forth in our filings with the SEC.
Additional information concerning these and other factors can be found
in our press releases and public periodic filings with the SEC. Many of
the factors that will determine our future results are beyond the
ability of management to control or predict. Readers should not place
undue reliance on forward-looking statements, which reflect management′s
views only as of the date hereof. We undertake no obligation to revise
or update any forward-looking statements, or to make any other
forward-looking statements, whether as a result of new information,
future events or otherwise.
Penn Virginia Corporation
James W. Dean
Vice President,
Corporate Development
Ph: 610-687-7531
Fax: 610-687-3688
invest@pennvirginia.com