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Delphi Energy Corp. Reports 2018 Year End Reserves


CALGARY, Alberta, March 04, 2019 (GLOBE NEWSWIRE) — Delphi Energy Corp. (“Delphi” or the “Company”) is pleased to announce its crude oil and natural gas reserves information for the year ended December 31, 2018 and provide an operations update.

HIGHLIGHTS

  • Successfully explored and delineated the Montney at West Bigstone with a drilling program that consisted of twelve (7.8 net) horizontal wells and brought on production twelve (7.8 net) horizontal Montney wells through significantly expanded infrastructure;
  • Increased proved developed producing, total proved and total proved plus probable reserves by one percent, 17 percent and 27 percent, respectively, from a successful drilling program in 2018;
  • Increased field condensate reserves, included in natural gas liquids (“NGL”), related to the Company’s Montney shale gas reserves by 12 percent, 42 percent and 56 percent for proved developed producing, total proved and total proved plus probable reserves, respectively;
  • Field condensate to gas ratio for proved developed producing shale gas reserve extensions through drilling additions in 2018 was 99 barrels per million cubic feet of natural gas (“bbls/mmcf”), significantly higher than 53 bbls/mmcf for proved developed producing reserves in 2017;
  • Increased annual field condensate production by 29 percent, NGL’s by 13 percent, and natural gas by 12 percent for an overall annual production increase of 16 percent to 9,774 boe/d in 2018 from 8,401 boe/d in 2017;
  • Increased the net present value (discounted at ten percent) of proved developed producing reserves by 16 percent through an increased weighting in Montney field condensate and a reduction in Montney operating costs;
  • Increased the net present value (discounted at ten percent) of total proved and total proved plus probable reserves by 18 percent and 26 percent respectively through a significant increase in undeveloped locations as a result of successful delineation drilling; and
  • At December 31, 2018, had undeveloped land of 62,310 net acres with an associated value of $32.1 million(1).

     (1) As determined independently by Seaton-Jordan and Associates Ltd. in accordance with NI 51-101(1)(e).

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, 2018 and prepared a reserves report (the “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, 2019 was used in the evaluation.  Company gross reserves in the total proved and total proved plus probable categories increased 17 percent and 27 percent respectively, compared to 2017.  While Company gross reserves in the proved developed producing category grew by one percent, the field condensate component of natural gas liquids associated with the Montney grew by 12 percent, contributing to a growth in value for the category.

The following is a summary of reserves information detailed in the GLJ Report at December 31, 2018:

Conventional
Natural Gas
Shale Gas Natural Gas Liquids Oil Equivalent(1)
Company Company Company Company Company Company Company Company
Gross Net Gross Net Gross Net Gross Net
Reserves Category (mmcf) (mmcf) (mmcf) (mmcf) (mbbls) (mbbls) (mboe) (mboe)
Proved
Producing 6,809 6,042 51,553 46,028 5,311 4,130 15,038 12,808
Developed Non-Producing 1,012 942 13 9 182 166
Undeveloped 54,985 51,410 7,021 6,193 16,186 14,761
Total Proved 7,820 6,984 106,539 97,438 12,345 10,332 31,405 27,736
Total Probable 6,588 5,954 105,016 96,090 11,780 9,523 30,380 26,530
Total Proved Plus Probable 14,408 12,938 211,554 193,528 24,125 19,854 61,786 54,266

(1) 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).
(2) Tables may not add due to rounding.

