Delphi Energy Corp. Reports 2019 Year End Results
March 11, 202011:11 PM Globe Newswire
CALGARY, Alberta – Delphi Energy Corp. (“Delphi” or the “Company”) is pleased to announce its financial and operational results and reserves for the year ended December 31, 2019.2019 HIGHLIGHTSDuring 2019, the Company incurred $26.8 million in capital expenditures while generating $52.6 million of adjusted funds flow;Reduced bank debt plus adjusted working capital deficit by $41.1 million, or 44 percent, from the first quarter of 2019. Net bank debt as at December 31, 2019 was $51.8 million;During the fourth quarter, Delphi commenced construction of a two well pad in West Bigstone for the kickoff of the 2020 capital program. In 2019, Delphi drilled the fourth well from the four-well pad initiated in the fourth quarter of 2018 and also completed and tied-in all four (2.60 net) wells. The installation of artificial lift on some legacy wells has brought back production capacity and will be expanded to other wells to reduce ongoing operating costs;Continued the strong hedge book with commodity risk management contracts throughout the year. The Company realized $13.3 million of hedging gains in 2019. As at December 31, 2019, Delphi’s risk management contracts had mark-to-market net asset value of $6.3 million;Delphi completed a Recapitalization Transaction in the fourth quarter that successfully extended the maturity date of the second lien senior secured notes by 21 months to mature on April 15, 2023 and raised $46.5 million through private placements for the development of the Company’s Montney asset or a consolidation of assets. The Recapitalization Transaction also provided for a common share consolidation of 15:1;Average production in the quarter of 7,022 barrels of oil equivalent per day (“boe/d”) was down 26 percent from the 9,444 boe/d in the comparative quarter of 2018 as no additional production has been brought on-stream since the second quarter of 2019. During the fourth quarter of 2019, the liquids yield averaged 109 barrels per million cubic feet (“bbls/mmcf”), up ten percent from the 99 bbls/mmcf in the fourth quarter of 2018. Of the 109 bbls/mmcf, 78 bbls/mmcf were the higher valued condensate and pentane products;Adjusted funds flow for the fourth quarter decreased 26 percent over the comparative quarter, largely due to lower total cash revenues and increased finance costs partially offset by a decrease in operating, transportation and general and administrative expenses. On a per unit basis, the cash netback was $10.17 per boe compared to $10.24 per boe in the fourth quarter of 2018; andIn 2019, the Company completed the permanent assignment of approximately 35 percent of its firm full-path Alliance service (the “Permanent Assignment Transaction”) for net proceeds of $11.5 million. The net proceeds from the Permanent Assignment Transaction were used to repay bank indebtedness.FINANCIAL AND OPERATIONAL HIGHLIGHTSThree months ended December 31Twelve months ended December 3120192018% Change20192018% ChangeFinancial($ thousands, except per share)Crude oil and natural gas revenues19,14726,786(29)93,138127,254(27)Net earnings (loss)(13,082)(17,318)(24)(74,581)(26,366)183Per share – basic and diluted (2)(0.89)(1.40)(36)(5.76)(2.13)170Cash flow from operating activities11,3289,4282052,61654,128(3)Per share – basic and diluted(1) (2)0.770.7614.064.25(4)Adjusted funds flow(1)6,5738,890(26)52,17846,61512Per share – basic and diluted(1) (2)0.450.72(38)4.033.6610Net debt(1)155,297181,985(15)155,297181,985(15)Capital expenditures, net of dispositions2,07226,942(92)28,84990,834(68)Weighted average shares (000s) (2)Basic14,67512,3701912,95112,7305Diluted14,67512,3701912,95112,7305Operating(boe conversion – 6:1 basis)Production:Field condensate (bbls/d)1,7472,644(34)2,2452,542(12)Natural gas liquids (bbls/d)1,0271,289(20)1,2091,411(14)Natural gas (mcf/d)25,48733,063(23)29,23734,925(16)Total (Boe/d)7,0229,444(26)8,3279,774(15)Average realized sales prices, before financial instrumentsField condensate ($/bbl)64.8442.665264.9266.96(3)Natural gas liquids ($/bbl)19.0738.87(51)24.5844.88(45)Natural gas ($/mcf)2.943.71(21)2.703.23(16)Netbacks ($/boe)Crude oil and natural gas revenues29.6330.83(4)30.6535.68(14)Marketing income (1)0.031.61(98)1.471.414Realized gain (loss) on financial instruments5.78(3.38)(271)4.38(3.47)(226)Revenue, after realized financial