CALGARY, ALBERTA--(Marketwire - Feb 28, 2013) - Delphi Energy Corp. (DEE.TO) ("Delphi" or the "Company") is pleased to report its crude oil and natural gas reserves information for the year ended December 31, 2012.
2012 was a year of significant achievements for Delphi with the initial development of its Montney play at Bigstone. The Company brought three horizontal Montney wells on production through 100 percent owned and constructed facilities and associated gas gathering systems during the year. Success on this play has translated into significant reserve additions.
- Replaced 2012 production of 8,276 barrels of oil equivalent per day ("boe/d") (3.0 million boe) by 2.0 times with total proved plus probable reserve additions of 11.9 million boe and dispositions and revisions of 5.9 million boe;
- Increased total proved plus probable reserves by seven percent to 43.0 million boe compared to 2011. Total proved reserves decreased by five percent to 23.8 million boe compared to 25.1 million boe in 2011;
- Increased total proved plus probable Bigstone Montney reserves by 233 percent to 11.0 million boe compared to 3.3 million boe in 2011;
- Achieved finding and development costs ("F&D") including changes in future development costs ("FDC") of $16.35 per boe for total proved plus probable reserves. Including dispositions in the year, finding, development and acquisition costs ("FD&A") including changes in FDC were $18.03 per boe for total proved plus probable reserves;
- Increased total proved plus probable reserve liquids (light and medium crude oil and natural gas liquids) weighting to 24.2 percent in 2012 from 22.9 percent in 2011;
- Successfully drilled and completed two additional Montney horizontal wells in the first quarter of 2013, utilizing a slickwater hybrid frac system resulting in a combined final test rate of 13.0 million cubic feet per day ("mmcf/d") of raw gas and 1,100 barrels per day ("bbls/d") of wellhead condensate.
GLJ Petroleum Consultants Ltd. ("GLJ"), the Company''s independent petroleum engineering firm, has evaluated Delphi''s crude oil, natural gas and natural gas liquids reserves as at December 31, 2012 and prepared a reserves report in accordance with National Instrument 51- 101 "Standards of Disclosure for Oil and Gas Activities" and the "Canadian Oil and Gas Evaluation Handbook".
To view the Reserves Summary graph, please visit the following link: http://media3.marketwire.com/docs/228dee_graph.jpg.
The following is summary reserves information detailed in the GLJ reserves report at December 31, 2012:
|December 31, 2012|
|Light and||Natural Gas||Natural Gas||Total|
|Medium Oil||Liquids||% of|
|Total Proved Plus Probable||1,017||195,795||9,412||43,062||100|
|(1)||Delphi''s reserves represent the operated and non-operated working interest share of reserves before deduction of royalties and include any royalty interests of the Company.|
|(2)||Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil (6:1).|
Net Present Value of Reserves
The estimated future net revenues associated with Delphi''s reserves at December 31, 2012, based on the GLJ January 1, 2013 price forecast, are summarized in the following table.
| Net Present Values of Future Net Revenue Before Income
Taxes Discounted at (%/year)
|Unit Value Before
|Total Proved Plus Probable||841.6||521.2||362.9||271.5||213.1||10.00||1.67|
|(1)||The estimated future net revenues are before the deduction of estimated future site restoration costs but are reduced for estimated future abandonment costs for reserve wells and estimated capital for future development associated with the reserves. The estimated values disclosed do not necessarily represent fair market value.|
|(2)||Unit values are calculated using net reserves defined as Delphi''s working interest share after deduction of royalty obligations plus Delphi''s royalty interests.|
The following reconciliation of Delphi''s reserves compares changes in the Company''s reserves at December 31, 2011 to the reserves at December 31, 2012, each evaluated in accordance with National Instrument 51-101 definitions.
