DENVER, March 12, 2014 /PRNewswire/ -- Double
Eagle Petroleum Co. (NASDAQ: DBLE) today reported its financial
and operating results for the year ended December 31, 2013. The Company reported a
net loss attributable to common stock of $16,796,000, or $1.48 per share for 2013 as compared to a net
loss of $14,050,000, or $1.25 per share for 2012.
Clean earnings, a non-GAAP financial measure, totaled
$10,167,000, or $0.90 per share, for the year ended December 31, 2013, as compared to $15,200,000 or $1.35 per share for the year ended December 31, 2012. Clean earnings excludes
the effects on net loss of non-cash charges, consisting of
depreciation, depletion and amortization expense, unrealized gains
and losses related to the Company's economic hedges, impairment
charges and stock-based compensation expense. Clean earnings also
excludes the impact of income taxes, as the Company does not expect
to pay income tax in the foreseeable future due to its net
operating loss carryforwards. Please see the table at the end of
this release for the reconciliation of clean earnings to GAAP net
loss.
The Company's 2013 results were impacted by the following:
Pricing.
The Company benefited from an
11% increase in its average realized natural gas prices, increasing
to $3.91 per Mcfe in 2013 from
$3.52 per Mcfe in 2012.
Production.
Production totaled 9.2 Bcfe
for the year ended December 31, 2013,
representing a 12% decrease from 2012.
The Company experienced a 14% decrease in its average daily net
production at the Catalina Unit as compared to the prior year,
which was primarily the result of a series of equipment challenges
experienced in 2013, including a compressor failure and unscheduled
maintenance on several injection pumps. Coalbed methane gas
wells are susceptible to water saturation when offline and the
Company's operations team has focused its efforts on increasing
production given these challenges. As a result of these
efforts, the Company realized a sequential increase of 9% in its
average daily net production in the fourth quarter of 2013 as
compared to the third quarter of 2013. The Company also
completed a workover program in the third quarter of 2013, which
focused on opening-up the Almond formation in 12 existing Catalina
wells. The sequential production growth in the fourth quarter
of 2013 is also partially attributable to the success from this
workover program.
The Company also experienced a decrease in production from its
non-operated properties in the Spyglass Hill Unit and on the
Pinedale Anticline. The operator of the Spyglass Hill Unit
completed 27 new wells in late 2013. Production from the new
wells was not significant in 2013 due to the water management
systems. The operator has announced that it has a robust
drilling program planned for 2014, which includes six water
injection wells and improvements to the water management
system.
Non-cash gain/loss on derivative instruments.
The Company had an unrealized non-cash loss from its derivatives of
$6,656,000 in 2013, resulting from
the net changes in the fair values of its commodity contracts and
interest rate swap in 2013. This compared to an unrealized
non-cash loss of $7,933,000 in
2012.
Impairment charges.
The Company recorded
additional impairment charges related to its Niobrara exploration well totaling
$4,812,000 during the year ended
December 31, 2013. The Company
is currently producing gas from the Niobrara formation, and is awaiting a permit
that will also allow natural gas production from the Frontier and
Dakota formations in the third quarter of 2014.
Reserves
The Company had estimated proved reserves of 74.7 Bcfe as of
December 31, 2013, with a PV-10 value
of $78,183,000. Estimated
proved reserves were 97% natural gas, of which 80% were proved
developed. Approximately 63% of the Company's 2013 production
was replaced through revisions of estimates and extensions and
discoveries. The positive revisions were largely due to
an increase in the average natural gas price used in the reserve
estimate, as calculated in accordance with the Securities and
Exchange Commission ("SEC"). SEC pricing increased 38% to
$3.53 per MMbtu in 2013 as compared
to $2.56 per MMbtu in 2012. As
a result of the higher pricing, certain of the Company's
undeveloped well locations on the Pinedale Anticline, which were
excluded from our 2012 estimate, became economic. The
increase from the Pinedale Anticline reserves was partially offset
by downward revisions to the reserves from the Company's Atlantic
Rim properties. The downward revision in the Atlantic Rim is
a reflection of the lower production volumes from these properties
in 2013 due to the previously discussed operational
challenges.