instruments35.4429.062236.5033.629Royalties(2.43)(1.72)41(2.13)(2.08)2Operating expense(10.01)(7.33)37(9.44)(8.38)13Transportation expense(4.43)(4.43)–(4.31)(4.86)(11)Operating netback (1)18.5715.581920.6218.3013Permanent Assignment Transaction(0.01)––3.80––General and administrative expenses(1.58)(1.61)(2)(1.74)(1.61)8Finance charges(6.56)(3.54)85(5.29)(3.43)54Settlement of unutilized take-or-pay contract(0.26)(0.19)37(0.22)(0.19)16Cash netback (1)10.1610.24(1)17.1713.0731(1) Refer to non–GAAP measures (2) As part of the Recapitalization Transaction effective November 26, 2019, Delphi consolidated its common shares on a basis of 15:1. Comparative period per share amounts prior to the consolidation have been adjusted to reflect the consolidation.MESSAGE TO SHAREHOLDERSIn 2019, Delphi scaled back its drilling program to four (2.6 net) wells, spending only 55 percent of its adjusted funds flow generated in 2019, to focus on improving its available liquidity into an uncertain and volatile commodity price environment. Having reduced bank debt by approximately 44 percent and extended the maturity date of its senior secured notes to April 15, 2023, the Company is now in a better position to endure this recent collapse in world oil prices due to the unprecedented combined demand destruction event of the coronavirus with a price war driven supply surge. The Company’s 2020 risk management program also provides protection from the current oil price weakness with 70 percent of its volumes hedged in the second quarter of 2020 and approximately 50 percent of its volumes hedged in the second half of 2020 at prices 75 percent higher than current WTI oil prices.Delphi’s focus on improving its liquidity during 2019 also included the successful disposition of a portion of its unutilized Alliance firm service and the Recapitalization Transaction that to date has injected $31 million of gross proceeds into the Company that has been used to fund the first quarter 2020 capital program, with another $15.5 million to be received in the third quarter of 2020 upon certain conditions being met.As part of the Recapitalization Transaction, Delphi also took significant steps to re-invigorate the culture and leadership of the Company by making significant changes to the leadership team as well as the Board of Directors. The objective was to have an immediate impact on the results of the capital being deployed. The Company has decreased its full time staff to 18, while reducing its 2020 salary expenses by approximately 30 percent.While Delphi fell short of its expectations to reduce drilling and completion costs utilizing pad drilling in 2019, the Company is excited about the significant improvements made by the new team, cutting drilling times in half and reducing overall drilling and completions costs by an estimated 23 percent compared to 2019. More importantly, there are additional opportunities identified to further reduce the capital costs, and improve the economic returns.Given the reduced level of new wells added in 2019, the Company’s corporate base production decline has fallen to a forecasted and manageable 22 percent in 2020, requiring less than four net wells to maintain current production levels. Delphi has successfully implemented a number of initiatives in the field to mitigate declines in legacy wells as well as reduce operating costs. The Company is currently finishing its three well first half 2020 capital program.Although the Company has successfully implemented significant “change” initiatives that has improved its forward looking operational results, the current and deteriorating environment will continue to prove challenging. The Company recognizes that this challenging environment requires larger scale and greater financial strength than Delphi has at its current size, and continues to evaluate a number of strategic business combination opportunities to enhance its sustainability. The Company is planning minimal capital spending during the second quarter, utilizing free cash flow generated to lower bank indebtedness, and will evaluate its second half 2020 plans later in the second quarter.Delphi remains well positioned with a high quality resource base supported by a significant infrastructure footprint and a large drilling inventory.The Company looks forward to providing an update to its ongoing corporate initiatives and operations in the second