CALGARY, ALBERTA–(Marketwired – Feb. 12, 2014) – Delphi Energy Corp. (TSX:DEE) (“Delphi” or the “Company”) is pleased to report its crude oil and natural gas reserves information for the year ended December 31, 2013.
2013 was a year of transformation for Delphi with a step change in well performance experienced at Delphi’s Bigstone liquids-rich Montney development project. Delphi brought on production five horizontal Montney wells stimulated with a new completion technique during the year (four of them drilled with extended-reach horizontal laterals and completed with 30 fracture stages). The slickwater hybrid fracs, which had not previously been used in the greater Bigstone area, have proven to be a key driver for Delphi in unlocking significant value from the Montney formation at Bigstone. The Company’s December 31, 2013 reserves report, evaluated by GLJ Petroleum Consultants Ltd. (“GLJ Report”), recognizes the production performance resulting from this completion technique.
Highlights
| (1) | Operating netback is calculated by subtracting royalties, operating and transportation costs from revenues. |
| (2) | Recycle ratio is calculated as operating netback per boe divided by FD&A costs, including FDC, per boe. |
| (3) | Capital invested of $70.4 million; change in FDC of $120.2 million; acquisition costs of $13.8 million; reserve extensions, improved recovery and technical revisions of 23.1 million boe. |
Corporate Reserves Summary
GLJ Petroleum Consultants Ltd. (“GLJ”), the Company’s independent petroleum engineering firm, has evaluated Delphi’s crude oil, natural gas and natural gas liquids reserves as at December 31, 2013 and prepared a reserves report in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” and the “Canadian Oil and Gas Evaluation Handbook”. GLJ’s price forecast dated January 1, 2014 was used in the evaluation.
The following is summary reserves information detailed in the GLJ Report at December 31, 2013:
| December 31, 2013 | ||||||
| Light and Medium Oil |
Natural Gas | Natural Gas Liquids |
Total | % of | ||
| Reserves(1) | (mbbls) | (mmcf) | (mbbls) | (mboe)(2) | P+P | |
| Proved | ||||||
| Developed Producing | 394 | 68,108 | 3,197 | 14,943 | 24 | |
| Developed Non-producing | – | 8,983 | 411 | 1,908 | 3 | |
| Undeveloped | 171 | 80,059 | 5,777 | 19,291 | 31 | |
| Total Proved | 565 | 157,150 | 9,385 | 36,142 | 59 | |
| Probable | 287 | 112,301 | 6,515 | 25,520 | 41 | |
| Total Proved Plus Probable | 853 | 269,451 | 15,901 | 61,662 | 100 | |
| (1) | Delphi’s reserves represent the operated and non-operated working interest share of reserves before deduction of royalties and include any royalty interests of the Company. |
| (2) | Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil (6:1). |
Net Present Value of Future Net Revenue
The estimated future net revenues associated with Delphi’s reserves at December 31, 2013, based on the GLJ January 1, 2014 price forecast, are summarized in the following table.
| Net Present Values of Future Net Revenue Before Income Taxes Discounted at (%/year) | |||||||||
| Unit Value Before Income Tax Discounted at 10%/year(2) | |||||||||
| ($ thousands)(1) | 0% | 5% | 10% | 15% | 20% | ($/boe) | ($/mcfe) | ||
| Proved | |||||||||
| Developed Producing | 268,323 | 221,195 | 189,970 | 167,750 | 151,082 | 15.54 | 2.59 | ||
| Developed Nonproducing | 35,403 | 24,996 | 18,879 | 14,927 | 12,184 | 11.18 | 1.86 | ||
| Undeveloped | 384,707 | 247,324 | 170,244 | 122,502 | 90,666 | 10.11 | 1.69 | ||
| Total Proved | 688,433 | 493,515 | 379,093 | 305,179 | 253,931 | 12.33 | 2.05 | ||
| Total Probable | 606,675 | 325,071 | 204,832 | 142,881 | 106,413 | 9.41 | 1.57 | ||
| Total Proved Plus Probable | 1,295,108 | 818,586 | 583,925 | 448,060 | 360,345 | 11.12 | 1.85 | ||
| (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. |
Future Development Costs
The following table provides the future development costs, undiscounted, included in the GLJ Report for both proved and proved plus probable reserves. The scheduled future development costs are funded by the operating income forecast during those years in the GLJ Report.