Using the forward strip as of December
31, 2013, the Company estimates its proved reserves to be
91.9 Bcfe with a PV-10 value of $99,355,000. Please refer to the table at
the end of this release for additional information on this non-GAAP
metric.
Hedging Activity
The Company continues to benefit from its hedging program,
realizing prices above the prevailing market prices in both 2013
and 2012. Excluding the impact of its commodity hedges which
settled during the year, the Company's per Mcf realized natural gas
price was $3.22 and $2.32 for the years ended December 31, 2013 and 2012, respectively.
The Company has historically entered into forward sales contracts,
collars and fixed price swaps to manage the price risk associated
with its natural gas production. All of the hedging contracts
the Company enters require no initial cash payments. The
table below summarizes the Company's open derivative contracts as
of December 31, 2013.
Type of
Contract
|
|
Remaining
Contractual
Volume (Mcf)
|
|
Term
|
|
Price
|
Fixed Price
Swap
|
|
1,825,000
|
|
01/14-12/14
|
|
$
4.27
|
|
Costless
Collar
|
|
1,800,000
|
|
01/14-12/14
|
|
$
4.00
|
floor
|
|
|
|
|
|
|
$
4.50
|
ceiling
|
Fixed Price
Swap
|
|
1,800,000
|
|
01/14-12/14
|
|
$
4.20
|
|
Fixed Price
Swap
|
|
540,000
|
|
01/14-12/14
|
|
$
4.17
|
|
Total 2014 Contracted
Volumes
|
|
5,965,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price
Swap
|
|
3,000,000
|
|
01/15-12/15
|
|
$
4.28
|
|
Fixed Price
Swap
|
|
3,600,000
|
|
01/15-12/15
|
|
$
4.15
|
|
Total 2015 Contracted
Volumes
|
|
6,600,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price
Swap
|
|
1,830,000
|
|
01/16-12/16
|
|
$
4.07
|
|
Total 2016 Contracted
Volumes
|
|
1,830,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Contracted
Volumes
|
|
14,395,000
|
|
|
|
|
|
|
|
|
|
(1)
|
All contracts are
indexed to the New York Mercantile Exchange
|
Liquidity and Capital Investment
The Company had $47,450,000
outstanding on its credit facility as of December 31, 2013, at an average interest rate of
3.3%. The Company generated cash flow from operations of
$13,082,000 as compared to
$19,468,000 for years ended
December 31, 2013 and 2012,
respectively.
Form 10-K and Earnings Conference Call
Please refer to the Company's Form 10-K, which will be filed
with the Securities and Exchange Commission on March 13, 2014, for a more detailed discussion of
the Company's results.
Double Eagle will host a conference call to discuss it 2013 year
end results on March 13, 2014 at
11:00 a.m. Eastern Time (9 a.m. Mountain). Those wanting to listen
and participate in the question and answer portion can call (800)
434-1335 and use conference code 567915#.
A replay of this conference call will be available for one week
by calling (800) 704-9804 and using pass code * then 567915#.