quarter.OPERATING AND FINANCIAL HIGHLIGHTS FOR THE QUARTER AND YEAR ENDED DECEMBER 31, 2019Upon the closing of the Recapitalization Transaction in the fourth quarter of 2019, as disclosed in the MD&A for the year ended December 31, 2019, the Company commenced its winter drilling program and began the construction of a two well pad. In addition, Delphi installed pump jacks on two wells that required critical lift. Capital spending in three and twelve months ended December 31, 2019 was $2.1 million and $28.8 million, respectively. In 2019, the Company drilled the last well (0.65 net) of the four well pad, of which three (1.95 net) of the wells were drilled in 2018, and completed and equipped all four wells. In order to accommodate production from the four well pad and future development in West Bigstone, the Company expanded the battery at West Bigstone and pipeline to connect West Bigstone to the 7-11 facility in East Bigstone.In 2019, the Company successfully completed the Permanent Assignment Transaction for net proceeds of $11.5 million. The net proceeds from the Permanent Assignment Transaction, $8.4 million net proceeds from the first escrow release from the Recapitalization Transaction and adjusted free cash flow of $21.2 million from the first quarter of 2019 to the fourth quarter of 2019 have allowed the Company to reduce net bank debt by $41.1 million or 44 percent since the peak at the end of the first quarter of 2019.Production volumes in the fourth quarter of 2019 averaged 7,022 boe/d, a decrease of 16 percent from 8,386 boe/d average in the third quarter of 2019 and 26 percent lower in comparison to the same period in 2018 as no additional wells have been brought on-stream since the second quarter of 2019. The production from the four-well pad, which was brought on-stream throughout the second quarter, has contributed to an increase in liquids yield. During the fourth quarter of 2019, the liquids yield averaged 109 bbls/mmcf, up ten percent from the 99 bbls/mmcf in the fourth quarter of 2018. Of the 109 bbls/mmcf, 78 bbls/mmcf were the higher valued condensate and pentane products. The Company’s production portfolio for the fourth quarter of 2019 was weighted 25 percent to field condensate, 15 percent to natural gas liquids and 60 percent to natural gas. The production portfolio for the comparative quarter in 2018 was weighted 28 percent to field condensate, 14 percent to natural gas liquids and 58 percent to natural gas.Crude oil and natural gas revenues were $19.1 million, down eight percent from the third quarter of 2019 largely due to lower field condensate and natural gas volumes partially offset by an increase in the price received for its natural gas. In comparison, crude oil and natural gas revenues in the fourth quarter of 2019 were $7.6 million or 29 percent lower than the fourth quarter of 2018 due to lower production volumes and realized prices for natural gas and natural gas liquids partially offset by an improvement in the benchmark price for field condensate.Operating expenses in the fourth quarter of 2019 totaled $6.5 million or $10.01 per boe. Until additional production is brought on-stream, fixed operating costs and declining production results in increased operating costs on a per boe basis. Operating expenses in the fourth quarter of 2019 include well workover and stimulation and $0.4 million of third-party equalizations related to prior periods. The Company is realizing reduced processing fees as approximately 30 percent of its natural gas production was sweetened at the amine facility at 7-11 and further processed at its 25 percent owned natural gas processing plant in Bigstone. Transportation expenses in the fourth quarter of 2019 decreased 26 percent to $2.9 million in comparison to the same period in 2018 as the Company ships more of its natural gas volumes on the less costly NGTL system.The Company’s hedge book continues to be a critical pillar in managing cash flows during this extremely volatile commodity price environment. In 2019, Delphi realized $13.3 million of gains on its risk management contracts contributing $4.38 per boe to the operating netback. The operating netback before hedging and the Permanent Assignment Transaction was $16.24 per boe compared to $21.77 per boe in 2018, a decrease of 25 percent per boe largely due to a decrease in crude oil and natural gas revenues and lower