| ($ thousands) | 2014 | 2015 | 2016 | 2017 | 2018 | Rem | Total |
| Total Proved | 63,228 | 79,222 | 40,804 | 12,639 | 2,868 | 5,653 | 204,414 |
| Total Proved Plus Probable | 63,204 | 88,883 | 113,606 | 18,561 | 30,302 | 7,353 | 321,909 |
Forecast Prices
The following is a summary of GLJ’s January 1, 2014 price forecast used in the evaluation.
| Natural Gas | Oil | ||||||
| AECO/NIT | NYMEX | Edmonton | NYMEX | Pentanes Plus | Exchange | ||
| Spot | Henry Hub | Light | WTI | Edmonton | Inflation | Rate | |
| Year | $CDN/MMBtu | $US/MMBtu | $CDN/bbl | $US/bbl | $CDN/bbl | % | $US/$CDN |
| 2014 | 4.03 | 4.25 | 92.76 | 97.50 | 105.20 | 2.0 | 0.95 |
| 2015 | 4.26 | 4.50 | 97.37 | 97.50 | 107.11 | 2.0 | 0.95 |
| 2016 | 4.50 | 4.75 | 100.00 | 97.50 | 107.00 | 2.0 | 0.95 |
| 2017 | 4.74 | 5.00 | 100.00 | 97.50 | 107.00 | 2.0 | 0.95 |
| 2018 | 4.97 | 5.25 | 100.00 | 97.50 | 107.00 | 2.0 | 0.95 |
| 2019 | 5.21 | 5.50 | 100.00 | 97.50 | 107.00 | 2.0 | 0.95 |
| 2020 | 5.33 | 5.63 | 100.77 | 98.54 | 107.82 | 2.0 | 0.95 |
| 2021 | 5.44 | 5.74 | 102.78 | 100.51 | 109.97 | 2.0 | 0.95 |
| 2022 | 5.55 | 5.86 | 104.83 | 102.52 | 112.17 | 2.0 | 0.95 |
| 2023 | 5.66 | 5.97 | 106.93 | 104.57 | 114.41 | 2.0 | 0.95 |
| 2024+ | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | 2.0 | 0.95 |
Reserves(1) Reconciliation
The following reconciliation of Delphi’s reserves compares changes in the Company’s reserves at December 31, 2012 to the reserves at December 31, 2013, each evaluated in accordance with National Instrument 51-101 definitions.
| Light and | Associated and | |||
| Medium | Non-Associated | Natural Gas | Total Oil | |
| Crude Oil | Gas | Liquids | Equivalent | |
| Proved | (mbbls) | (mmcf) | (mbbls) | (mboe) |
| December 31, 2012 | 691 | 109,368 | 4,876 | 23,796 |
| Extensions and Improved Recovery | – | 56,392 | 4,471 | 13,869 |
| Technical Revisions | (13) | 4,707 | 752 | 1,524 |
| Discoveries | – | – | – | – |
| Acquisitions | – | – | – | – |
| Dispositions | – | (19) | (1) | (5) |
| Economic Factors | – | (119) | (14) | (34) |
| Production | (113) | (13,178) | (698) | (3,008) |
| December 31, 2013 | 565 | 157,150 | 9,385 | 36,142 |
| Light and | Associated and | |||
| Medium | Non-Associated | Natural Gas | Total Oil | |
| Crude Oil | Gas | Liquids | Equivalent | |
| Probable | (mbbls) | (mmcf) | (mbbls) | (mboe) |
| December 31, 2012 | 326 | 86,427 | 4,536 | 19,267 |
| Extensions and Improved Recovery | – | 21,726 | 1,462 | 5,083 |
| Technical Revisions | (39) | 4,553 | 529 | 1,250 |
| Discoveries | – | – | – | – |
| Acquisitions | – | – | – | – |
| Dispositions | – | (4) | (0) | – |
| Economic Factors | – | (402) | (12) | (79) |
| Production | – | – | – | – |
| December 31, 2013 | 287 | 112,301 | 6,515 | 25,520 |
| Light and | Associated and | |||
| Medium | Non-Associated | Natural Gas | Total Oil | |
| Crude Oil | Gas | Liquids | Equivalent | |
| Proved Plus Probable | (mbbls) | (mmcf) | (mbbls) | (mboe) |
| December 31, 2012 | 1,017 | 195,795 | 9,412 | 43,062 |
| Extensions and Improved Recovery | – | 78,118 | 5,933 | 18,952 |
| Technical Revisions | (51) | 9,260 | 1,281 | 2,774 |
| Discoveries | – | – | – | – |
| Acquisitions | – | – | – | – |
| Dispositions | – | (23) | (2) | (5) |
| Economic Factors | – | (521) | (26) | (113) |
| Production | (113) | (13,178) | (698) | (3,008) |
| December 31, 2013 | 853 | 269,451 | 15,901 | 61,662 |
| (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. |
Finding and Development Costs