Net Present Value of Future Net Revenue

The net present value of future net revenues, discounted at ten percent, for proved developed producing reserves increased by 16 percent as a result of richer, more valuable boe’s replacing production as well as the commissioning of the Company’s Amine facility at Bigstone.  This project, although only in operation for approximately eight months of 2018, was a key component in reducing operating costs in the Montney from $8.72/boe in 2017 to $7.65/boe in 2018.  The net present value of future net revenues, discounted at ten percent, for total proved and total proved plus probable reserves increased by 18 percent and 26 percent respectively, compared to 2017. The estimated future net revenues associated with Delphi’s reserves at December 31, 2018, based on the GLJ January 1, 2019 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
10%/year(2)
0 % 5 % 10 % 15 % 20 % $/boe $/mcfe
($ thousands)
Proved
Producing 237,276 191,187 159,904 137,879 121,743 12.48 2.08
Developed Non-Producing 1,220 1,169 1,029 882 751 6.18 1.03
Undeveloped 193,675 116,306 70,566 42,179 23,764 4.78 0.80
Total Proved 432,172 308,662 231,500 180,940 146,259 8.35 1.39
Total Probable 495,420 264,529 154,664 96,993 64,092 5.83 0.97
Total Proved Plus Probable 927,592 573,191 386,163 277,932 210,350 7.12 1.19

(1) Future net revenues are estimated using forecast prices, costs arising from the anticipated development and production of reserves, 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.
(3) Tables may not add due to rounding.

Future Development Costs

Future development costs (“FDC”) have increased by $83.2 million and $199.1 million for the total proved and total proved plus probable categories respectively, primarily as a result of new undeveloped locations being booked offsetting the successful delineation wells drilled in 2018.

The following table provides the future development costs, undiscounted, included in the GLJ Report for total proved and total proved plus probable reserves.

($ millions) 2019 2020 2021 2022 2023 Rem Total
Total Proved 56 55 71 52 0 0 234
Total Proved Plus Probable 56 94 76 129 118 1 474

Forecast Prices

The following is a summary of GLJ’s January 1, 2019 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
2019 1.85 3.00 63.33 56.25 67.67 0.0 0.750
2020 2.29 3.15 75.32 63.00 79.22 2.0 0.770
2021 2.67 3.35 79.75 67.00 83.54 2.0 0.790
2022 2.90 3.50 81.48 70.00 85.49 2.0 0.810
2023 3.14 3.63 83.54 72.50 87.80 2.0 0.820
2024 3.23 3.70 86.06 75.00 90.30 2.0 0.825
2025 3.34 3.77 89.09 77.50 93.33 2.0 0.825
2026 3.41 3.85 92.62 80.41 96.86 2.0 0.825
2027 3.48 3.93 94.57 82.02 98.81 2.0 0.825
2028 3.54 4.00 96.56 83.66 100.80 2.0 0.825
2029+ +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr 2.0 0.825

Reserves(1) Reconciliation

The following reconciliation of Delphi’s reserves compares changes in the Company’s gross reserves at December 31, 2017 to the reserves at December 31, 2018, each evaluated in accordance with National Instrument 51-101 definitions.  Negative technical revisions and economic factors to shale gas and associated natural gas liquids product types were primarily related to shale gas and the associated plant extracted natural gas liquids.  Technical revisions and economic factors related to field condensate (included in the “associated natural gas liquids” product type) were positive 7 mboe for total proved and negative 408 mboe for total proved plus probable.

Shale Gas Conventional Natural Gas
Shale Associated
Natural Gas
Natural Associated
Natural Gas
Total Oil
Gas Liquids Gas Liquids Equivalent
Proved (mmcf) (mbbls) (mmcf) (mbbls) (mboe)
December 31, 2017 93,933 9,574 8,370 230 26,854
Extensions and Improved Recovery 32,118 4,500 9,853
Technical Revisions (8,033 ) (571 ) 848 59 (1,710 )
Discoveries
Acquisitions
Dispositions
Economic Factors (129 ) (3 ) (24 )
Production (11,479 ) (1,389 ) (1,269 ) (53 ) (3,567 )
December 31, 2018 106,539 12,113 7,820 232 31,405
Shale Gas Conventional Natural Gas
Shale Associated
Natural Gas
Natural Associated
Natural Gas
Total Oil
Gas Liquids Gas Liquids Equivalent
Probable (mmcf) (mbbls) (mmcf) (mbbls) (mboe)
December 31, 2017 76,377 7,536 6,784 236 21,633
Extensions and Improved Recovery 43,037 5,250 12,423
Technical Revisions (14,376 ) (1,250 ) (156 ) 6 (3,666 )
Discoveries
Acquisitions
Dispositions
Economic Factors (22 ) (40 ) 1 (9 )
Production
December 31, 2018 105,016 11,537 6,588 243 30,380
Shale Gas Conventional Natural Gas
Associated Associated
Shale Natural Gas Natural Natural Gas Total Oil
Gas Liquids Gas Liquids Equivalent
Proved Plus Probable (mmcf) (mbbls) (mmcf) (mbbls) (mboe)
December 31, 2017 170,309 17,110 15,154 466 48,486
Extensions and Improved Recovery 75,155 9,750 22,276
Technical Revisions (22,409 ) (1,821 ) 692 65 (5,376 )
Discoveries
Acquisitions
Dispositions
Economic Factors (22 ) (169 ) (2 ) (33 )
Production (11,479 ) (1,389 ) (1,269 ) (53 ) (3,567 )
December 31, 2018 211,554 23,650 14,408 475 61,786

