Double Eagle Petroleum Co. Reports Full-Year 2013 Financial Results
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 |
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.
WANT YOUR COMPANY'S NEWS FEATURED ON PRNEWSWIRE.COM?
Newsrooms &
Influencers
Digital Media
Outlets
Journalists
Opted In
Share this article