PITTSBURGH, Feb. 5, 2016 /PRNewswire/ -- During 2015, CONSOL
Energy Inc. (NYSE: CNX) added 934 Bcfe (net to CONSOL) of proved
reserves through extensions and discoveries. As of December 31, 2015, total proved reserves were 5.6
Tcfe, which included 583 Bcfe, or 10.3%, of oil, condensate, and
liquids. Marcellus Shale reserves account for 369 Bcfe, or 14.4%,
of these heavier hydrocarbons.
CONSOL Energy replaced 284% of its 2015 production, when
considering increases from extensions and discoveries of 934 Bcfe.
Production in 2015 was 329 Bcfe (net to CONSOL).
During 2015, drilling and completion costs incurred directly
attributable to extensions and discoveries were $618.3 million. When divided by the extensions
and discoveries of 934 Bcfe, this yields a drill bit finding and
development cost of $0.66 per Mcfe,
compared to $0.76 per Mcfe at
year-end 2014.
Future development costs for PUD reserves are estimated to be
approximately $943 million, or
$0.48 per Mcfe.
The following table shows the summary of changes in
reserves:
Summary of Changes
in Proved Reserves (Bcfe)
|
Balance at December
31, 2014
|
6,828
|
Price
revisions(1)
(2)
|
(3,159)
|
Plan and other
revisions(2)
|
1,369
|
Extensions and
discoveries
|
934
|
Production
|
(329)
|
Balance at December
31, 2015
|
5,643
|
|
|
Note: The proved
reserve estimate for 2015 was prepared by CONSOL Energy and audited
by Netherland, Sewell & Associates, Inc.
|
(1) Amount of reserves
that would not be included in the December 31, 2014 proved reserve
balance due to the decrease in natural gas,
natural gas liquids (NGLs), and oil prices in 2015.
|
(2) Approximately 2,200
Bcfe within the "Price revisions" and "Plan and other revisions"
categories has been removed due to changes to the
company's five year drill plan.
|
Total net revisions are 1,790 Bcfe, which include negative price
revisions of 3,159 Bcfe and net positive plan and other revisions
of 1,369 Bcfe. The positive plan and other revisions are primarily
driven by performance revisions resulting from CONSOL's success in
reducing costs, continued improvements in type curves and EURs in
the Marcellus, and focusing on developing higher internal rate of
return projects across the company. Approximately 2,200 Bcfe of
negative revisions included in price revisions and plan and other
revisions have been removed from CONSOL's 5-year development
plan.
Proved developed reserves of 3,697 Bcfe in 2015 were 16% higher
than 2014 and comprised 66% of total proved reserves, compared to
47% in 2014. Proved undeveloped reserves (PUDs) were 1,946 Bcfe at
December 31, 2015, or 34% of total
proved reserves, compared to 53% at year-end 2014. This reflects
consistent booking of proved undeveloped reserves in 2015, as a
result of the company's continued success in the Marcellus Shale
and increased activity in the dry Utica. PUDs at year-end 2015 represent 78% of
the total wells the company expects to drill over the next five
years.
In the Marcellus Shale CONSOL Energy and its joint venture (JV)
partner turned in line 81 gross wells with an average completed
lateral length of approximately 7,600 feet and expected ultimate
recoveries (EUR) averaging approximately 2 Bcfe per thousand feet
of completed lateral. Max 24-hour production rates were as high
as 19 MMcf per day, with 31
wells peaking at rates greater than 10 MMcf per day and 12 wells
peaking at rates greater than 15 MMcf per day. As of December 31, 2015, the Marcellus Shale proved
reserves were 2,573 Bcfe, which included 1,689 Bcfe of proved
developed reserves.
In the Utica Shale, during 2015 CONSOL Energy and its JV partner
turned in line 32 gross wells with an average completed lateral
length of approximately 7,600 feet and EURs ranging up to 3 Bcfe
per thousand feet of completed lateral. In the Dry Utica Shale,
four 100% CONSOL-owned wells peaked at over 20 MMcf per day with
the Westmoreland County, PA Gaut
4I testing at a 24-hour flow rate of 61 MMcf per day and the
Monroe County, Ohio Switz 6D
testing at a 24-hour flow rate in excess of 44 MMcf per day. In
2015, CONSOL booked 876 Bcfe of Utica PUDs, which is an increase of
262% from the 334 Bcfe booked during 2014 and includes 523 Bcfe of
offset Dry Utica PUDs in Monroe County,
Ohio, due to successful drilling results and cost
reductions.