Finding and development costs in 2013, 2012, and averages for the three most recent financial years, were as follows:
| 2013 | 2012 | 2011 – 2013 | ||||
| Proved | Proved Plus Probable |
Proved | Proved Plus Probable |
Proved | Proved Plus Probable |
|
| Capital ($ thousands) | ||||||
| Exploration and Development (“E&D”) Costs(1) | 71,956 | 71,956 | 83,728 | 83,728 | 270,162 | 270,162 |
| Change in FDC related to E&D | 96,780 | 121,472 | 31,644 | 65,642 | 129,897 | 197,226 |
| Total E&D Costs | 168,736 | 193,428 | 115,372 | 149,370 | 400,058 | 467,388 |
| Acquisition Costs(1) | 13,664 | 13,664 | 139 | 139 | 14,077 | 14,077 |
| Disposition Proceeds(1) | (3,319) | (3,319) | (34,664) | (34,664) | (50,857) | (50,857) |
| Change in FDC related to Acquisitions and Dispositions (“A&D”) | – | – | (8,299) | (8,299) | (9,461) | (10,234) |
| Total Net A&D Costs | 10,345 | 10,345 | (42,823) | (42,823) | (46,240) | (47,013) |
| Total Costs | 179,081 | 203,773 | 72,548 | 106,546 | 353,818 | 420,374 |
| Reserves (mboe) | ||||||
| Reserve Additions(2) | 15,359 | 21,613 | 4,172 | 9,134 | 25,413 | 40,197 |
| Acquisitions and Dispositions | (5) | (5) | (2,421) | (3,225) | (2,716) | (3,782) |
| Total Reserve Additions | 15,354 | 21,608 | 1,751 | 5,909 | 22,697 | 36,415 |
| Finding and Development Costs ($/boe) | ||||||
| E&D, excluding change in FDC | 4.68 | 3.33 | 20.07 | 9.17 | 10.63 | 6.72 |
| E&D, including change in FDC related to E&D | 10.99 | 8.95 | 27.66 | 16.35 | 15.74 | 11.63 |
| Exploration, Development, Acquisitions and Dispositions, including change in FDC | 11.66 | 9.43 | 41.44 | 18.03 | 15.59 | 11.54 |
| Total exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect the total cost of reserve additions in that year. | |
| (1) | Unaudited. |
| (2) | Includes extensions and improved recovery, technical revisions, discoveries, and economic factors. |
Net Asset Value
The estimated net asset value of the Company at December 31, 2013 has been calculated using the before tax, net present value of reserves discounted at 10 percent as follows:
| ($ thousands except share count and per share value) | |
| Estimated future net revenues of proved plus probable reserves(1) | 583,925 |
| Undeveloped land(2) | 102,879 |
| Mark-to-market value of hedging contracts(3) | (5,856) |
| In-the-money option proceeds(4) | 11,520 |
| Total asset value | 692,468 |
| Total debt plus working capital deficiency (unaudited) | (138,340) |
| Net asset value | 554,128 |
| Common shares outstanding and in-the-money options | 162,736,548 |
| Net asset value per share | 3.41 |
| (1) | Discounted at 10 percent and before deducting future income tax expenses and reclamation costs. The Company estimates it has approximately $364.3 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. as at December 31, 2013. Fair market value was determined in accordance with NI 51-101 5.9(1)(e). At December 31, 2013 Delphi had an interest in 219,878 net acres of undeveloped land. |
| (3) | Financial positions at December 31, 2013. Delphi had no physical contracts at December 31, 2013. |
| (4) | In-the-money option proceeds are based on the closing December 31, 2013 share price of $1.94. |
Operations Update
Since the end of 2013, Delphi has added an additional well (0.98 net) to its production base by bringing the 15-21-60-23W5 well on production in early February. Before the end of the winter drilling season, the Company expects to bring two additional wells (2.0 net) on production for a total of eight (7.78 net) slickwater hybrid fracture stimulated wells.
