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8-K - FORM 8-K - Escalera Resources Co. | c24153e8vk.htm |
Exhibit 99.1
Double Eagle Petroleum Company
1675 Broadway, Suite 2200 Denver, Colorado, 80202· 1-303-794-8445 · Fax: 1-303-794-8451
1675 Broadway, Suite 2200 Denver, Colorado, 80202· 1-303-794-8445 · Fax: 1-303-794-8451
Denver, Colorado FOR RELEASE AT 5:00 PM EASTERN DAYLIGHT TIME
Date: November 2, 2011
Date: November 2, 2011
Double Eagle Petroleum Reports Third Quarter Results and Operations Update
Denver, Colorado Double Eagle Petroleum Co. (NASDAQ: DBLE) reported today its financial results
for the third quarter ended September 30, 2011. The Company had net income attributable to common
stock of $2,906,000, or $0.26 per share, for the third quarter of 2011 as compared to $1,932,000,
or $0.17 per share, for the third quarter of 2010. The increase in net income in the third quarter
of 2011 was attributed to the following:
| $4,642,000 pre-tax unrealized non-cash gain on the Companys economic hedges; |
| 20% increase in realized natural gas price; and |
| 4% increase in production. |
The Companys third quarter 2010 results included pre-tax proceeds of $3,841,000 received as a
litigation settlement.
Clean earnings, a non-GAAP metric, totaled $5,693,000 for the third quarter of 2011, or $0.51 per
share, as compared to $6,866,000, or $0.62 per share, for the third quarter of 2010. Clean
earnings excludes the effects on net income of non-cash charges, including depreciation, depletion
and amortization expense, unrealized gains/losses related to the Companys economic hedges, as well
as share-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.
Production
Total natural gas and crude oil production increased 4% to 2.4 Bcfe for the quarter ended September
30, 2011 as compared to the same period a year ago. The production increase was driven by higher
production volume from the Companys non-operated Atlantic Rim properties. The operator of these
properties added additional water injection capacity at the Sun Dog Unit in early 2011, which
resulted in improved production from certain wells. In addition, the Company benefited from higher
working interests in both units for part of the 2011 period as compared to the prior year, as we
completed our purchase of additional working interests in the Sun Dog and Doty Mountain Units in
late July 2010.
At the Catalina Unit, production decreased to 1.2 Bcf for the quarter ended September 30, 2011 from
1.4 Bcf in the third quarter of 2010. Management believes the decrease is primarily the result of
the fields normal production decline. Production from the Mesa Units in the Pinedale Anticline
increased 3% from the third quarter of 2010.
Revenue
Production-related revenue increased 21% to $12,922,000 for the third quarter of 2011, as compared
to $10,665,000 for the third quarter of 2010. The production-related revenue included gains of
$161,000 and $1,715,000 for the quarters ended September 30, 2011 and 2010, respectively, for the
settlement of certain derivative instruments, which are not accounted for as cash flow hedges.
Production-related revenue improved quarter over quarter due to an increase in the Companys
realized natural gas price and the increase in total production. This was offset by the decline in
Catalina Unit production, which also resulted in lower transportation revenue to the Company.
The Companys realized natural gas price increased to $4.64 per Mcf in the third quarter of 2011 as
compared to $3.86 per Mcf in the third quarter of 2010. The realized gas price includes the impact
of realized gains/losses on derivative instruments. Excluding the realized gains/losses on hedges,
the Companys average realized natural gas price was $3.60 and $3.12 for the third quarter of 2011
and 2010, 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 contracts the Company enters into are at no up-front cost to the Company. The table below
summarizes the Companys current open derivative contracts:
Remaining | ||||||||||||||
Contractual | Daily | Price | ||||||||||||
Type of Contract | Volume (mcf) (1) | Production (mcf) | Term | Price | Index (2) | |||||||||
Fixed Price Swap |
488,000 | 8,000 | 01/11-12/11 | $7.07 | CIG | |||||||||
Costless Collar |
150,000 | 5,000 | 12/09-11/11 | $4.50 floor | NYMEX | |||||||||
$9.00 ceiling | ||||||||||||||
Fixed Price Swap |
1,830,000 | 5,000 | 01/12-12/12 | $5.10 | NYMEX | |||||||||
Fixed Price Swap |
3,660,000 | 10,000 | 01/12-12/12 | $5.05 | NYMEX | |||||||||
Fixed Price Swap |
2,190,000 | 6,000 | 01/13-12/13 | $5.16 | NYMEX | |||||||||
Costless Collar |
2,190,000 | 6,000 | 01/13-12/13 | $5.00 floor | NYMEX | |||||||||
$5.35 ceiling | ||||||||||||||
Total |
10,508,000 | |||||||||||||
(1) | As of November 1, 2011. |
|
(2) | CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. NYMEX
refers to quoted prices on the New York Mercantile Exchange. |
Production Costs and Other Expenses
The Companys production costs for the third quarter of 2011 increased 2% to $1.24 per Mcfe as
compared to $1.21 per Mcfe a year ago. The increase in production costs was
primarily driven by higher production costs from the Sun Dog Unit, partially offset by lower repair
and maintenance expense at the Catalina Unit.