production volumes which will carry a higher proportion of fixed operating costs per unit. The operating netback before hedging and the Permanent Assignment Transaction was $12.79 per boe in the fourth quarter of 2019 compared to $18.96 per boe in the same period in 2018. The operating netback on a per boe basis decreased in the fourth quarter of 2019 compared to the same period in 2018 due to less marketing income and higher operating expenses. The Company’s ability to generate marketing income is dependent on the premium in Chicago benchmark pricing relative to AECO benchmark pricing which has been narrowing as AECO benchmark improves while the Chicago benchmark weakens.The cash netback before the Permanent Assignment for 2019 was $13.37 per boe, a three percent increase in comparison to the same period in 2018 mainly due to realized hedging gains partially offset by higher general and administrative and finance costs. On an absolute basis, Delphi has reduced general and administrative costs by $0.8 million in 2019 in comparison to 2018.In the fourth quarter of 2019, the Company’s senior lenders completed the semi-annual borrowing base review of the senior credit facility and reduced the borrowing base from $90.0 million to $80.0 million. Bank debt at the end of the year was $46.4 million and outstanding letters of credit were $5.3 million, leaving $28.3 million available to be drawn on the senior credit facility. Net debt at the end of the year was $155.3 million.HEDGINGDelphi’s realized prices for condensate and NGL in 2020 are well protected by WTI crude oil swap contracts for an average volume of 1,021 bbl/d at an average price of $82.23 per bbl and Conway propane swap contracts for an average volume of 100 bbl/d at an average price of $43.23 per bbl. In addition, the Company has purchased a put option for an average of 686 bbl/d in 2020 at Cdn$78.00 per bbl and has sold a put option for an average of 686 bbl/d in 2020 at Cdn$58.00 per bbl.The Company’s realized price for natural gas in 2020 is protected by NYMEX HH natural gas swap contracts for an average volume of 5,600 million British thermal units per day (“mmbtu/d”) at an average price of $3.54 per million British thermal units (“mmbtu”) and Chicago – NYMEX natural gas basis swap contracts for an average volume of 1,021 mmbtu/d at an average basis discount of $0.18 per mmbtu, resulting in an average swap price of $3.36 per mmbtu in Chicago.Hedging contracts in place for 2020 protect the realized price for approximately 40 percent of Chicago natural gas sales and approximately 65 percent of field condensate and NGL sales combined, based on production in the fourth quarter of 2019.Delphi’s commodity risk management contracts were valued at $6.3 million as at December 31, 2019. Based on the current volatility and significant drop in WTI prices, Delphi’s risk management contract value has more than doubled since December 31, 2019.2019 OPERATIONS REVIEWThe 2019 capital program consisted of the drilling and completions of the four well pad in West Bigstone with a surface location of 13-34-59-24W5 (“13-34”) and tie-in of the pad to the 7-11 facility at East Bigstone with a designated 14 kilometre pipeline to eliminate increased line-pack issues on legacy production. The four wells were drilled in the fourth quarter of 2018 and the first quarter of 2019 with an average horizontal length in the Montney of 2,850 metres. The average timing from spud to total depth and spud to rig release was 27 days and 33 days for these 4 wells with average drilling cost of $4.6MM per well.The 13-34 pad offset the Company’s western-most wells drilled at West Bigstone at 16-10-60-24W5 and 15-10-60-24W5 (“16-10” and “15-10”). The two eastern-most wells on the 13-34 pad were completed with a hybrid completion consisting of 50 fracs pumped using a ball-drop liner, and 30 individual fracs placed using plug and perf for a total of 80 discrete fracs. This is a similar design used at 16-10 and 15-10 where 65 fracs were placed. On the two western-most wells on the pad, extreme limited entry frac technique was used consisting of 40 stages with five clusters per stage for a total of 200 clusters or fracture initiations. Approximately 4,800 tonnes of proppant was pumped in each of these four wells and average completions cost of $5.6MM, for a total drilling and completions (“D&C”) cost of $10.2MM per well. The average 