RANGE RESOURCES CORPORATION (NYSE:RRC) announced
today that proved reserves as of December 31, 2016 were 12.1 Tcfe.
Reserves
Highlights –
- Proved reserves increased 11%, excluding acquisitions and
divestitures
- Proved developed reserves increased 14%, excluding acquisitions
and divestitures
- Drill-bit development cost with revisions is expected to be
$0.34 per mcfe
- Future development costs for proved undeveloped reserves are
estimated to be $0.42 per mcfe; Marcellus costs are estimated to be
$0.37 per mcfe
- Unhedged recycle ratio improves to over 3x based on future
development costs of $0.42 per mcfe
Commenting on Range’s 2016 proved reserves, Jeff
Ventura, Range’s CEO, said, “Range had another solid year of
reserve growth, replacing 292% of production from drilling
activities with drill-bit development costs of $0.34 per mcfe when
considering pricing and performance revisions. Positive
performance revisions continued in 2016 as we extended laterals,
improved targeting and drove efficiencies throughout our developed
leasehold and infrastructure. The strong reserve additions
from drilling activity were driven primarily by our development in
the Marcellus, as our acquisition of North Louisiana assets closed
in late 2016. Future development costs for proven undeveloped
locations are estimated to be $0.42 per mcfe, which is outstanding
and should improve our top tier unhedged recycle ratio to over
3x. Importantly, Range added 1.65 Tcfe of reserves, excluding
acquisitions, reflecting our large inventory of low-risk, high-
return projects in the Marcellus shale and in North Louisiana.”
“In North Louisiana, performance in 2016 was in
line with our acquisition economics and the properties recorded a
slight performance increase, while drilling added 79 Bcfe of
reserves post-acquisition. Looking forward, we see capital
efficiencies continuing as we drive down well costs while
optimizing targeting. Our reserve booking philosophy on the
newly acquired assets is consistent with our approach in the
Marcellus. As a result, a relatively small portion of the
Company’s future development capital, only $2.2 billion over the
next five years, is allocated to proven locations, while the
remainder of capital delineates our extensive acreage position,
still classified as unproven. In fact, less than 0.5 offset
proven undeveloped locations are currently recorded in the
Marcellus and North Louisiana for each horizontal producing
well. We believe this will generate consistent SEC reserve
growth over time as additional acreage is classified as proven and
capital is allocated to offset locations. As an example,
Range has approximately 740 Bcfe of additional reserves in the
Terryville area that would be included as SEC proved reserves if
included within the five-year development plan. Our economic
resilience is further demonstrated in the year-end SEC PV10 reserve
value of $9.0 billion using future strip prices and current sales
contracts. With 56% of SEC reserves being proved developed
(PD), our PD reserve life and debt per PD reserve ratios remain
exceptionally strong.”
Range’s estimate of costs incurred during 2016,
excluding acquisition costs is approximately $570 million.
This is on target with Range’s previously announced capital budget
of $495 million, prior to the Memorial acquisition.
|
|
SUMMARY OF CHANGES IN PROVED
RESERVES |
|
(in Bcfe) |
|
|
|
Balance at December 31, 2015 |
9,892 |
|
|
|
Extensions, discoveries and additions |
1,394 |
|
Purchases |
1,260 |
|
Performance revisions: |
|
PUD
improved recovery |
393 |
|
Performance |
154 |
|
Total
Performance revisions |
547 |
|
|
|
Reclassification of PUD to unproved under SEC 5-year rule |
( 269 |
) |
Price
revisions |
(23 |
) |
Sales of
proved reserves |
(165 |
) |
Estimated
Production |
(564 |
) |
|
|
Balance at December 31, 2016 |
12,072 |
|
During 2016, Range added 1,394 Bcfe of proved
reserves through the drill-bit, driven by 1,315 Bcfe from the
Company’s Marcellus development. The “extensions,
discoveries, and additions” amount excludes 393 Bcfe of Marcellus
reserves associated with undrilled locations that now have
increased recovery estimates as a result of longer laterals, better
lateral targeting and increased frac stages. This improved
recovery estimate is included in the “revision” category. The
lateral lengths for existing proved undeveloped locations increased
to 7,162 feet in the 2016 report from 6,301 feet in the 2015
report, while newly added proved undeveloped locations in the
Marcellus incorporate an average lateral length of approximately
7,900 feet.