The Company continued to hold its general and administrative expenses flat, totaling $1,513,000 and
$1,540,000 for the quarter ended September 30, 2011 and 2010, respectively.
Liquidity
In October 2011, the Company amended its credit facility to increase the revolving line of credit
to $150 million ($60 million borrowing base) and to extend the maturity date of the facility to
October 2016. The Company had $32 million outstanding as of September 30, 2011 with an average
interest rate of 3.18%. The Companys borrowing base was reaffirmed as of October 1, 2011.
Please refer to the Companys Form 10-Q, which will be filed with the Securities and Exchange
Commission on November 3, 2011, for a more detailed discussion of the Companys results.
Operations Update
Atlantic Rim Coal Bed Methane
The Company has completed the drilling of 13 gross (12.72 net) and 2 gross (net) water injection
wells, along with the related gathering system, as part of its 2011 drilling program. The Company
has commenced hydraulic fracturing operations and it expects to complete the fracturing of all
wells by November 15. The addition of the 12.72 net additional wells represents an increase of
approximately 25% in total net producing wells in the Catalina Unit. Upon completion of the 2011
drilling program, the Company will have 111 approved drilling permits remaining for future drilling
locations. There are also 76 additional potential locations for which the Company has not yet
filed for permits.
Atlantic Rim Niobrara
The Company commenced drilling the first Niobrara appraisal well in the Atlantic Rim on October 28,
2011, in which it has a 93% working interest. The well will be drilled vertically to approximately
9400 feet, testing multiple zones including the Shannon, Niobrara (4 potential benches over 1500
feet), Dakota and Frontier formations. The well bore design will allow for either a vertical or
horizontal completion. The Company believes that the suite of logs and sidewall cores for the
appraisal well will provide valuable information on the appropriate completion operations for this
well and additional data for identifying future drilling locations.
The location of this well was selected after reprocessing 25 square miles of 3D seismic and
evaluating log data for wells drilled in the area. The Company is also planning to shoot 15-25
square miles of additional 3D seismic in 2012 to further high-grade the deep and CBM Atlantic Rim
opportunities. The Company has already identified 20 potential
locations of future Niobrara wells, filed for three permits and staked 15 Niobrara locations to
avoid future Bureau of Land Management permitting delays. The locations for future drilling will
be refined after evaluating the data from the appraisal well and the new seismic data from the 2012
seismic program.
High Road Prospect, Powder River Basin, Wyoming
The Company will participate for a 40% before payout working interest (32% after payout) in its
internally generated High Road prospect, a well targeting the Minnelusa formation at 9,700 feet.
The well is approximately 20 miles southeast of Gillette, Wyoming. The well will be operated by
True Oil Company and offsets a well that has produced a cumulative 575,000 barrels of oil. Drilling
is expected to commence in the fourth quarter of 2011. This prospect has four additional locations
and water flood potential if successful.
Earnings Conference Call
Double Eagle will host a conference call to discuss results on Thursday, November 3, 2011 at 11:00
a.m. Eastern Daylight Time (9 a.m. Mountain). Those wanting to listen and participate in the Q&A
portion can call (800) 434-1335 and use conference code 434981#.
A replay of this conference call will be available for one week by calling (800) 704-9804 and using
pass code * then 434981#.
SUMMARY STATEMENT OF OPERATIONS
(In thousands, except per share data)
(In thousands, except per share data)
Three months ended | Nine months ended | |||||||||||||||
September 30, | September 30, | September 30, | September 30, | |||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenues |
||||||||||||||||
Oil and gas sales |
$ | 11,540 | $ | 7,601 | $ | 33,843 | $ | 26,258 | ||||||||
Transportation revenue |
1,221 | 1,349 | 3,674 | 4,238 | ||||||||||||
Price risk management activities |
4,803 | 3,263 | 5,732 | 11,188 | ||||||||||||
Proceeds from the Madden Deep settlement |
| 3,841 | | 3,841 | ||||||||||||
Other income, net |
469 | 108 | 774 | 465 | ||||||||||||
Total revenues |
18,033 | 16,162 | 44,023 | 45,990 | ||||||||||||
Expenses |
||||||||||||||||
Lease operating expenses |
3,018 | 2,828 | 8,361 | 7,167 | ||||||||||||