The next well to be brought on-stream will be the 13 – 30 – 60-22W5 (“13-30”) well where the Company has finished completion and clean-up flow operations. The 13-30 Montney well was drilled to a total depth of 5,419 metres with a horizontal lateral length of 2,593 metres and stimulated with a 30 stage slickwater hybrid completion. The well was produced on clean-up over a five day period, recovering approximately 27 percent of the initial load frac water and is now shut-in to equip the well for production. After running production tubing, the well produced over the final 24 hours at an average rate of 7.5 million cubic feet per day (“mmcf/d”) of raw gas, 976 barrels per day (“bbls/d”) of wellhead condensate (130 bbls/mmcf of raw gas) and approximately 1,010 bbls/d of load frac water. With an estimated plant NGL yield of 39 bbls/mmcf of raw gas, total production for the 13-30 well over the final 24 hour period was approximately 2,381 barrels of oil equivalent per day (“boe/d”), (53 percent field and plant NGL’s). The well is expected to commence production in March and consistent with the previous slickwater fracture stimulated wells, will continue to recover load frac water over the next few months.
The table below illustrates the significant impact the slickwater hybrid fracturing technique has had on well performance at Bigstone in comparison to smaller conventional frac methods. Well performance during the initial 30 days of production has almost doubled, as observed in the 15-30 and 16-30 production performance where the two wells are approximately 400 metres (one spacing unit) apart. Longer term production performance has tripled when observing production rates after 180 days. Wellhead condensate production and yields have also improved by two to three times. Numbers in bold indicate new data since the following table was previously released.
| Initial Production (IP) Rate Well Performance(1) | |||||||||
| Well(2) | HZ Length (metres) |
Number of Fracs |
Initial Test Rate(3) (boe/d) |
IP30 Total Sales (boe/d) |
IP30 FCond Rate (bbls/d) |
IP30 Total NGL Yield (bbl/mmcf) |
IP180 Total Sales (boe/d) |
Total Sales on Day 180 (boe/d) |
|
| Conventional Fracs (original completion technique) | |||||||||
| 16-30 | #1 | 2,760 | 20 | 3,047 | 1,099 | 273 | 104 | 558 | 259 |
| 05-02 | #2 | 3,005 | 20 | 2,390 | 969 | 170 | 80 | 479 | 250 |
| 14-23 | #3 | 2,238 | 20 | 3,715 | 1,570 | 223 | 70 | 635 | 291 |
| Slickwater Fracs (new completion technique) | |||||||||
| 15-10 | #4 | 1,424 | 20 | 957 | 991 | 194 | 86 | 660 | 421 |
| 11-17 | S.BS Expl(4) | 1,848 | 26 | 962 | |||||
| Type Well | 2,400 – 3,000 | 30 | 1,219 | 288 | 85 | 899 | 646 | ||
| 15-24 | #7 | 2,328 | 30 | 1,585 | 1,387 | 454 | 136 | ||
| 10-27 | #5 | 2,407 | 30 | 2,350 | 1,815 | 582 | 133 | 1,364 | 928 |
| 13-30 | #10 | 2,593 | 30 | 2,381 | |||||
| 16-23 | #6 | 2,809 | 30 | 1,943 | 1,781 | 465 | 108 | 1,235 | 842 |
| 15-21 | #9 | 2,886 | 30 | 1,686 | |||||
| 15-30 | #8 | 3,014 | 30 | 2,953 | 2,076 | 566 | 113 | ||
| (1) | Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. |
| (2) | Slickwater frac wells numbered chronologically and sorted on HZ length. |
| (3) | Final continuous 24 hour rate on clean-up test. 100% of load frac oil had not been recovered for wells 1, 2, 3. |
| (4) | Initial Exploration Well on Delphi’s South Bigstone Lands |
To handle the growing Montney production volumes, the Company is continuing with construction to expand its 7-11 facility. The expanded facility will handle 45 mmcf/d of raw gas as well as increased field condensate volumes with the installation of larger inlet separation, increased condensate storage tank capacity and additional compression. The Company expects a facility shut-in of approximately five to seven days in the latter part of February in order to complete the expansion and have it back on-stream by the end of the month.
