CALGARY, ALBERTA–(Marketwired – Feb. 29, 2016) – Delphi Energy Corp. (“Delphi” or the “Company”) (TSX:DEE) is pleased to report its crude oil and natural gas reserves information for the year ended December 31, 2015.
While remaining focused on its large-scale Montney project at Bigstone, the Company successfully streamlined its business in 2015 through two major asset dispositions. The dispositions represented approximately 26 percent of the Company’s total proved plus probable reserves at December 31, 2014, and 2,600 barrels of oil equivalent per day (“boe/d”) or 26 percent of the Company’s production capability in 2015 and resulted in a 30 percent reduction in debt to $121.7 million at December 31, 2015.
At December 31, 2015, the Montney reserves at Bigstone represent approximately 95 percent of the Company’s total proved and total proved plus probable reserves and approximately 90 percent of its current production capability.
- Achieved average corporate production in 2015 of 9,469 boe/d with the Montney representing 70 percent or 6,590 boe/d. Fourth quarter corporate production averaged 8,814 boe/d with the Montney representing 79 percent or 6,924 boe/d;
- Invested capital of $50.6 million drilling 6.0 gross (5.3 net) Montney horizontal wells during 2015. The capital program was directed at infill locations to minimize capital spending on infrastructure. All Montney locations drilled were previously booked as undeveloped locations. Disposition proceeds during the year totaled $60.7 million;
- Reduced total future development costs (“FDC”) for total proved and total proved plus probable reserves by $122.1 million and $147.6 million, respectively, as a result of dispositions, reserve category reclassifications resulting from the infill drilling program, undeveloped locations removed from the report due to economic considerations and realized capital cost reductions;
- Added 5.4 million boe (3.9 million boe after technical revisions) of proved producing reserves through its 2015 capital program. Excluding reserves associated with the dispositions, the Company replaced 110 percent of the 3.5 million boe produced in 2015. Proved producing Montney reserves increased 19 percent to 11.6 million boe;
- Achieved corporate finding and development costs (“F&D”), including changes in FDC, of $12.04 per boe for proved producing reserves compared to the 2013-15 three year average of $14.54 per boe. With a realized operating netback(1) of $16.45 per boe, achieved a proved producing recycle ratio(2) of 1.4 times;
- For the Montney program, Delphi achieved F&D costs, including changes in FDC, of $10.12 per boe for proved producing reserves compared to the 2013-15 three year average of $13.41 per boe; and
- Achieved gross average drill and complete costs on the 6 wells drilled in 2015 of $8.1 million per well compared to a gross average of $10.2 million per well in 2014. Costs have been further reduced to an average of $7.0 million on the most recent three wells.(1) Operating netback is calculated by subtracting royalties, operating and transportation costs from revenues and includes hedging gains or losses.
(2) Recycle ratio is calculated as operating netback per boe divided by F&D or FD&A costs, including change in FDC, per boe.
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, 2015 and prepared a reserves report (“GLJ 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, 2016 was used in the evaluation.
The following is summary reserves information detailed in the GLJ Report at December 31, 2015:
|Total Natural Gas(1)||Natural Gas Liquids||Oil Equivalent(2)|
|Total Proved Plus Probable||182,745||161,862||15,005||10,703||45,463||37,680|
|(1) Total Natural Gas includes product types of Shale Gas and Conventional Natural Gas. Product type Shale Gas accounts for approximately 94 percent of Total Proved Natural Gas and 95 percent of Total Proved Plus Probable Natural Gas.|
|(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, 2015, based on the GLJ January 1, 2016 price forecast, are summarized in the following table.
|Net Present Values of Future Net Revenue||Unit Value Before Income|
|Before Income Taxes Discounted At (%/year)(1)||Tax Discounted at|
|Total Proved Plus Probable||628,859||390,002||265,151||192,332||146,026||7.04||1.17|
|(1) Future net revenues are estimated using forecast prices, costs arising from the anticipated development and production of reserves, net of the associated royalties, operating costs, development costs, and abandonment and reclamation costs. 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
Future development costs have been reduced by $122.1 million and $147.6 million for the total proved and total proved plus probable categories, respectively as a result of dispositions, undeveloped reserve conversions, reduced forecast development costs and FDC related to locations removed from the report due to economic considerations.
The following table provides the future development costs, undiscounted, included in the GLJ Report for total proved and total proved plus probable reserves.
|Total Proved Plus Probable||50,100||51,240||123,053||17,621||459||1,312||243,785|
The following is a summary of GLJ’s January 1, 2016 price forecast used in the evaluation.