SUMMARY
CONSOLIDATED STATEMENTS OF OPERATIONS
|
(In thousands, except
share and per share data)
|
|
|
|
|
|
|
|
Year Ended December
31,
|
|
|
|
|
2013
|
|
2012
|
|
|
|
|
|
Revenues
|
|
|
|
|
Oil and gas
sales
|
|
$
31,784
|
|
$
26,574
|
Transportation
revenue
|
|
3,745
|
|
4,999
|
Price risk management
activities, net
|
|
(730)
|
|
4,939
|
Other income,
net
|
|
520
|
|
1,653
|
|
|
|
|
|
Total
revenues
|
|
35,319
|
|
38,165
|
|
|
|
|
|
Expenses
|
|
|
|
|
Lease operating
expenses
|
|
13,135
|
|
12,299
|
Production
taxes
|
|
3,906
|
|
3,000
|
Pipeline operating
expenses
|
|
5,194
|
|
4,892
|
Exploration expenses
including dry holes
|
|
181
|
|
696
|
Impairment and
abandonment
|
|
|
|
|
of equipment and
properties
|
|
4,992
|
|
4,988
|
|
|
|
|
|
Total
expenses
|
|
27,408
|
|
25,875
|
|
|
|
|
|
Gross margin
percentage
|
|
22.4%
|
|
32.2%
|
|
|
|
|
|
General and
administrative
|
|
5,395
|
|
6,209
|
Depreciation, depletion
and amortization
|
|
20,942
|
|
20,216
|
Interest expense,
net
|
|
1,307
|
|
1,610
|
|
|
|
|
|
Pre-tax
loss
|
|
(19,733)
|
|
(15,745)
|
|
|
|
|
|
Deferred tax
benefit
|
|
6,660
|
|
5,418
|
|
|
|
|
|
Net loss
|
|
(13,073)
|
|
(10,327)
|
|
|
|
|
|
Preferred stock
requirements
|
|
(3,723)
|
|
(3,723)
|
|
|
|
|
|
Net loss
attributable
|
|
|
|
|
to common
stock
|
|
$
(16,796)
|
|
$
(14,050)
|
|
|
|
|
|
Net loss per
common share:
|
|
|
|
|
Basic and
Diluted
|
|
$
(1.48)
|
|
$
(1.25)
|
|
|
|
|
|
Weighted average
shares outstanding:
|
|
|
|
|
Basic and
Diluted
|
|
11,332,129
|
|
11,250,513
|
|
|
|
|
|
|
SELECTED BALANCE
SHEET DATA
|
(In
thousands)
|
|
|
|
|
|
|
|
December
31,
|
|
|
|
2013
|
|
2012
|
|
%
Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
$
132,400
|
|
$
158,810
|
|
-17%
|
|
|
|
|
|
|
Outstanding balance
on credit facility
|
47,450
|
|
47,450
|
|
0%
|
|
|
|
|
|
|
Total stockholders'
equity
|
27,311
|
|
43,470
|
|
-37%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED CASH FLOW
DATA
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
2013
|
|
2012
|
|
%
Change
|
|
|
|
|
|
|
Net cash provided
by
|
|
|
|
|
|
operating
activities
|
$
13,082
|
|
$
19,468
|
|
-33%
|
|
|
|
|
|
|
Net cash used
in
|
|
|
|
|
|
investing
activities
|
(10,523)
|
|
(25,773)
|
|
-59%
|
|
|
|
|
|
|
Net cash provided
(used) by
|
|
|
|
|
|
financing
activities
|
(3,830)
|
|
1,697
|
|
-326%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SELECTED
OPERATIONAL DATA
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
December 31,
|
|
|
|
2013
|
|
2012
|
|
%
Change
|
|
|
|
|
|
|
Total production
(Mcfe)
|
9,211,802
|
|
10,514,841
|
|
-12%
|
|
|
|
|
|
|
Average price
realized per Mcfe
|
$
4.12
|
|
$
3.70
|
|
11%
|
|
|
|
|
|
|
Use of Non-GAAP Financial Measures
The Company believes that the presentation of "clean earnings"
below provides a meaningful non-GAAP financial measure to help
management and investors understand and compare operating results
and business trends among different reporting periods on a
consistent basis, independent of regularly reported non-cash
charges. The measure also excludes the impact of income taxes
because the Company does not expect to pay taxes in the near future
due to its net operating loss carryforwards. The Company's
management also uses clean earnings in its planning and development
of target operating models and to enhance its understanding of
ongoing operations. Readers should not view clean earnings as being
superior to, or an alternative to, GAAP results or as being
comparable to results reported or forecasted by other companies. A
reconciliation of GAAP net income with clean earnings for the years
ended December 31, 2013 and 2012, is
as follows:
|
Year ended
December 31,
|
|
2013
|
|
|
2012
|
Net loss as
reported
|
|
|
|
|
under US
GAAP
|
$
(16,796)
|
|
|
$
(14,050)
|
Add back non-cash
items:
|
|
|
|
|
Provision for income
taxes
|
(6,660)
|
|
|
(5,418)
|
Depreciation,
depletion, amortization and accretion expense
|
21,218
|
|
|
20,404
|
Non-cash loss on
derivative instruments (1)
|
6,656
|
|
|
7,933
|
Share-based
compensation expense
|
744
|
|
|
1,341
|
Impairments &
abandonments
|
4,992
|
|
|
4,988
|
Other non-cash
items
|
13
|
|
|
2
|
Clean
earnings
|
$
10,167
|
|
|
$
15,200
|
|
|
|
|
|
|
|
|
|
|
Clean earnings per
share
|
$
0.90
|
|
|
$
1.35
|
Clean earnings per
share - less non recurring sales of property (2)
|
$
0.85
|
|
|
$
1.20
|
|
|
|
|
(1)
|
Non-cash loss on
derivatives is comprised of an unrealized losses from the Company's
mark-to-market derivative instruments (both commodity contracts and
interest rate swaps), resulting from recording the instruments at
fair value at each year end.