2019 gross year end total proved plus probable producing booking for the two openhole wells were approximately 900mboe per well, with 35% field condensate while the two cemented liner wells were approximately 600mboe, with 41% field condensate. The company is encouraged with the results of openhole wells given these wells are drilled at 6 wells per section density and continue to investigate the parameters resulting in the underperformance of the cemented liners to date.In the fourth quarter of 2019, the company started construction of a two well pad, which was spudded on January 1, 2020. The average timing from spud to total depth and spud to rig release was 12.8 days and 17.8 days for these 2 wells with average drilling field estimate cost of $3.4MM. The drilling time was 14 days faster than the 13-34 average, resulting in $1.2MM savings in drilling cost per well. Significant changes to the Company’s drilling practice included:Utilizing a Hybrid bit in the intermediate section and optimizing drilling parameters reduced drilling time to intermediate casing point;Drilling the lateral with water-based fluid combined with bottomhole assembly (BHA) optimization increased the rate of penetration throughout the lateral resulting in a lateral drilling time of 4 days with one bit run;The addition of reamers to the BHA in both intermediate hole and the lateral eliminated the need for dedicated reamer runs at the total depth of each section saving approximately 3 days per well.The company commenced the completions of these two wells in late February 2020 and the pressure pumping and milling operations are 100% completed with flowback operation and tubing installation to follow. Each of these wells were completed with a hybrid completion consisting of 50 fracs pumped using a ball-drop liner, and 15 individual fracs placed using plug and perf for a total of 65 discrete fracs with total of 5,200 tonnes of proppant pumped. The company is targeting completions cost of $4.5MM, resulting in total D&C cost target of $7.9MM per well which is 23% lower than the 13-34. This reduction in capital cost per well will significantly improve the economic metrics of Bigstone Montney.On Production YearWell CountSpud to RRDrill DaysStage CountTotal SandDrilling CostCompletions CostTotal (days)(days)(tonnes)(C$ thousands)(C$ thousands)(C$ thousands)2015 & Prior244235292,007$5,361$4,710$10,071201663328393,918$3,985$3,721$7,7062017153328404,634$3,744$4,305$8,0492018123125494,291$4,125$5,216$9,341201943327604,771$4,594$5,578$10,1722020217.812.8655,200$3,400$4,500$7,900RESERVES HIGHLIGHTSSuccessfully explored and delineated the Montney at West Bigstone with a drilling program that consisted of four (2.6 net) horizontal wells and brought on production four (2.6 net) horizontal Montney wells through significantly expanded infrastructure;Field condensate to gas ratio for proved developed producing shale gas reserve extensions through drilling additions in 2019 was 127 barrels per million cubic feet of natural gas (“bbls/mmcf”), significantly higher than 59 bbls/mmcf for proved developed producing reserves in 2018;At December 31, 2019, had undeveloped land of 58,878 net acres with an associated value of $26.8 million(1). (1) As determined independently by Seaton-Jordan and Associates Ltd. in accordance with NI 51-101(1)(e).RESERVES SUMMARYGLJ 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, 2019 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, 2020 was used in the evaluation. Company gross reserves in the total proved and total proved plus probable categories decreased 4 percent and 6 percent respectively, compared to 2018.The following is a summary of reserves information detailed in the GLJ Report at December 31, 2019:Conventional Natural GasShale GasNatural Gas LiquidsOil Equivalent(1)CompanyCompanyCompanyCompanyCompanyCompanyCompanyCompanyGrossNetGrossNetGrossNetGrossNetReserves Category(mmcf)(mmcf)(mmcf)(mmcf)(mbbls)(mbbls)(mboe)(mboe)ProvedProducing5,0164,44345,34640,5744,6063,59312,99911,096Developed Non-Producing––––––––Undeveloped––58,17754,5377,3996,50817,09515,598Total Proved5,0164,443103,52395,11112,00510,10230,09526,694Total Probable5,4994,93497,46089,82611,1028,87728,26224,670Total Proved Plus Probable10,5159,378200,982184,93723,10718,97958,35651,364(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 RevenueThe net present value of future net