Production taxes |
1,084 | 1,180 | 3,230 | 3,489 | ||||||||||||
Pipeline operating expenses |
1,016 | 987 | 3,017 | 3,106 | ||||||||||||
Exploration expenses including
dry holes |
67 | 56 | 239 | 122 | ||||||||||||
Impairment of properties and
surrendered leases |
| | 73 | 80 | ||||||||||||
Total expenses |
5,185 | 5,051 | 14,920 | 13,964 | ||||||||||||
Gross Margin Percentage |
71.2 | % | 68.7 | % | 66.1 | % | 69.6 | % | ||||||||
General and administrative |
1,513 | 1,540 | 4,433 | 4,465 | ||||||||||||
Depreciation, depletion and
amortization expense |
4,926 | 4,701 | 14,317 | 13,771 | ||||||||||||
Other expense, net |
(352 | ) | (422 | ) | (997 | ) | (1,172 | ) | ||||||||
Pre-tax income |
6,057 | 4,448 | 9,356 | 12,618 | ||||||||||||
Provision for deferred taxes |
(2,221 | ) | (1,586 | ) | (3,459 | ) | (4,531 | ) | ||||||||
Net Income |
3,836 | 2,862 | 5,897 | 8,087 | ||||||||||||
Preferred stock requirements |
930 | 930 | 2,792 | 2,792 | ||||||||||||
Net income attributable
to common stock |
$ | 2,906 | $ | 1,932 | $ | 3,105 | $ | 5,295 | ||||||||
Net income per common share: |
||||||||||||||||
Basic |
$ | 0.26 | $ | 0.17 | $ | 0.28 | $ | 0.48 | ||||||||
Diluted |
$ | 0.26 | $ | 0.17 | $ | 0.28 | $ | 0.48 | ||||||||
Weighted average
shares outstanding: |
||||||||||||||||
Basic |
11,197,681 | 11,128,802 | 11,187,298 | 11,117,060 | ||||||||||||
Diluted |
11,226,724 | 11,128,802 | 11,207,517 | 11,117,060 | ||||||||||||
SELECTED BALANCE SHEET DATA
(In thousands)
(In thousands)
September 30, | December 31, | |||||||||||
2011 | 2010 | % Change | ||||||||||
Total assets |
$ | 152,461 | $ | 152,517 | 0 | % | ||||||
Balance outstanding on
credit facility |
32,000 | 32,000 | 0 | % | ||||||||
Total stockholders equity |
52,601 | 52,705 | 0 | % |
SELECTED CASH FLOW DATA
(In thousands)
(In thousands)
Nine months ended September 30, | ||||||||||||
2011 | 2010 | % Change | ||||||||||
Net cash provided by
operating activities |
$ | 18,782 | $ | 21,251 | -12 | % | ||||||
Net cash used in
investing activities |
(12,218 | ) | (20,063 | ) | -39 | % | ||||||
Net cash used in
financing activities |
(3,217 | ) | (3,187 | ) | 1 | % |
SELECTED OPERATIONAL DATA
Three months ended, | ||||||||||||
September 30, | September 30, | |||||||||||
2011 | 2010 | % Change | ||||||||||
Total production (Mcfe) |
2,424,907 | 2,340,556 | 4 | % | ||||||||
Average price realized per
Mcfe |
$ | 4.83 | $ | 3.98 | 21 | % |
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 Companys 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 superior to or an alternative to GAAP results or as being comparable to results
reported or forecasted by other companies. Readers should refer to the reconciliation of GAAP net
income with clean aernings for the three and nine months ended September 30, 2011 and 2010,
respectively, contained below.
Reconciliation of Net Income to Clean Earnings
(In thousands, except per share data)
(In thousands, except per share data)
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net Income as reported |
$ | 2,906 | $ | 1,932 | $ | 3,105 | $ | 5,295 | ||||||||
Add back non-cash items: |
||||||||||||||||
Provision for income taxes |
2,221 | 1,586 | 3,459 | 4,531 | ||||||||||||
Depreciation, depletion,
amortization and accretion
expense |
4,969 | 4,737 | 14,444 | 13,862 | ||||||||||||
Non-cash gain on derivatives (1) |
(4,575 | ) | (1,548 | ) | (4,993 | ) | (8,030 | ) | ||||||||
Share-based compensation expense |
242 | 230 | 767 | 726 | ||||||||||||
Impairments and abandonments |
| | 73 | 80 | ||||||||||||
Other non-cash items |
(70 | ) | (71 | ) | (211 | ) | (213 | ) | ||||||||
Clean Earnings |
$ | 5,693 | $ | 6,866 | $ | 16,644 | $ | 16,251 | ||||||||
Clean Earnings per Share |
$ | 0.51 | $ | 0.62 | $ | 1.48 | $ | 1.46 |
(1) | Non-cash gain on derivatives is comprised of an unrealized loss (gain) from the
Companys mark-to-market derivative instruments (both commodity contracts and interest
rate swaps), resulting from recording the instruments at fair value at each period end. |
About Double Eagle
Double Eagle Petroleum Co. explores for, develops, and sells natural gas and crude oil, with
natural gas constituting more than 95% of its production and reserves. The Company currently has
development activities and opportunities in its Atlantic Rim coal bed methane and in the Pinedale
Anticline in Wyoming. Also, exploration potential exists in its Niobrara acreage in Wyoming and
Nebraska, which totals over 70,000 net acres.
# # #
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 Companys 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
John Campbell, IR
(303) 794-8445
www.dble.com