The following reconciliation of Delphi’s reserves compares changes in the Company’s Gross reserves at December 31, 2014 to the reserves at December 31, 2015, each evaluated in accordance with National Instrument 51-101 definitions.
|Medium||Natural||Natural Gas||Total Oil|
|December 31, 2014||19||181,458||12,641||42,903|
|Extensions and Improved Recovery||–||10,528||907||2,662|
|December 31, 2015||–||95,997||7,892||23,891|
|Medium||Natural||Natural Gas||Total Oil|
|December 31, 2014||5||131,662||9,477||31,426|
|Extensions and Improved Recovery||–||(5,615)||(538)||(1,474)|
|December 31, 2015||–||86,749||7,114||21,572|
|Medium||Natural||Natural Gas||Total Oil|
|Proved Plus Probable||(mbbls)||(mmcf)||(mbbls)||(mboe)|
|December 31, 2014||24||313,120||22,118||74,329|
|Extensions and Improved Recovery||–||4,913||369||1,188|
|December 31, 2015||–||182,745||15,005||45,463|
|(1) Gross reserves represent the operated and non-operated working interest share of reserves before deduction of royalties and does not include any royalty interests of the Company.|
|(2) Total Natural Gas includes product types of Shale Gas and Conventional Natural Gas.|
In the total proved and total proved plus probable reserve categories of the report for the year ended December 31, 2015 negative revisions associated with both non-Montney and Montney reserves were reported due to both economic factors and technical revisions.
Finding and Development Costs
In 2015, corporate finding and development costs (“F&D”), including changes in FDC, were $12.04 per boe for proved producing reserves compared to the 2013-15 three year average of $14.54 per boe. Three year average corporate F&D costs are $12.31 per boe and $10.99 per boe for total proved and total proved plus probable reserves respectively. Including acquisitions and dispositions, three year average corporate finding, development, acquisition and disposition (“F,D&A”) costs are $18.33 per boe, $16.81 per boe, and $17.01 per boe for proved producing, total proved and total proved plus probable reserves respectively.
One year F&D and one year F,D&A costs in the total proved and total proved plus probable categories are not meaningful in 2015 as the reduction in future development costs from 2014 to 2015 exceeded actual capital spent and total reserve additions, including technical revisions and economic factors, are also negative. One year F,D&A costs in the proved producing category is also not meaningful as disposition proceeds exceeded actual capital spent and total reserve additions are also negative.
|2015||2013 – 2015 Totals/Average|
|Proved||Total||Proved plus||Proved||Total||Proved plus|
|Capital ($ thousands)|
|Exploration and Development (“E&D”) Costs(1)||50,551||50,551||50,551||223,358||223,358||223,358|
|Change in Future Development Costs related to E&D||(3,858)||(79,225)||(79,425)||244||46,302||101,360|
|Total E&D Costs||46,693||(28,674)||(28,874)||223,602||269,660||324,718|
|Acquisition and Disposition (“A&D”) Costs||(60,679)||(60,679)||(60,679)||(49,291)||(49,291)||(49,291)|
|Change in Future Development Costs related to A&D||(2,483)||(42,923)||(68,210)||(2,483)||(44,616)||(58,011)|
|Total Acquisition and Disposition (“A&D”) Costs||(63,162)||(103,602)||(128,889)||(51,774)||(93,907)||(107,302)|
|Total Reserve Discoveries, Extensions & Revisions(2)||3,877||(3,822)||(6,821)||15,376||21,913||29,540|
|Total Acquisitions and Dispositions||(6,126)||(11,736)||(18,590)||(6,000)||(11,456)||(16,762)|
|Total Reserve Additions||(2,249)||(15,558)||(25,411)||9,376||10,457||12,778|
|Finding, Development, Acquisition and Disposition Costs ($/boe)|
|E&D, including change in FDC related to E&D (F&D)||12.04||7.50||4.23||14.54||12.31||10.99|
|E&D and A&D, including change in FDC (F,D&A)||7.32||8.50||6.21||18.33||16.81||17.01|
|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.|
|(2) Includes extensions and improved recovery, technical revisions, discoveries, and economic factors.|
For the Montney program, Delphi achieved F&D costs, including changes in FDC, of $10.12 per boe(1) for proved producing reserves compared to the 2013-15 three year average of $13.41 per boe(2). Three year average Montney F&D costs are $11.71 per boe(2) and $10.14 per boe(2) for total proved and total proved plus probable reserves respectively. Three year average Montney F,D&A costs are $14.79 per boe(3), $12.58 per boe(3) and $10.62 per boe(3) for proved producing, total proved and total proved plus probable reserves respectively. At December 31, 2015, the average gross estimated ultimate recoverable reserves of an extended reach, slickwater stimulated horizontal Montney well is 973 mboe, 900 mboe, 1,212 mboe and 1,065 mboe in the proved producing, total proved, proved plus probable producing and total proved plus probable categories respectively.
