CALGARY, Alberta, March 12, 2020 (GLOBE NEWSWIRE) -- 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 HIGHLIGHTS
- During 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; and
- In 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 $11.5 million. The net proceeds from the Permanent Assignment Transaction were used to repay bank indebtedness.
| FINANCIAL AND OPERATIONAL HIGHLIGHTS | ||||||||||||
| Three months ended December 31 | Twelve months ended December 31 | |||||||||||
| 2019 | 2018 | % Change | 2019 | 2018 | % Change | |||||||
| Financial | ||||||||||||
| ($ thousands, except per share) | ||||||||||||
| Crude oil and natural gas revenues | 19,147 | 26,786 | (29 | ) | 93,138 | 127,254 | (27 | ) | ||||
| Net earnings (loss) | (13,082 | ) | (17,318 | ) | (24 | ) | (74,581 | ) | (26,366 | ) | 183 | |
| Per share – basic and diluted (2) | (0.89 | ) | (1.40 | ) | (36 | ) | (5.76 | ) | (2.13 | ) | 170 | |
| Cash flow from operating activities | 11,328 | 9,428 | 20 | 52,616 | 54,128 | (3 | ) | |||||
| Per share – basic and diluted(1) (2) | 0.77 | 0.76 | 1 | 4.06 | 4.25 | (4 | ) | |||||
| Adjusted funds flow(1) | 6,573 | 8,890 | (26 | ) | 52,178 | 46,615 | 12 | |||||
| Per share – basic and diluted(1) (2) | 0.45 | 0.72 | (38 | ) | 4.03 | 3.66 | 10 | |||||
| Net debt(1) | 155,297 | 181,985 | (15 | ) | 155,297 | 181,985 | (15 | ) | ||||
| Capital expenditures, net of dispositions | 2,072 | 26,942 | (92 | ) | 28,849 | 90,834 | (68 | ) | ||||
| Weighted average shares (000s) (2) | ||||||||||||
| Basic | 14,675 | 12,370 | 19 | 12,951 | 12,730 | 5 | ||||||
| Diluted | 14,675 | 12,370 | 19 | 12,951 | 12,730 | 5 | ||||||
| Operating | ||||||||||||
| (boe conversion – 6:1 basis) | ||||||||||||
| Production: | ||||||||||||
| Field condensate (bbls/d) | 1,747 | 2,644 | (34 | ) | 2,245 | 2,542 | (12 | ) | ||||
| Natural gas liquids (bbls/d) | 1,027 | 1,289 | (20 | ) | 1,209 | 1,411 | (14 | ) | ||||
| Natural gas (mcf/d) | 25,487 | 33,063 | (23 | ) | 29,237 | 34,925 | (16 | ) | ||||
| Total (Boe/d) | 7,022 | 9,444 | (26 | ) | 8,327 | 9,774 | (15 | ) | ||||
| Average realized sales prices, before financial instruments | ||||||||||||
| Field condensate ($/bbl) | 64.84 | 42.66 | 52 | 64.92 | 66.96 | (3 | ) | |||||
| Natural gas liquids ($/bbl) | 19.07 | 38.87 | (51 | ) | 24.58 | 44.88 | (45 | ) | ||||
| Natural gas ($/mcf) | 2.94 | 3.71 | (21 | ) | 2.70 | 3.23 | (16 | ) | ||||
| Netbacks ($/boe) | ||||||||||||
| Crude oil and natural gas revenues | 29.63 | 30.83 | (4 | ) | 30.65 | 35.68 | (14 | ) | ||||
| Marketing income (1) | 0.03 | 1.61 | (98 | ) | 1.47 | 1.41 | 4 | |||||
| Realized gain (loss) on financial instruments | 5.78 | (3.38 | ) | (271 | ) | 4.38 | (3.47 | ) | (226 | ) | ||
| Revenue, after realized financial instruments | 35.44 | 29.06 | 22 | 36.50 | 33.62 | 9 | ||||||
| Royalties | (2.43 | ) | (1.72 | ) | 41 | (2.13 | ) | (2.08 | ) | 2 | ||
| Operating expense | (10.01 | ) | (7.33 | ) | 37 | (9.44 | ) | (8.38 | ) | 13 | ||
| Transportation expense | (4.43 | ) | (4.43 | ) | - | (4.31 | ) | (4.86 | ) | (11 | ) | |
| Operating netback (1) | 18.57 | 15.58 | 19 | 20.62 | 18.30 | 13 | ||||||
| Permanent Assignment Transaction | (0.01 | ) | - | - | 3.80 | - | - | |||||
| General and administrative expenses | (1.58 | ) | (1.61 | ) | (2 | ) | (1.74 | ) | (1.61 | ) | 8 | |
| Finance charges | (6.56 | ) | (3.54 | ) | 85 | (5.29 | ) | (3.43 | ) | 54 | ||
| Settlement of unutilized take-or-pay contract | (0.26 | ) | (0.19 | ) | 37 | (0.22 | ) | (0.19 | ) | 16 | ||
| Cash netback (1) | 10.16 | 10.24 | (1 | ) | 17.17 | 13.07 | 31 | |||||
(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 SHAREHOLDERS
In 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, 2019
Upon 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.