Outlook
The Company has achieved a step change in well performance from its extended-reach horizontal lateral sections stimulated with the slickwater hybrid fracturing technique as compared to conventional gelled oil fracs. The wells continue to exceed the Company’s initial type curve expectations. Given the improved well performance to date, Delphi plans to re-evaluate its base type curve assumptions after the winter drilling program is completed.
Delphi is maintaining its current market guidance for 2014 until a review of the well results of the winter drilling program are completed. Corporate production is forecast to grow 20 percent compared to 2013, predominantly from a Montney focused capital program with its superior netbacks, resulting in expected cash flow growth of 49 percent. Delphi is estimating production to average 9,500 to 10,000 boe/d on a net capital program of $67 to $72 million, drilling a total of seven Montney horizontal wells at Bigstone. The previously announced GOR funding, expected funds from operations for 2014 and the Company’s credit facility provide the financial resources for the Company to carry out its planned 2014 capital program. Total debt at year end 2014 is expected to be between $145.0 and $150.0 million versus between $135.0 and $140.0 million at the end of 2013. The total debt to funds flow ratio is forecast to drop to 2.2 times in the fourth quarter of 2014 and reach a targeted 1.5 times in 2015. Delphi expects AECO natural gas prices to average approximately Cdn. $3.35 per mcf and Edmonton light oil prices to average approximately Cdn. $93.50 per barrel, resulting in cash flow for 2014 of approximately $55.0 to $60.0 million. Currently, the Company has approximately 66 percent of its natural gas production hedged at an average price of $3.68 per mcf for 2014 and approximately 27 percent of its crude oil and condensate production hedged at a floor price of Cdn $96.03 per barrel for the first half of 2014.
Delphi’s business plan contemplates production growth to 20,000 boe/d by 2017, with targeted annual production per share growth of 25 percent and annual cash flow per share growth of 45 percent. The contemplated 50 well drilling program represents less than half of the current development drilling inventory on approximately 50 percent of Delphi’s current Montney undeveloped land holdings of 124 gross sections (110 net). The Company now has a current project inventory that will provide economic growth beyond a 10-year horizon. Over this time period, the Company’s balance sheet is forecast to continually strengthen, with internally generated cash flow funding the majority of the capital expenditures on a go forward basis.
Delphi anticipates releasing its audited financial statements for the year ended December 31, 2013 on March 19, 2014 and its Annual Information Form by March 28, 2014, 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, 2013, 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, 2013 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, 2013 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.
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Forward-Looking Statements. This release 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. Mboe or mboe represents one thousand boe.
Tables in this press release may not add due to rounding.
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”, “operating netbacks” “cash netbacks” 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 cash flow from operating activities before accretion on long-term debt, decommissioning expenditures and changes in non-cash working capital. 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 the fair value of financial instruments plus the long term portion of the restricted share units (“RSU”). Net debt is used by management to monitor remaining availability under its credit facilities. Operating netbacks have been defined as revenue less royalties, transportation and operating costs. Cash netbacks have been defined as operating netbacks less interest and general and administrative costs. Netbacks are generally discussed and presented on a per boe basis.
Delphi Energy Corp.
300, 500 – 4 Avenue S.W.
Calgary, Alberta, T2P 2V6
Email: info@delphienergy.ca
Website: www.delphienergy.ca
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