(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) Tables may not add due to rounding.

Finding and Development Costs

In 2018, Delphi brought twelve gross (7.8 net) wells on production.  Capital to drill, complete, equip and tie-in these wells totaled $83.6 million which includes $15.0 million of capital spent on these wells in 2017 and excludes $22.4 million of capital spent in 2018 on major infrastructure and wells not brought on production in 2018.  Included in these well costs is capital for major gathering and infrastructure costs in order to bring the delineation wells (particularly at West Bigstone) on stream.  Company gross proved developed producing reserve additions (classified as extensions and improved recovery) for these wells was 4.5 mmboe resulting in a finding and development cost of $18.60 per boe.  Finding and development costs for proved and proved plus probable reserves for 2018 and the last three years are presented below.

2018 2016 – 2018 Totals/Average
Proved
Producing
Total
Proved
Total
Proved
plus
Probable
Proved
Producing
Total
Proved
Total
Proved
plus
Probable
Capital ($ thousands)      
Exploration and Development (“E&D”) Costs 90,991 90,991 90,991 263,690 263,690 263,690
Change in FDC related to E&D (5 ) 83,201 199,082 (114 ) 147,208 288,321
Total E&D Costs 90,986 174,192 290,073 263,576 410,898 552,011
Acquisition and Disposition (“A&D”) Costs (157 ) (157 ) (157 ) (58,991 ) (58,991 ) (58,991 )
Change in FDC related to A&D (22,884 ) (58,057 )
Total A&D Costs (157 ) (157 ) (157 ) (58,992 ) (81,875 ) (117,048 )
Total Costs 90,829 174,035 289,916 204,585 329,023 434,963
Reserves (mboe)      
Total Reserve Discoveries, Extensions & Revisions(1) 3,785 8,119 16,867 12,095 19,632 33,052
Total Acquisitions and Dispositions (720 ) (2,777 ) (7,386 )
Total Reserve Additions 3,785 8,119 16,867 11,375 16,856 25,666
   
E&D, including change in FDC related to E&D (F&D) 24.04 21.45 17.20 21.79 20.93 16.70
E&D and A&D, including change in FDC (F,D&A) 24.00 21.44 17.19 17.99 19.52 16.95

(1) Includes extensions and improved recovery, technical revisions, discoveries and economic factors.

Delphi will release its Annual Information Form on or before April 1, 2019, which will include all required National Instrument 51-101 reserves disclosure.

Net Asset Value

The estimated net asset value of the Company at December 31, 2018 has been calculated using before tax, net present value of reserves discounted at ten percent as follows:

($ millions) Proved Plus Probable
Discounted (10%) net present value of reserves $386,163
Undeveloped land $32,074
Mark-to-market value of hedging contracts $26,626
Total assets value   $444,863
Total debt plus working capital deficiency ($181,985 )
Net asset value $262,878
Common shares outstanding 185,547,351
Net asset value per share $1.42
YE2017 NAV per share $1.17
% change 21%

OPERATIONS UPDATE

The fourth quarter of 2018 was challenging for our industry with ongoing constraints on exports from the Western Canadian Sedimentary Basin coupled with a decline in international crude oil prices impacting the price received for our energy products.  Differentials for all grades of crude oil and condensate were severely impacted by pipeline apportionment and lack of storage.  With the curtailment of heavy oil production introduced by the Government of Alberta and easing of storage constraints, differentials to benchmark prices have significantly improved in recent months.