To provide more clarity, the 2016 reserve revisions
category is segregated into four components. First, as mentioned
above, the improved recovery component has a positive revision of
393 Bcfe. Second, field level performance increased reserves
by 154 Bcfe due primarily to the continued improvement in the
well performance of existing Marcellus producing wells.
Third, as a result of Range’s continued success in drilling longer
laterals, the future development plan has been re-optimized which
results in some previously planned wells not being drilled within
five years from their original booking date. Accordingly,
Range removed from its Securities and Exchange Commission (“SEC”)
proved reserves 269 Bcfe of proved undeveloped reserves that now
fall outside the five-year window. The Company expects these
proved undeveloped reserves can be added back in future years as
field development continues. The wells that remain have
longer laterals, greater estimated ultimate recoveries (“EURs”) and
lower per foot drilling and completion costs which result in
expected improved economics. The resulting corporate proved
undeveloped development cost of $0.42 per mcfe is based on 2016
well costs and consists of Marcellus cost of $0.37 per mcfe and
North Louisiana cost of $0.68 per mcfe. Lastly, the lower SEC
price for 2016 as compared to 2015 resulted in a minimal downward
revision in proved reserves of 23 Bcfe, reflecting the Company’s
low-cost reserve base.
During the year, Range sold 165 Bcfe of proved
reserves primarily in Oklahoma and non-operated areas in
Pennsylvania.
Year-end 2016 proved reserves by volume were 65%
natural gas, 31% natural gas liquids and 4% crude oil and
condensate. Proved developed reserves represents 56% of the
Company’s reserves. The Company’s Appalachia reserves were
audited by Wright & Company, Inc. and were within 1% of the
aggregate estimates prepared by Range’s petroleum engineering staff
and the Company’s North Louisiana reserves were audited by
Netherland, Sewell and Associates, Inc. and were within
approximately 2% of Range’s estimates.
|
2016 SEC and Strip Pricing: |
|
|
|
|
2016 Year-End |
|
2015 Year-End |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SEC Pricing (a) |
|
Strip Pricing |
|
SEC Pricing (b) |
|
Strip Pricing |
|
|
|
|
|
|
|
|
|
|
|
|
WTI
Oil Price ($/Bbl) |
$ |
42.68 |
|
$ |
56.49 |
|
$ |
50.13 |
|
$ |
52.14 |
|
Natural Gas Price ($/Mmbtu) |
$ |
2.48 |
|
$ |
3.14 |
|
$ |
2.59 |
|
$ |
3.25 |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves PV-10 ($ Billions) |
$ |
3.7 |
|
$ |
9.0 |
|
$ |
3.0 |
|
$ |
6.8 |
|
|
|
|
|
|
|
|
|
|
|
|
(a) SEC benchmark prices adjusted for energy content, quality
and basis differentials were $2.07 per Mmbtu, $13.44 per barrel of
natural gas liquids and $37.41 per barrel of crude oil,
respectively. |
|
(b) SEC benchmark prices adjusted for energy content, quality
and basis differentials were $2.07 per Mmbtu, $11.74 per barrel of
natural gas liquids and $35.06 per barrel of crude oil,
respectively. |
|
Resource Potential
Range’s net unrisked unproved resource potential at
year-end 2016, for Appalachia quantifying only the potential
Marcellus and Upper Devonian future development, increased to
approximately 93 Tcfe, including 4.8 billion barrels of NGLs and
crude oil/condensate, consisting of over 4,700 locations in the
Marcellus and 2,800 locations in the Upper Devonian, based on
average lateral lengths of 8,000 feet. A resource estimate
has not yet been provided for the Utica, though Range has 400,000
net acres in southwest Pennsylvania. This acreage position has
three existing producing wells, one of which is considered a top
producer in the play, and multiple operators with offset Utica
activity. As a result, the Company expects to increase its
resource potential in Appalachia in the future. Range’s
unrisked unproved resource potential at year-end 2016 for North
Louisiana was 6.7 Tcfe, consisting of 670 high-graded drilling
locations, based on average lateral lengths of 7,500 feet.
These locations consist of Upper and Lower Red targets,
predominantly in the Terryville area.
North Louisiana Extension
Wells
Range has completed three wells in the extension
area of North Louisiana, south of Terryville. These three
wells were drilled on the north, east and west sides of the Vernon
Field. Each of the wells encountered significant amounts of
gas in multiple zones across the Upper and Lower Red intervals,
similar to the prolific Vernon Field that was productive out of
both horizons.