revenues, discounted at ten percent, for proved developed producing reserves decreased by 15 percent compared to 2018 due to the reduction in price forecasts. The net present value of future net revenues, discounted at ten percent, for total proved and total proved plus probable reserves decreased by 10 percent and 5 percent respectively, compared to 2018 due to the reduction in price forecasts. The estimated future net revenues associated with Delphi’s reserves at December 31, 2019, based on the GLJ January 1, 2020 price forecast, are summarized in the following table.Net Present Values of Future Net RevenueUnit Value Before IncomeBefore Income Taxes Discounted At (%/year)(1)Tax Discounted at10%/year(2)0%5%10%15%20%$/boe$/mcfe($ thousands)ProvedProducing 190,210 158,389 135,179 117,994 104,95412.182.03Developed Non-Producing–––––––Undeveloped 184,754 116,231 73,448 45,815 27,3484.710.78Total Proved 374,964 274,619 208,627 163,810 132,3027.821.30Total Probable 456,420 256,237 156,771 103,075 71,8736.351.06Total Proved Plus Probable 831,384 530,856 365,398 266,885 204,1757.111.19(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 CostsFuture development costs (“FDC”) have increased by $21.3 million and $1.4 million for the total proved and total proved plus probable categories respectively, primarily as a result of new undeveloped locations being booked offsetting the successful delineation wells drilled in 2019.The following table provides the future development costs, undiscounted, included in the GLJ Report for total proved and total proved plus probable reserves.($ millions)20202021202220232024RemTotalTotal Proved3793764900255Total Proved Plus Probable3793811235982475Forecast PricesThe following is a summary of GLJ’s January 1, 2019 price forecast used in the evaluation.Natural GasOilAECO/NITNYMEXEdmontonNYMEXPentanes PlusExchangeSpotHenry HubLightWTIEdmontonInflationRateYear$CDN/MMBtu$US/MMBtu$CDN/bbl$US/bbl$CDN/bbl%$US/$CDN20202.082.4271.7161.0077.800.00.76020212.352.7574.0363.0079.222.00.77020222.552.9076.9266.0083.332.00.78020232.653.0080.1368.0086.542.00.78020242.753.1082.6970.0089.102.00.78020252.853.2085.2672.0091.672.00.78020262.913.2787.8274.0094.232.00.78020272.973.3390.1475.8196.552.00.78020283.033.4092.0977.3398.502.00.78020293.093.4794.0878.88100.492.00.7802030++2.0%/yr+2.0%/yr+2.0%/yr+2.0%/yr+2.0%/yr2.00.780Reserves(1) ReconciliationThe following reconciliation of Delphi’s reserves compares changes in the Company’s gross reserves at December 31, 2018 to the reserves at December 31, 2019, each evaluated in accordance with National Instrument 51-101 definitions.Shale GasConventional Natural GasShaleAssociated Natural GasNaturalAssociated Natural GasTotal OilGasLiquidsGasLiquidsEquivalentProved(mmcf)(mbbls)(mmcf)(mbbls)(mboe)December 31, 2018106,53912,1137,82023231,405Extensions and Improved Recovery12,7041,601––3,718Technical Revisions(6,068)(695)(1,450)(9)(1,957)Discoveries–––––Acquisitions41355––124Dispositions–––––Economic Factors(221)(9)(527)(23)(157)Production(9,844)(1,219)(827)(41)(3,038)December 31, 2019103,52311,8455,01616030,095Shale GasConventional Natural GasShaleAssociated Natural GasNaturalAssociated Natural GasTotal OilGasLiquidsGasLiquidsEquivalentProbable(mmcf)(mbbls)(mmcf)(mbbls)(mboe)December 31, 2018105,01611,5376,58824330,380Extensions and Improved Recovery3,110774––1,293Technical Revisions(10,328)(1,380)(816)(36)(3,273)Discoveries–––––Acquisitions16126––53Dispositions–––––Economic Factors(499)(52)(273)(11)(192)Production–––––December 31, 201997,46010,9055,49919628,262Shale GasConventional Natural GasAssociatedAssociatedShaleNatural GasNaturalNatural GasTotal OilGasLiquidsGasLiquidsEquivalentProved Plus Probable(mmcf)(mbbls)(mmcf)(mbbls)(mboe)December 31, 2018211,55423,56014,40847561,786Extensions and Improved Recovery15,8142,375––5,011Technical Revisions(16,396)(2,075)(2,267)(45)(5,230)Discoveries–––––Acquisitions57481––177Dispositions–––––Economic Factors(720)(61)(800)(34)(348)Production(9,844)(1,219)(827)(41)(3,038)December 31, 2019200,98222,75110,51535658,356(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 CostsIn 2019, Delphi brought four gross (2.6 net) wells on production. Capital to drill, complete, equip and tie-in these wells totaled $33.9 million which includes $11.3 million of capital spent on these wells in 2018 and excludes $6.9 million of capital spent in 2019 on major