|)||Natural Gas Liquids
|)||Total Oil Equivalent
|December 31, 2011||1,913||114,791||4,029||25,074|
|Extensions and Improved Recovery||-||19,598||1,525||4,791|
|December 31, 2012||691||109,368||4,876||23,796|
|)||Natural Gas Liquids
|)||Total Oil Equivalent
|December 31, 2011||765||71,072||2,498||15,108|
|Extensions and Improved Recovery||-||29,670||2,183||7,128|
|December 31, 2012||326||86,427||4,536||19,267|
|Proved Plus Probable||Light and
|)||Natural Gas Liquids
|)||Total Oil Equivalent
|December 31, 2011||2,678||185,862||6,527||40,182|
|Extensions and Improved Recovery||-||49,268||3,707||11,919|
|December 31, 2012||1,017||195,795||9,412||43,062|
Finding and Development Costs
Finding and development costs in 2012, 2011, and averages for the three most recent financial years, were as follows:
|Proved||Proved Plus Probable||Proved||Proved Plus Probable||Proved||Proved Plus Probable|
|Capital (unaudited) ($ thousands)|
|Exploration and Development ("E&D") Costs||83,728||83,728||114,477||114,477||303,155||303,155|
|Change in Future Development Costs ("FDC") related to E&D||31,644||65,642||1,473||10,112||65,995||121,800|
|Total E&D Costs||115,372||149,370||115,950||124,589||369,150||424,955|
|Acquisition Costs (unaudited)||139||139||273||273||431||431|
|Disposition Costs (unaudited)||(34,664||)||(34,664||)||(12,873||)||(12,873||)||(47,783||)||(47,783||)|
|Change in FDC related to Acquisitions and Dispositions ("A&D")||(8,299||)||(8,299||)||(1,162||)||(1,935||)||(9,638||)||(11,491||)|
|Total A&D Costs||(42,823||)||(42,823||)||(13,762||)||(14,535||)||(56,990||)||(58,843||)|
|Acquisitions and Dispositions||(2,421||)||(3,225||)||(291||)||(551||)||(2,993||)||(4,267||)|
|Total Reserve Additions||1,751||5,909||5,591||8,899||14,997||24,890|
|Finding and Development Costs ($/boe)|
|E&D, excluding change in FDC||20.07||9.17||19.46||12.11||16.85||10.40|
|E&D, including change in FDC related to E&D||27.66||16.35||19.71||13.18||20.52||14.57|
|Exploration, Development, Acquisitions and Dispositions, including change in FDC||41.45||18.03||18.28||12.37||20.81||14.71|
Total exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect the total cost of reserve additions in that year.
(1) Includes extensions and improved recovery, technical revisions and economic factors.
Net Asset Value
The estimated net asset value of the Company at December 31, 2012 has been calculated using before tax, net present value of reserves discounted at ten percent as follows:
|($thousands except share count and per share value)|
|Estimated future net revenues of proved plus probable reserves (1)||362,860|
|Undeveloped land (2)||65,319|
|Mark-to-market value of hedging contracts(3)||(3,789||)|
|In-the-money option proceeds (4)||573|
|Total asset value||424,963|
|Bank debt plus working capital deficiency (unaudited)||(92,815||)|
|Net asset value||332,148|
|Common shares outstanding and in-the-money options||153,896,798|
|Net asset value per share||2.16|
|(1)||Discounted at 10 percent and before deducting future income tax expenses and reclamation costs. The Company estimates it has approximately $315 million of tax deductions available to offset future taxable income.|
|(2)||Undeveloped land was determined by an independent land valuation report by Seaton-Jordan & Associates Ltd. Fair value was determined according to paragraph (e), subsection (1), Section 5.9 of NI 51-101 and further detailed in Companion Policy 51-101CP. At December 31, 2012 Delphi had an interest in 196,543 net acres of undeveloped land.|
|(3)||Includes both physical and financial positions at December 31, 2012.|
|(4)||In-the-money option proceeds are based on the closing December 31, 2012 share price of $1.14.|
Delphi is also pleased to provide the following operations update.
At East Bigstone, Delphi recently brought on production its fourth horizontal Montney well. The 15-10-60-23W5 well was drilled during the fourth quarter of 2012 to a total depth of 4,455 metres with a horizontal lateral length of 1,424 metres. The well was completed with a 20 stage slickwater hybrid completion. Total drill and completion costs are estimated to be $8.3 million. During the seven day clean-up flow period, prior to running production tubing, the well had recovered approximately 29 percent of the initial load frac water volumes. The well was brought on production on January 27, 2013 through the Company''s 100 percent owned compression and dehy facility and over the first 12 full days on production, averaged 4.2 mmcf/d of raw gas (rate on the last full day of production was consistent with the 12 day average), with associated field condensate production over the same period averaging 50 barrels per million cubic feet ("bbls/mmcf") of raw gas. Including plant recovered liquids (estimated to be 36 bbls/mmcf raw gas), the Company estimates total natural gas liquids ("NGL''s) production to be 86 bbls/mmcf of raw gas production (100 bbls/mmcf sales) consisting of 70 percent field and plant recovered condensate. Total production rate over this initial period was approximately 990 boe/d (37 percent NGL''s).
Initial results of this well, and particularly the new completion design employed, are very encouraging based on the shallower initial declines exhibited on the 15-10 well (as compared to the first three wells drilled in East Bigstone which were completed with gelled oil fracs), as well as the higher initial field condensate to gas production ratio.