The well to the west of Vernon logged pay in three
Upper Red zones that have an estimated 210 Bcf per square mile in
place. The same well logged pay in three zones in the Lower
Red with an estimated 188 Bcf per square mile, for a combined total
of almost 400 Bcf per square mile. For reference, this total
gas in place is more than 2.5 times Terryville. The well was
completed in one of the Upper Red zones and had an initial flowing
pressure of 6,500 psi and a peak constrained 24-hour production
rate of 12.4 Mmcf per day. Based on managed cumulative production
of 660 Mmcf after 79 days and an effective lateral length of 5,050
feet, the well is expected to have a normalized gas EUR that is in
line with Terryville Upper and Lower Red wells.
The eastern well also logged pay in three Upper Red
zones and three Lower Red zones. The Upper Red zones had a
total of 153 Bcf per square mile and the Lower Red totaled 263 Bcf
per square mile, for a combined total of over 400 Bcf per square
mile. The well was completed in one of the Lower Red zones
and had an initial flowing pressure of 6,700 psi and a peak
constrained 24-hour production rate of 23.3 Mmcf per day.
Based on managed cumulative production of 641 Mmcf after 67 days
and an effective lateral length of 4,250 feet, the well also
appears to have a normalized gas EUR that is in line with
Terryville Upper and Lower Red wells.
The well to the north of Vernon field does not have
the same amount of production history, though initial production
results were below the two other tests. The well was
completed in one of the Lower Red zones and had an initial flowing
pressure of 5,600 psi and a peak constrained 24-hour production
rate of 5 Mmcf per day.
Commenting on the results, Jeff Ventura, Range’s
CEO, said “Range is very encouraged by the early success the team
has had in North Louisiana. We saw several opportunities to
create value when we acquired the assets in late 2016. The
team is already generating value in Terryville through operational
improvements that are resulting in significantly lower well costs
and improved targeting, which should result in better well
performance. This will remain our focus in North Louisiana
for 2017, driving better returns and potentially increasing our
drilling inventory throughout the acreage.”
“We also saw the opportunity to create value over
time through improved marketing and potentially developing
additional horizons within Terryville. In addition we saw
long-term potential for development of new fields in the extension
areas. The initial production results from outside of
Terryville are encouraging. These initial three tests confirm
that the Lower Cotton Valley pay section thickens as we move
towards the Vernon Field, the gas in place increases and there are
multiple stacked-pay targets. While remaining very focused on
our core assets in the Marcellus and Terryville, we will look to
expand on the initial results from the extension area by
methodically testing additional targets throughout this year.”
Disclosure Statements:
Certain selected financial information in this
release is unaudited. Audited financial results will be
provided in our Annual Report on Form 10-K for the year ended
December 31, 2016, which we plan to file with the SEC on February
22, 2017.
Range has disclosed two primary metrics in this
release to measure our ability to establish a long-term trend of
adding reserves at a reasonable cost – a reserve replacement ratio
and finding and development cost per unit. The reserve replacement
ratio is an indicator of our ability to replace annual production
volumes and grow our reserves. It is important to economically find
and develop new reserves that will offset produced volumes and
provide for future production given the inherent decline of
hydrocarbon reserves as they are produced. We believe the ability
to develop a competitive advantage over other natural gas and oil
companies is dependent on adding reserves in our core areas at
lower costs than our competition. The reserve replacement
ratio is calculated by dividing production for the year into the
sum of proved extensions, discoveries and additions and proved
reserves added by performance revisions or price revisions as
stated in each instance in the release. The use of
performance revisions is warranted because any adjustment in
reserve estimates after the initial estimate of reserves is
reflected as a “revision,” even in those instances where the
original estimate of reserves was made when the location was
classified as proven undeveloped. Any change in the estimate
after the well is drilled and reclassified as proved developed
would be classified as a “revision.”
Finding and development cost per unit is a non-GAAP
metric used in the exploration and production industry by
companies, investors and analysts. The calculations presented by
the Company are based on estimated and unaudited costs incurred
excluding asset retirement obligations, gas gathering facilities
and non-cash stock-based compensation and divided by proved reserve
additions (extensions, discoveries and additions shown in the
table) adjusted for the changes in proved reserves for performance,
price and deferral revisions or excluding certain costs such as
acreage and acquisitions as stated in each instance in the release.