One year F&D and F,D&A costs in the total proved and total proved plus probable categories are not meaningful in 2015 as the reduction in future development costs from 2014 to 2015 exceeded actual capital spent and total reserve additions, including technical revisions and economic factors, are also negative.
(1) Capital invested of $46.7 million; change in FDC of -$3.9 million; reserve extensions, improved recovery, technical revisions and economic factors of 4.2 million boe.
(2) Capital invested of $213.7 million; change in FDC of $0.6 million, $71.8 million and $147.2 million for proved producing, total proved and total proved plus probable respectively; reserve extensions, improved recovery, technical revisions and economic factors of 16.0 million boe, 24.4 million boe and 35.6 million boe for proved producing, total proved and total proved plus probable respectively.
(3) Capital invested of $213.7 million; change in FDC of $0.6 million, $76.8 million and $167.0 million for proved producing, total proved and total proved plus probable respectively; acquisition costs of $22.6 million; reserve extensions, improved recovery, acquisitions, technical revisions and economic factors of 16.0 million boe, 24.9 million boe and 38.0 million boe for proved producing, total proved and total proved plus probable respectively.
Net Asset Value
The estimated net asset value of the Company at December 31, 2015 has been calculated using the before tax, net present value of reserves discounted at five and ten percent as follows:
|($ thousands except share count and per share value)||5%||10%|
|Estimated future net revenues of Proved Plus Probable reserves(1)||390,002||265,151|
|Mark-to-market value of hedging contracts(3)||18,461||18,461|
|In-the-money option proceeds(4)||1,863||1,863|
|Total asset value||495,531||370,680|
|Bank debt plus working capital deficiency (unaudited)||(121,664)||(121,664)|
|Net asset value||373,867||249,016|
|Common shares outstanding and in-the-money options||157,810,378||157,810,378|
|Net asset value per share||2.37||1.58|
|(1) Discounted at five and ten percent and before deducting future income tax expenses. The Company estimates it has approximately $335.7 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, 2015. Fair market value was determined in accordance with NI 51-101 5.9(1)(e).|
|(3) Financial and physical contracts at December 31, 2015.|
|(4) In-the-money option proceeds are based on the closing December 31, 2015 share price of $0.89.|
Since the end of 2015, Delphi has added another Montney well (0.88 net) to its production base with the 14-27-60-23W5M (“14-27”) well that was drilled at the end of 2015. 14-27 was completed in early January utilizing a 37 stage slickwater frac. The well was produced on clean-up over a 3.1 day period recovering approximately 14 percent of the initial load frac water. Over the last 24 hours prior to running production tubing, the well flowed on clean-up at an average rate of 7.2 million cubic feet per day (“mmcf/d”) of raw gas and 1,384 barrels per day (“bbls/d”) of wellhead condensate (192 bbls/mmcf of raw gas). Total production for the 14-27 well over this 24 hour period was approximately 2,670 barrels of oil equivalent per day (“boe/d”), including an estimated plant natural gas liquids (“NGL”) yield of 34 bbls/mmcf of raw gas. 14-27 was brought on production at the beginning of February and is currently producing at a restricted rate of approximately 5.0 mmcf/d of raw gas and 550 bbls/d of wellhead condensate. Initial average production rates over the first 30 days will be reported once the data is available.
The Company has also drilled and completed the 13-21-60-23W5 (“13-21”) well (0.66 net). The 13-21 well is the western-most Montney well drilled by Delphi and completed with slickwater fracs. It was drilled to a total depth of 5,690 metres with a horizontal lateral length of 2,781 metres. Delphi continues to optimize its completion techniques, as the 13-21 well was fraced over 37 stages with the largest sand tonnage and slickwater volumes for Delphi Montney wells to date. The 13-21 well was flowed on clean-up over a 2.8 day period, recovering approximately 17 percent of the initial load frac water. Over the last 24 hours prior to running production tubing, the well flowed on clean-up at an average rate of 6.1 mmcf/d of raw gas and 1,872 bbls/d of wellhead condensate (309 bbls/mmcf of raw gas). Total production for the 13-21 well over this 24 hour period was approximately 2,954 boe/d, including an estimated plant NGL yield of 34 bbls/mmcf of raw gas. 13-21 is expected to be brought on production at a restricted rate in March 2016.
Delphi has also commenced drilling of the 15-23-60-23W5 well (1.0 net) and is expected to finish in early March. Completion operations are scheduled after spring break-up conditions allow for access, likely early in the third quarter of 2016.