As of December 31, 2015, CONSOL
Energy has total proved, probable, and possible reserves (also
known as "3P reserves") of 38.3 Tcfe, which is an increase of 1.7
Tcfe, or 5%, in 3P reserves from the 36.6 Tcfe reported at year-end
2014. The increase in 3P reserves is primarily attributed to more
certainty in the success of the Ohio Utica Shale, as well as
continued success and optimization in the Marcellus Shale. The
company has had strong initial success in the Pennsylvania dry Utica Shale, but it is still
early in the play and reserve bookings are currently limited to one
PDP well in the 2015 reserve report. The company continues testing
Upper Devonian and dry Utica
potential in Pennsylvania,
Ohio, and West Virginia and believes that these areas
will provide additional opportunities for CONSOL's proved reserves
over time. The company's 3P reserves have been determined in
accordance with the guidelines of the Society of Petroleum
Engineers Petroleum Resources Management System.
The following table shows the breakdown of reserves, in Bcfe,
from the company's current development and exploration plays:
Breakdown of
Reserves (Bcfe)
|
|
|
Proved
Developed
|
Proved
Developed
Non-Producing
|
Proved
Undeveloped
|
Total
Proved
|
Probable
|
Possible
|
Total
3P
|
Marcellus
Shale
|
1,689
|
170
|
714
|
2,573
|
14,576
|
6,551
|
23,700
|
Coalbed
Methane
|
952
|
12
|
335
|
1,299
|
589
|
593
|
2,481
|
Utica
|
369
|
54
|
876
|
1,299
|
2,526
|
1,198
|
5,023
|
Other
(1)
|
446
|
6
|
21
|
472
|
3,351
|
3,295
|
7,116
|
Total
|
3,455
|
242
|
1,946
|
5,643
|
21,042
|
11,637
|
38,321
|
Definition:
Total 3P is a summation of total proved, probable, and possible
reserves.
The estimates
of reserves and future revenue were prepared in accordance with the
definitions and guidelines of the SEC
Regulation S-X Rule 4.10(a).
(1) Includes
Upper Devonian proved reserves of 55.7 Bcfe and 750
Bcfe of 3P reserves.
|
|
The Securities and Exchange Commission ("SEC") rules require
that the proved reserve calculations be based on the first day of
the month average prices over the preceding twelve months. For the
year-end 2015 reserve evaluation, the benchmark prices were
$2.59 per MMBtu for natural gas,
$15.59 per barrel for natural gas
liquids, $26.65 per barrel for
condensate and $50.28 per barrel for
crude oil (Cushing), representing the simple average of the prices
for the first day for each month of 2015. Comparative prices for
year-end 2014 were $4.35 per MMBtu
for natural gas, $46.54 per barrel
for natural gas liquids, $75.99 per
barrel for condensate and $94.99 per
barrel for crude oil (Cushing).
Based on these prices adjusted for energy content, quality,
hedges, transportation costs, and basis differentials ($2.02 per Mcf, $15.59 per barrel of natural gas liquids,
$24.00 per barrel of condensate and
$45.28 per barrel of crude oil,
respectively), the pre-tax discounted (10%) present value ("PV-10")
of the company's proved reserves was $1.66
billion for 2015, compared to $4.88
billion at year-end 2014.
The company's reserve based lending credit facility, which as of
December 31, 2015 had a $2 billion borrowing base, is redetermined
semiannually in the spring and fall based off the present value of
the company's oil and gas reserves at a forward looking price deck.
At future strip pricing for natural gas and liquids as of
December 31, 2015 adjusted for energy
content, quality, hedges, transportation costs, and basis
differentials, the pre-tax discounted (10%) PV-10 of the company's
proved reserves would be $3.4 billion
for 2015.
Standardized Measure of Discounted Future Net Cash
Flows
The following information was prepared in accordance with the
provisions of the Financial Accounting Standards Board's Accounting
Standards Update No. 2010-03, "Extractive Activities-Oil and
Gas (Topic 932)." This topic requires the standardized measure of
discounted future net cash flows to be based on the average,
first-day-of-the-month price for the year ended December 31,
2015. Because prices used in the calculation are average prices for
that year, the standardized measure could vary significantly from
year to year based on the market conditions that occurred.
The projections should not be viewed as realistic estimates of
future cash flows, nor should the "standardized measure" be
interpreted as representing current value to CONSOL Energy.