infrastructure. Included in these well costs is capital for major gathering and infrastructure costs in order to bring these wells into the 7-11 facility in East Bigstone. Company gross proved developed producing reserve additions (classified as extensions and improved recovery) for these wells was 1.6 mmboe resulting in a finding and development cost of $21.20 per boe. Finding and development costs for proved and proved plus probable reserves for 2019 and the last three years are presented below.20192017 – 2019 Totals/AverageProved ProducingTotal ProvedTotal Proved plus ProbableProved ProducingTotal ProvedTotal Proved plus ProbableCapital ($ thousands) Exploration and Development (“E&D”) Costs28,84928,84928,849238,727238,727238,727Change in FDC related to E&D35421,6101,400487196,993313,156Total E&D Costs29,20350,45930,249239,214435,720551,883Acquisition and Disposition (“A&D”) Costs(11,537)(11,537)(11,537)(13,290)(13,290)(13,290)Change in FDC related to A&D––––––Total A&D Costs(11,537)(11,537)(11,537)(14,141)(13,290)(13,290)Total Costs17,66638,92218,712225,924422,430538,593Reserves (mboe) Total Reserve Discoveries, Extensions & Revisions(1)9991,603(567)9,45620,42331,398Total Acquisitions and Dispositions–1241770124177Total Reserve Additions9991,727(391)9,45620,54731,575 E&D, including change in FDC related to E&D (F&D)29.2431.48n/a23.5021.3317.58E&D and A&D, including change in FDC (F,D&A)17.6922.54n/a23.8920.5617.06(1) Includes extensions and improved recovery, technical revisions, discoveries and economic factors.Delphi will release its Annual Information Form on or before March 30, 2020, which will include all required National Instrument 51-101 reserves disclosure.Net Asset ValueThe estimated net asset value of the Company at December 31, 2019 has been calculated using before tax, net present value of reserves discounted at ten percent as follows:($ millions)Proved Plus ProbableDiscounted (10%) net present value of reserves$365,398Undeveloped land$26,787Mark-to-market value of hedging contracts$6,329Total assets value $398,515Total debt plus working capital deficiency($155,297)Net asset value$243,218Common shares outstanding18,430,418Net asset value per share$13.20YE2019 NAV per share$21.30% change(38%)BOARD CHANGESIn accordance with the amended and restated Investor Rights Agreement, Delphi announces that, effective March 10, 2020, Shawn Singh, a nominee of Luminus, has been appointed to Delphi’s Board of Directors.Shawn Singh – General Counsel and Chief Compliance Officer – Luminus Management LLCShawn Singh has been General Counsel and Chief Compliance Officer for Luminus Management since August 2017. He has served as General Counsel and Chief Compliance for other investment funds, including DW Partners, Calypso Capital and Cheyne Capital. In addition, Mr. Singh was the Regulatory Counsel, Counsel and Chief Compliance Officer of Guggenheim Partners overseeing registered investment advisers. Mr. Singh was previously an associate at several large international law firms in New York including Fried, Frank, Harris, Shriver & Jacobson LLP and Norton, Rose, Fulbright, LLP. Mr. Singh holds a B. Soc Science from the University of Ottawa and received his Juris Doctorate from Brooklyn Law School.On behalf of the Board of Directors and all the employees of Delphi, we would like to thank our shareholders for their continued support.CONFERENCE CALL AND WEBCAST A conference call and webcast to review 2019 year end results is scheduled for 9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) on Thursday, March 12, 2020. The conference call number is 1-844-358-8760. A brief presentation by David J. Reid, President and CEO, Karyssa Quansah, VP Finance, and Morteza Nobakht, VP Development, will be followed by a question and answer period. The conference call will also be broadcast live on the Internet and may be accessed through www.delphienergy.ca or by entering https://edge.media-server.com/mmc/p/nhfvj55z in your web browser.A recorded rebroadcast will be archived and made available on the Company’s website at www.delphienergy.ca or by entering https://edge.media-server.com/mmc/p/nhfvj55z in your web browser. Delphi’s annual and fourth quarter 2019 financial statements and management’s discussion and analysis are available on the Company’s website at www.delphienergy.ca and SEDAR at www.SEDAR.com.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.