The Company continues to pursue opportunities to reduce operating costs at its Bigstone property. Delphi estimates $6.0 – $7.0 million in reduced operating costs in 2016 over 2015, as the more efficient Montney production replaces the lower netback properties disposed of in 2015. A new fuel gas pipeline accessing higher quality fuel gas has been installed and the 7-11 compression and dehydration facility has been expanded with an owned compressor replacing two existing rental compressors resulting in reduced maintenance and rental costs as well as increased throughput capacity. In addition, with the disposition of the lower netback properties, the Company has reduced its staff from 36 to 24 (34 percent), resulting in expected general and administrative savings of $2.0 – $2.5 million.
The following table has been updated to reflect new well production data since it was previously released and continues to illustrate the significant impact the slickwater hybrid fracturing technique has had on well performance at Bigstone in comparison to smaller conventional frac methods.
Initial Production (IP) Rate Well Performance (1)
(original completion technique)
(new completion technique)
|Type Well||2,400 – 3,000||30 – 40||1,629||449||119||1,306||1,083||943||843||614|
|Average Wells #5 through #22||1,459||438||131||1,220||991||870||762||702|
|(1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries.|
|(2) Wells numbered chronologically.|
|(3) Initial Exploration Well on Delphi’s South Bigstone Lands.|
|(4) Production from 14-24 w as restricted during first 29 days of flow.|
On December 1, 2015, Delphi began delivering the majority of its natural gas production on its Alliance pipeline firm capacity into the Chicago market rather than the AECO market. Well in advance of commencement of these deliveries, the Company continued execution of its successful risk management strategy to protect its revenue stream into the Chicago market through NYMEX, Chicago basis and US/CDN foreign exchange rate contracts. As a result, the Company is very well hedged through 2016 with approximately 75 percent of its natural gas production hedged at an average price of Cdn. $4.43 per mcf (excluding transportation costs). For 2017, the Company has approximately 50 percent of its natural gas production hedged at an average price of Cdn. $4.24 per mcf (excluding transportation costs). Delphi also has approximately 43 percent of its condensate volumes hedged at a floor price of $76.49 per barrel. The table below summarizes the Company’s current commodity price risk management contracts for 2016 and future years.
|Natural Gas (Cdn)||2016||2017|
|% Hedged (1)||8%||7%|
|Hedge Price (Cdn $/mcf) (2)||$3.84||$3.96|
|Strip Price (Cdn $/mcf)||$1.71||$2.42|
|Natural Gas (US)||2016||2017||2018||2019|
|% Hedged (1)||67%||43%||14%||6%|
|Hedge Price (US $/mcf)||$3.50||$3.23||$2.79||$2.81|
|Strip Price (US $/mcf)||$2.07||$2.49||2.57||$2.62|
|% Hedged in Cdn $ (3)||99%||113%||99%||100%|
|Hedge Price (Cdn $/mcf) (4)||$4.50||$4.28||$3.70||$4.02|
|% Hedged (1)||43%|
|Floor Price (WTI Cdn $/bbl)||$78.50|
|Ceiling Price (WTI Cdn $/bbl) (5)||$85.00|
|Strip Price (WTI Cdn $/bbl)||$50.66|
|(1) Percent hedged is based on expected 2016 average natural gas production of 35 mmcf/d and 1,850 bbls/d of condensate and C5+, consistent with guidance.|
|(2) Before deduction of transportation costs to ship production to AECO on TCPL pipeline.|
|(3) Percent of US $ hedge value locked in with Cdn/US FX hedges.|
|(4) Before deduction of transportation costs to ship production to Chicago on Alliance pipeline.|
|(5) 400 bbls/d have upside to a ceiling price of $85.00 per barrel at a deferred cost of $4.02 per barrel.|
Delphi continues to navigate this very challenging low commodity price environment with a singular focus on its core Bigstone Montney asset. This focused effort is successfully improving foundational cash generating efficiencies that will be more fully recognized as the rate of capitalization and production growth accelerates into the recovery phase of this commodity price cycle.
Continued innovation of our well design, driving costs lower, while maintaining full ownership and control of our infrastructure are both paramount in our continued effort towards top decile capital and cash generating efficiencies. Generating margin growth trumps production growth in the current environment. The Company’s significant hedge position through 2016 and 2017, protects both the equity account and the balance sheet, while contributing to a meaningful capital program of four to five wells in 2016. Delphi’s significant drilling inventory is immediately accessible to deliver production growth into a strengthening commodity price environment.
Delphi anticipates releasing its audited financial statements for the year ended December 31, 2015 on March 16, 2016 and its Annual Information Form by March 31, 2015, which will include all required National Instrument 51-101 reserves disclosure.