Material revisions to estimates of proved reserves may occur in the
future; development and production of the reserves may not occur in
the periods assumed; actual prices realized are expected to vary
significantly from those used; and actual costs may vary. CONSOL
Energy's investment and operating decisions are not based on the
information presented, but on a wide range of reserve estimates
that include probable as well as proved reserves and on a different
price and cost assumptions.
The standardized measure is intended to provide a better means
for comparing the value of CONSOL Energy's proved reserves at a
given time with those of other gas producing companies than is
provided by a comparison of raw proved reserve quantities.
Reconciliation of
PV-10 to Standardized Measure
|
|
|
|
|
December
31,
|
(Dollars in
millions)
|
|
2015
|
|
2014
|
|
2013
|
Future cash
inflows
|
|
$ 11,838
|
|
$ 28,503
|
|
$ 21,603
|
Future production
costs
|
|
(6,585)
|
|
(10,101)
|
|
(7,106)
|
Future development
costs (including abandonments)
|
|
(1,220)
|
|
(3,369)
|
|
(3,903)
|
Future net cash flows
(pre-tax)
|
|
4,033
|
|
15,033
|
|
10,594
|
10% discount
factor
|
|
(2,374)
|
|
(10,149)
|
|
(7,814)
|
PV-10 (Non-GAAP
measure) (1)
|
|
1,659
|
|
4,884
|
|
2,780
|
Undiscounted income
taxes
|
|
(1,532)
|
|
(5,712)
|
|
(4,026)
|
10% discount
factor
|
|
892
|
|
3,812
|
|
2,927
|
Discounted income
taxes
|
|
(640)
|
|
(1,900)
|
|
(1,099)
|
Standardized GAAP
measure
|
|
$ 1,019
|
|
$ 2,984
|
|
$ 1,681
|
(1) We calculate our present
value at 10% (PV-10) in accordance with the following table.
Management believes that the presentation of the non-Generally
Accepted Accounting Principle (GAAP) financial measure of PV-10
provides useful information to investors because it is widely used
by professional analysts and sophisticated investors in evaluating
oil and gas companies. Because many factors that are unique to each
individual company impact the amount of future income taxes
estimated to be paid, the use of a pre-tax measure is valuable when
comparing companies based on reserves. PV-10 is not a measure of
the financial or operating performance under GAAP. PV-10 should not
be considered as an alternative to the standardized measure as
defined under GAAP. We have included a reconciliation of the most
directly comparable GAAP measure-after-tax discounted future net
cash flows.
|
Cautionary Statements
Various statements in this release, including those that express
a belief, expectation or intention, may be considered
forward-looking statements under federal securities laws including
Section 21E of the Securities Exchange Act of 1934 (the "Exchange
Act") that involve risks and uncertainties that could cause actual
results to differ materially from projected results. Accordingly,
investors should not place undue reliance on forward-looking
statements as a prediction of actual results. The forward-looking
statements may include projections and estimates concerning the
timing and success of specific projects and our future production,
revenues, income and capital spending. When we use the words
"believe," "intend," "expect," "may," "should," "anticipate,"
"could," "estimate," "plan," "predict," "project," "will," or their
negatives, or other similar expressions, the statements which
include those words are usually forward-looking statements. When we
describe strategy that involves risks or uncertainties, we are
making forward-looking statements. The forward-looking statements
in this press release, if any, speak only as of the date of this
press release; we disclaim any obligation to update these
statements. We have based these forward-looking statements on our
current expectations and assumptions about future events. While our
management considers these expectations and assumptions to be
reasonable, they are inherently subject to significant business,
economic, competitive, regulatory and other risks, contingencies
and uncertainties, most of which are difficult to predict and many
of which are beyond our control. These risks, contingencies and
uncertainties relate to, among other matters, the following:
deterioration in economic conditions in any of the industries in
which our customers operate may decrease demand for our products,
impair our ability to collect customer receivables and impair our
ability to access capital; prices for natural gas, natural gas and
other liquids and coal are volatile and can fluctuate widely based
upon a number of factors beyond our control including oversupply
relative to the demand available for our products, weather and the
price and availability of alternative fuels. An extended decline in
the prices we receive for our natural gas, natural gas liquids and
coal affecting our operating results and cash flows; foreign
currency fluctuations could adversely affect the competitiveness of
our coal abroad; our customers extending existing contracts or
entering into new long-term contracts for coal on favorable terms;
our reliance on major customers; our inability to collect payments
from customers if their creditworthiness declines or if they fail
to honor their contracts; the disruption of rail, barge, gathering,
processing and transportation facilities and other systems that
deliver our natural gas, natural gas liquids and coal to market; a
loss of our competitive position because of the competitive nature
of the natural gas and coal industries, or a loss of our
competitive position because of overcapacity in these industries
impairing our profitability; coal users switching to other fuels in