|
(2)
|
The Company received
cash proceeds of $500 from a third party as a penalty for
opting-out of farmout agreement at the Main Fork Unit during the
year ended December 31, 2013. The Company recorded proceeds
of $1,680 during the year ended December 31, 2012 related to the
sale of a non-core property.
|
PV-10 is a non-GAAP financial measure and represents the present
value of estimated future cash inflows from proved oil and natural
gas reserves, less future development and production costs,
discounted at 10% per annum to reflect the timing of future cash
flows and using 12-month average prices. PV-10 differs from
Standardized Measure (a GAAP metric) because it does not include
the effects of income taxes on future net revenues. Management uses
PV-10 as an arbitrary reserve asset value measure to compare
against past reserve bases and the reserve bases of other business
entities that are not dependent on the tax-paying status of the
entity. Please refer to the Company's Annual Report on Form
10-K for the year ended December 31,
2013 for a reconciliation of PV-10 to the Standardized
Measure.
The Company presents the below reconciliation of GAAP determined
reserves and PV-10 values to the forward strip pricing reserves and
PV-10 values. The Company believes that the forward strip priced
reserves are more representative of the future value of the
existing reserves at December 31,
2013:
|
Reserves
(Bcfe)
|
|
PV-10
|
Reserves as reported
using SEC Pricing
|
74.7
|
|
$
78,183
|
Increase due to price
(1)
|
17.2
|
|
21,172
|
Reserves using
forward strip pricing
|
91.9
|
|
$
99,355
|
(1) The average price used for the SEC estimate was
$3.53 per Mcf, or $3.24 per Mcf adjusted for quality,
transportation fees, and regional price differentials. The
average adjusted forward strip price was $3.75 per Mcf.
About Double Eagle
Double Eagle Petroleum Co., which is headquartered in
Denver, Colorado, explores,
develops, and sells natural gas and crude oil, with natural gas
primarily in the Rocky Mountain region. The Company currently has
development activities and opportunities in its Atlantic Rim
coalbed methane project and on the Pinedale Anticline in
Wyoming. Also, exploration potential exists in both its
Niobrara acreage in Wyoming and Nebraska, which totals over 70,000 net acres,
and in its acreage in Elko County, Nevada.
This release may contain forward-looking statements regarding
Double Eagle Petroleum Co.'s future and expected performance based
on assumptions that the Company believes are reasonable. No
assurances can be given that these statements will prove to be
accurate. A number of risks and uncertainties could cause
actual results to differ materially from these statements,
including, without limitation, decreases in prices for natural gas
and crude oil, unexpected decreases in gas and oil production, the
timeliness, costs and results of development and exploration
activities, unanticipated delays and costs resulting from
regulatory compliance, and other risk factors described from time
to time in the Company's Forms 10-K and 10-Q and other reports
filed with the Securities and Exchange Commission. Double
Eagle undertakes no obligation to publicly update these
forward-looking statements, whether as a result of new information,
future events or otherwise.
Company Contact:
John Campbell, IR
(303) 794-8445
www.dble.com
SOURCE Double Eagle Petroleum Co.