Drill-bit development cost per mcfe is based on estimated and
unaudited drilling, development and exploration costs incurred
divided by the reserve extensions, discoveries and additions with
the inclusion of any revisions as specified in the stated
measurement. These calculations do not include the future
development costs required for the development of proved
undeveloped reserves. The SEC method of computing finding costs
contains additional cost components and results in a higher
number. A reconciliation of the two methods will be shown on
the Company’s website at www.rangeresources.com after filing its
2016 Form 10-K.
The reserve replacement ratio and finding and
development cost per unit are statistical indicators that have
limitations, including their predictive and comparative value. As
an annual measure, the reserve replacement ratio can be limited
because it may vary widely based on the extent and timing of new
discoveries and the varying effects of changes in prices and well
performance. In addition, because the reserve replacement ratio and
finding and development cost per unit do not consider the cost or
timing of future production of new reserves, such measures may not
be an adequate measure of value creation. These reserves metrics
may not be comparable to similarly titled measurements used by
other companies.
Year-end pre-tax discounted present value is
considered a non-GAAP financial measure as defined by the SEC. We
believe that the presentation of pre-tax discounted present value
is relevant and useful to our investors because it presents the
discounted future net cash flows attributable to our proved
reserves prior to taking into account future corporate income taxes
and our current tax structure. We further believe investors and
creditors use pre-tax discounted present value as a basis for
comparison of the relative size and value of our reserves as
compared with other companies. Range's pre-tax discounted present
value as of December 31, 2016 may be reconciled to the GAAP
financial measure of its standardized measure of discounted future
net cash flows as of December 31, 2016 by reducing Range's pre-tax
discounted present value by the discounted future income taxes
associated with such reserves. This reconciliation will be included
in the Company’s 2016 Form 10-K.
Summary of Changes in Proved Reserves by
Category for 2016 |
|
|
|
|
|
|
|
Proved Developed Reserves |
|
Proved Undeveloped Reserves |
|
Total Proved Reserves |
|
(Bcfe) |
|
(Bcfe) |
|
(Bcfe) |
|
|
|
|
|
|
Proved Reserves
12/31/15 |
5,422 |
|
|
4,470 |
|
|
9,892 |
|
|
|
|
|
|
|
Pro-forma
changes in reserves: |
|
|
|
|
|
Extensions, discoveries and additions |
144 |
|
|
1,250 |
|
|
1,394 |
|
|
|
|
|
|
|
PUDs
drilled |
1,065 |
|
|
(1,065 |
) |
|
0 |
|
|
|
|
|
|
|
Performance revisions |
134 |
|
|
413 |
|
|
547 |
|
|
|
|
|
|
|
5-year
rule PUDs reclassified |
- |
|
|
(269 |
) |
|
(269 |
) |
|
|
|
|
|
|
Pricing
revisions |
(22 |
) |
|
(1 |
) |
|
(23 |
) |
|
|
|
|
|
|
Estimated
Production |
(564 |
) |
|
0 |
|
|
(564 |
) |
|
|
|
|
|
|
Proved Reserves
after pro-forma |
6,179 |
|
|
4,798 |
|
|
10,977 |
|
|
|
|
|
|
|
Purchases |
691 |
|
|
569 |
|
|
1,260 |
|
|
|
|
|
|
|
Sales of
reserves |
(100 |
) |
|
(65 |
) |
|
(165 |
) |
|
|
|
|
|
|
Proved Reserves
12/31/16 |
6,770 |
|
|
5,302 |
|
|
12,072 |
|
|
|
|
|
|
|
Percent by
Category |
56 |
% |
|
44 |
% |
|
100 |
% |
|
|
|
|
|
|
Increase in
reserves by category (a) |
14 |
% |
|
7 |
% |
|
11 |
% |
|
|
|
|
|
|
Increase in
reserves by category |
25 |
% |
|
19 |
% |
` |
22 |
% |
|
|
|
|
|
|
(a) Pro-forma change in reserves, which excludes
purchase and sale of reserves |
|
|
|
RANGE RESOURCES CORPORATION
(NYSE:RRC) is a leading U.S. independent oil and natural gas
producer with operations focused in stacked-pay projects in the
Appalachian Basin and North Louisiana. The Company pursues an
organic growth strategy targeting high return, low-cost projects
within its large inventory of low risk development drilling
opportunities. The Company is headquartered in Fort Worth, Texas.