order to comply with various environmental standards related to
coal combustion emissions; the impact of potential, as well as any
adopted environmental regulations including any relating to
greenhouse gas emissions on our operating costs as well as on the
market for natural gas and coal and for our securities; the risks
inherent in natural gas and coal operations, including our reliance
upon third party contractors, being subject to unexpected
disruptions, including geological conditions, equipment failure,
timing of completion of significant construction or repair of
equipment, fires, explosions, accidents and weather conditions
which could impact financial results; decreases in the availability
of, or increases in, the price of commodities or capital equipment
used in our mining and transportation operations; obtaining and
renewing governmental permits and approvals for our natural gas and
coal operations; the effects of government regulation on the
discharge into the water or air, and the disposal and clean-up of,
hazardous substances and wastes generated during our natural gas
and coal operations; our ability to find adequate water sources for
our use in gas drilling, or our ability to dispose of water used or
removed from strata in connection with our gas operations at a
reasonable cost and within applicable environmental rules; the
effects of stringent federal and state employee health and safety
regulations, including the ability of regulators to shut down our
operations; the potential for liabilities arising from
environmental contamination or alleged environmental contamination
in connection with our past or current gas and coal operations; the
effects of mine closing, reclamation, gas well closing and certain
other liabilities; uncertainties in estimating our economically
recoverable gas, oil and coal reserves; defects may exist in our
chain of title and we may incur additional costs associated with
perfecting title for gas rights on some of our properties or
failing to acquire these additional rights may result in a
reduction of our estimated reserves; the outcomes of various legal
proceedings, which are more fully described in our reports filed
under the Securities Exchange Act of 1934; exposure to
employee-related long-term liabilities; lump sum payments made to
retiring salaried employees pursuant to our defined benefit pension
plan exceeding total service and interest cost in a plan year;
divestitures we anticipate may not occur or produce anticipated
benefits; the terms of our existing joint ventures restrict our
flexibility, actions taken by the other party in our gas joint
ventures may impact our financial position and various
circumstances could cause us not to realize the benefits we
anticipate receiving from these joint ventures; risks associated
with our debt; replacing our gas and oil reserves, which if not
replaced, will cause our gas and oil reserves and production to
decline; declines in our borrowing base could occur for a variety
of reasons, including lower natural gas or oil prices, declines in
natural gas and oil proved reserves, and lending regulations
requirements or regulations; our hedging activities may prevent us
from benefiting from price increases and may expose us to other
risks; changes in federal or state income tax laws, particularly in
the area of percentage depletion and intangible drilling costs,
could cause our financial position and profitability to
deteriorate; failure to appropriately allocate capital and other
resources among our strategic opportunities may adversely affect
our financial condition; failure by Murray Energy to satisfy
liabilities it acquired from us, or failure to perform its
obligations under various arrangements, which we guaranteed, could
materially or adversely affect our results of operations, financial
position, and cash flows; information theft, data corruption,
operational disruption and/or financial loss resulting from a
terrorist attack or cyber incident; operating in a single
geographic area; certain provisions in our multi-year sales
contracts may provide limited protection during adverse economic
conditions, and may result in economic penalties or permit the
customer to terminate the contract; our common units in CNX Coal
Resources LP and CONE Midstream Partners LP are subordinated, and
we may not receive distributions from CNX Coal Resources LP or CONE
Midstream Partners LP; other factors discussed in the 2014 Form
10-K under "Risk Factors," as updated by any subsequent Form 10-Qs,
which are on file at the Securities and Exchange Commission.
The SEC permits oil and gas companies, in their filings with the
SEC, to disclose only proved, probable, and possible oil and gas
reserves that a company anticipates as of a given date to be
economically and legally producible and deliverable by application
of development projects to known accumulations. We may use certain
terms in this press release, such as EUR (estimated ultimate
recovery), unproved reserves and total resource potential, that the
SEC's rules strictly prohibit us from including in filings with the
SEC. These measures are by their nature more speculative than
estimates of reserves prepared in accordance with SEC definitions
and guidelines and accordingly are less certain. We also note that
the SEC strictly prohibits us from aggregating proved, probable and
possible reserves in filings with the SEC due to the different
levels of certainty associated with each reserve category.
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SOURCE CONSOL Energy Inc.