The Company has just concluded fracturing operations on its second horizontal Montney well of the winter season in East Bigstone. The 10-27-60-23W5 well was drilled during the first quarter of 2013 to a total depth of 5,260 metres with a horizontal lateral of 2,407 metres. The well was successfully completed with a 30 stage slickwater hybrid completion. The well has been flowing on clean-up over the past 4.5 days, recovering approximately 21 percent of the initial load frac water and is now shut-in to equip the well for production. Over the past 4.5 days the well has flowed at an average rate of approximately 8.9 mmcf/d of raw gas and approximately 800 bbls/d of wellhead condensate (90 bbls/mmcf of raw gas). Over the last 24 hours the well has produced at an average rate of 8.8 mmcf/d of raw gas and approximately 750 bbls/d of wellhead condensate (85 bbls/mmcf of raw gas), at a flowing pressure of approximately 530 psi. With a similar plant NGL yield of 36 bbls/mmcf of raw gas, total production over this last 24 hour period was approximately 2,350 boe/d (45 percent NGL''s).
The Company is currently drilling its third horizontal Montney well of the winter season in East Bigstone with a planned bottom hole location at 16-23-60-23W5. The horizontal lateral is planned for a total of 2,900 metres and will also be completed with the same 30 stage slickwater hybrid frac system.
Delphi expects to commence drilling operations after spring break-up on the previously announced farm-in lands to earn a 75 percent interest in the Montney and Nordegg on the 32.5 section land block. After earning, the Company will hold an average working interest of 85 percent in 78.5 sections of prospective Montney and Nordegg rights in the Bigstone area.
The Company''s Montney production at East Bigstone was shut-in on February 12, 2013 due to unscheduled pipeline repairs on a third-party main gathering pipeline. The outage is estimated to last until the first week of March.
Delphi anticipates releasing its audited financial statements for the year ended December 31, 2012 on March 20, 2013 and its Annual Information Form by March 29, 2013, which will include all required National Instrument 51-101 reserves disclosure.
Certain financial and operating information included in this press release for the quarter and year ended December 31, 2012, such as, but not limited to, finding and development costs, production information, net asset value calculations, are based on unaudited financial results for the year ended December 31, 2012 and are subject to the same limitations as discussed under forward-looking statements outlined at the end of this release. These estimate amounts may change upon completion of the audited financial statements for the year ended December 31, 2012 and those changes may be material.
Delphi Energy is a Calgary-based company that explores, develops and produces oil and natural gas in Western Canada. The Company is managed by a proven technical team. Delphi trades on the Toronto Stock Exchange under the symbol DEE.
Forward-Looking Statements. This management discussion and analysis contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", may", "will", "should", believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.
More particularly and without limitation, this management discussion and analysis contains forward looking statements and information relating to the Company''s risk management program, petroleum and natural gas production, future funds from operations, capital programs, commodity prices, costs and debt levels. The forward-looking statements and information are based on certain key expectations and assumptions made by Delphi, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the capital availability to undertake planned activities and the availability and cost of labour and services.
Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect the Company''s operations or financial results are included in reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). The forward-looking statements and information contained in this press release are made as of the date hereof for the purpose of providing the readers with the Company''s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Basis of Presentation. For the purpose of reporting production information, reserves and calculating unit prices and costs, natural gas volumes have been converted to a barrel of oil equivalent (boe) using six thousand cubic feet equal to one barrel. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with the Canadian Securities Administrators'' National Instrument 51-101 when boes are disclosed. Boes may be misleading, particularly if used in isolation.
As per CSA Staff Notice 51-327 initial test results and initial production performance should be considered preliminary data and such data is not necessarily indicative of long-term performance or of ultimate recovery.
Non-IFRS Measures. The release contains the terms "funds from operations", "funds from operations per share", "net debt", "cash operating costs" and "netbacks" which are not recognized measures under IFRS. The Company uses these measures to help evaluate its performance. Management considers netbacks an important measure as it demonstrates its profitability relative to current commodity prices. Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company''s ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from operations is a non-IFRS measure and has been defined by the Company as net earnings plus the add back of non-cash items (depletion and depletion, accretion, stock-based compensation, deferred income taxes and unrealized gain/(loss) on financial instruments) and excludes the change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding consistent with the calculation of earnings per share. Delphi''s determination of funds from operations may not be comparable to that reported by other companies nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. The Company has defined net debt as the sum of long term debt plus/minus working capital excluding the current portion of deferred income taxes and fair value of financial instruments. Net debt is used by management to monitor remaining availability under its credit facilities. Cash operating costs have been defined as the sum of operating expenses, transportation expense, general and administrative expenses and cash finance costs.
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