More information about Range can be found at
www.rangeresources.com.
All statements, except for statements of historical
fact, made in this release, including those relating to substantial
coverage ratio, expected lower finding and development costs,
estimated current development costs, expected proved undeveloped
reserves additions in future years, expected future development
plans, estimated future development costs, expected future capital
efficiencies, expected rates of return, expected low-risk
offsetting potential, expected low-cost strong return project
inventory, expected future lateral lengths, expected future strip
prices and differentials, improved recovery estimates, future
expectation of lower costs, future resource potential, and expected
future strong return projects 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. These statements are based on assumptions and estimates
that management believes are reasonable based on currently
available information; however, management's assumptions and
Range's future performance are subject to a wide range of business
risks and uncertainties and there is no assurance that these goals
and projections can or will be met. Any number of factors could
cause actual results to differ materially from those in the
forward-looking statements, including, but not limited to, the
volatility of oil and gas prices, the results of our hedging
transactions, the costs and results of drilling and operations, the
timing of production, mechanical and other inherent risks
associated with oil and gas production, weather, the availability
of drilling equipment, changes in interest rates, litigation,
uncertainties about reserve estimates, environmental risks and
regulatory changes. Range undertakes no obligation to publicly
update or revise any forward-looking statements. Further
information on risks and uncertainties is available in Range's
filings with the Securities and Exchange Commission ("SEC"), which
are incorporated by reference.
The SEC permits oil and gas companies, in filings
made with the SEC, to disclose proved reserves, which are estimates
that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions as well as the
option to disclose probable and possible reserves. Range has
elected not to disclose the Company’s probable and possible
reserves in its filings with the SEC. Range uses certain
broader terms such as "resource potential,” or "unproved resource
potential" or "upside" or other descriptions of volumes of
resources potentially recoverable through additional drilling or
recovery techniques that may include probable and possible reserves
as defined by the SEC's guidelines. Range has not attempted
to distinguish probable and possible reserves from these broader
classifications. The SEC’s rules prohibit us from including in
filings with the SEC these broader classifications of
reserves. These estimates are by their nature more
speculative than estimates of proved, probable and possible
reserves and accordingly are subject to substantially greater risk
of actually being realized. Unproved resource potential
refers to Range's internal estimates of hydrocarbon quantities that
may be potentially discovered through exploratory drilling or
recovered with additional drilling or recovery techniques and have
not been reviewed by independent engineers. Unproved resource
potential does not constitute reserves within the meaning of the
Society of Petroleum Engineer's Petroleum Resource Management
System and does not include proved reserves. Area wide
unproven resource potential has not been fully risked by Range's
management. “EUR,” or estimated ultimate recovery, refers to our
management’s estimates of hydrocarbon quantities that may be
recovered from a well completed as a producer in the area. These
quantities may not necessarily constitute or represent reserves
within the meaning of the Society of Petroleum Engineer’s Petroleum
Resource Management System or the SEC’s oil and natural gas
disclosure rules. Actual quantities that may be recovered from
Range's interests could differ substantially. Factors
affecting ultimate recovery include the scope of Range's drilling
program, which will be directly affected by the availability of
capital, drilling and production costs, commodity prices,
availability of drilling services and equipment, drilling results,
lease expirations, transportation constraints, regulatory
approvals, field spacing rules, recoveries of gas in place, length
of horizontal laterals, actual drilling results, including
geological and mechanical factors affecting recovery rates and
other factors. Estimates of resource potential may change
significantly as development of our resource plays provides
additional data. Investors are urged to consider closely the
disclosure in our most recent Annual Report on Form 10-K, available
from our website at www.rangeresources.com or by written
request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas
76102. You can also obtain this Form 10-K by calling the SEC
at 1-800-SEC-0330.
Range Investor Contacts:
Laith Sando, Vice President – Investor Relations
817-869-4267
lsando@rangeresources.com
David Amend, Investor Relations Manager
817-869-4266
damend@rangeresources.com
Michael Freeman, Senior Financial Analyst
817-869-4264
mfreeman@rangeresources.com
Josh Stevens, Financial Analyst
817-869-1564
jrstevens@rangeresources.com
or
Range Media Contact:
Michael Mackin, Director of Public Affairs
724-743-6776
mmackin@rangeresources.com
www.rangeresources.com
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