Production volumes for the twelve months ended December 31, 2018 averaged 9,774 boe/d, a 16 percent increase over the comparative period in 2017, while field condensate production volumes increased by 29 percent to 2,542 barrels per day (“bbls/day”) over that same period.

Production volumes in the fourth quarter of 2018 averaged 9,444 boe/d, a two percent decrease over the comparative quarter in 2017. Field condensate comprised about 28 percent of production on a barrel of oil equivalent (“boe”) basis while field condensate and natural gas liquids (“NGL”) combined accounted for 42 percent of production. Production in the fourth quarter of 2018 was negatively impacted by approximately 1,270 boe/d due to a combination of ongoing completion operations impacting adjacent producing wells (685 boe/d);  scheduled and unscheduled facility outages (410 boe/d); and, the permanent suspension of the Company’s Tower Creek sour gas well in October (175 boe/d).  The performance of impacted offset wells has continued to improve since being put back on production with the deficit of current performance to pre-fracing performance being reduced to about 80 boe/d.  With the shift to multi-well pad operations the impact on base production from offset frac operations will be greatly reduced.

Given the very low condensate pricing in November and December, Delphi deferred the reactivation of some of its more condensate-rich production until January where differentials narrowed to more historical norms. January’s realized condensate pricing, including its hedging gains was almost three times higher than December, and more consistent with realized pricing in the third quarter of 2018.

With delineation success at West Bigstone exhibiting robust production rates and higher condensate to gas ratios, Delphi has shifted its focus to development through multi-well pad operations in order to realize cost efficiencies while optimizing completion technique as well as diminish the impact of fracing operations on offset wells.  The first three wells of a four-well pad were drilled in the fourth quarter of 2018 with drilling of the fourth well finishing in January 2019.  Completion of these four wells have commenced and they are expected to be brought on production in the second quarter. These four wells are directly adjacent to the 16-10-60-24W5 (“16-10”) and 15-10-60-24W5 (“15-10”).

With the innovations on frac techniques utilized on 16-10- and 15-10, the average total IP30, IP90, and IP180 (for 16-10 only) of these two wells has exceeded the average west wells by 325 boe/d (31 percent), 334 boe/d (40 percent) and 355 boe/d (52 percent).  The West Bigstone wells have averaged approximately 55 percent liquids over the first 180 days of production. Furthering these innovations through even tighter frac spacing and extreme limited entry frac technique coupled with the reduced capital that pad operation efficiencies provide gives line of sight to superior economics at Bigstone.

Through the first half of 2019, Delphi will focus on completing and bringing on production its four-well pad in West Bigstone.  Facility upgrades and pipeline construction to route the West Bigstone production to Delphi’s 7-11 facility in East Bigstone is expected to be completed in late March.  Capital spending in 2019 will be in the context of cash flow.  Drilling plans for the second half of 2019 will be dependent on both commodity prices and the results of the four-well pad currently being completed.

About Delphi Energy Corp.

Delphi Energy Corp. is an industry-leading producer of liquids-rich natural gas.  The Company has achieved top decile results through the development of our high quality Montney property, uniquely positioned in the Deep Basin of Bigstone, in northwest Alberta. Delphi continues to outperform key industry players by improving operational efficiencies and growing our dominant Bigstone land position in this world-class play. Delphi is headquartered in Calgary, Alberta and trades on the Toronto Stock Exchange under the symbol DEE. 

FOR FURTHER INFORMATION PLEASE CONTACT:
DELPHI ENERGY CORP.
2300 – 333 – 7th Avenue S.W.
Calgary, Alberta
T2P 2Z1
Telephone: (403) 265-6171  Facsimile: (403) 265-6207
Email: info@delphienergy.ca  Website: www.delphienergy.ca
DAVID J. REID  MARK D. BEHRMAN
President & CEO Chief Financial Officer


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