HEDGING
Delphi’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 REVIEW
The 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 $7.9MM per well which is 23% lower than the 13-34. This reduction in capital cost per well will significantly improve the economic metrics of Bigstone Montney.
| On Production Year | Well Count | Spud to RR | Drill Days | Stage Count | Total Sand | Drilling Cost | Completions Cost | Total | |||
| (days) | (days) | (tonnes) | (C$ thousands) | (C$ thousands) | (C$ thousands) | ||||||
| 2015 & Prior | 24 | 42 | 35 | 29 | 2,007 | $5,361 | $4,710 | $10,071 | |||
| 2016 | 6 | 33 | 28 | 39 | 3,918 | $3,985 | $3,721 | $7,706 | |||
| 2017 | 15 | 33 | 28 | 40 | 4,634 | $3,744 | $4,305 | $8,049 | |||
| 2018 | 12 | 31 | 25 | 49 | 4,291 | $4,125 | $5,216 | $9,341 | |||
| 2019 | 4 | 33 | 27 | 60 | 4,771 | $4,594 | $5,578 | $10,172 | |||
| 2020 | 2 | 17.8 | 12.8 | 65 | 5,200 | $3,400 | $4,500 | $7,900 | |||
RESERVES HIGHLIGHTS
- Successfully 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 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, 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 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 | 5,016 | 4,443 | 45,346 | 40,574 | 4,606 | 3,593 | 12,999 | 11,096 | |
| Developed Non-Producing | - | - | - | - | - | - | - | - | |
| Undeveloped | - | - | 58,177 | 54,537 | 7,399 | 6,508 | 17,095 | 15,598 | |
| Total Proved | 5,016 | 4,443 | 103,523 | 95,111 | 12,005 | 10,102 | 30,095 | 26,694 | |
| Total Probable | 5,499 | 4,934 | 97,460 | 89,826 | 11,102 | 8,877 | 28,262 | 24,670 | |
| Total Proved Plus Probable | 10,515 | 9,378 | 200,982 | 184,937 | 23,107 | 18,979 | 58,356 | 51,364 | |
(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 Revenue
The 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 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 | 190,210 | 158,389 | 135,179 | 117,994 | 104,954 | 12.18 | 2.03 | ||||||
| Developed Non-Producing | - | - | - | - | - | - | - | ||||||
| Undeveloped | 184,754 | 116,231 | 73,448 | 45,815 | 27,348 | 4.71 | 0.78 | ||||||
| Total Proved | 374,964 | 274,619 | 208,627 | 163,810 | 132,302 | 7.82 | 1.30 | ||||||
| Total Probable | 456,420 | 256,237 | 156,771 | 103,075 | 71,873 | 6.35 | 1.06 | ||||||
| Total Proved Plus Probable | 831,384 | 530,856 | 365,398 | 266,885 | 204,175 | 7.11 | 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 $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) | 2020 | 2021 | 2022 | 2023 | 2024 | Rem | Total |
| Total Proved | 37 | 93 | 76 | 49 | 0 | 0 | 255 |
| Total Proved Plus Probable | 37 | 93 | 81 | 123 | 59 | 82 | 475 |
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 |
| 2020 | 2.08 | 2.42 | 71.71 | 61.00 | 77.80 | 0.0 | 0.760 |
| 2021 | 2.35 | 2.75 | 74.03 | 63.00 | 79.22 | 2.0 | 0.770 |
| 2022 | 2.55 | 2.90 | 76.92 | 66.00 | 83.33 | 2.0 | 0.780 |
| 2023 | 2.65 | 3.00 | 80.13 | 68.00 | 86.54 | 2.0 | 0.780 |
| 2024 | 2.75 | 3.10 | 82.69 | 70.00 | 89.10 | 2.0 | 0.780 |
| 2025 | 2.85 | 3.20 | 85.26 | 72.00 | 91.67 | 2.0 | 0.780 |
| 2026 | 2.91 | 3.27 | 87.82 | 74.00 | 94.23 | 2.0 | 0.780 |
| 2027 | 2.97 | 3.33 | 90.14 | 75.81 | 96.55 | 2.0 | 0.780 |
| 2028 | 3.03 | 3.40 | 92.09 | 77.33 | 98.50 | 2.0 | 0.780 |
| 2029 | 3.09 | 3.47 | 94.08 | 78.88 | 100.49 | 2.0 | 0.780 |
| 2030+ | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | 2.0 | 0.780 |
Reserves(1) Reconciliation
The 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 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, 2018 | 106,539 | 12,113 | 7,820 | 232 | 31,405 |
| Extensions and Improved Recovery | 12,704 | 1,601 | - | - | 3,718 |
| Technical Revisions | (6,068) | (695) | (1,450) | (9) | (1,957) |
| Discoveries | - | - | - | - | - |
| Acquisitions | 413 | 55 | - | - | 124 |
| Dispositions | - | - | - | - | - |
| Economic Factors | (221) | (9) | (527) | (23) | (157) |
| Production | (9,844) | (1,219) | (827) | (41) | (3,038) |
| December 31, 2019 | 103,523 | 11,845 | 5,016 | 160 | 30,095 |
| | |||||
| 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, 2018 | 105,016 | 11,537 | 6,588 | 243 | 30,380 |
| Extensions and Improved Recovery | 3,110 | 774 | - | - | 1,293 |
| Technical Revisions | (10,328) | (1,380) | (816) | (36) | (3,273) |
| Discoveries | - | - | - | - | - |
| Acquisitions | 161 | 26 | - | - | 53 |
| Dispositions | - | - | - | - | - |
| Economic Factors | (499) | (52) | (273) | (11) | (192) |
| Production | - | - | - | - | - |
| December 31, 2019 | 97,460 | 10,905 | 5,499 | 196 | 28,262 |
| 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, 2018 | 211,554 | 23,560 | 14,408 | 475 | 61,786 |
| Extensions and Improved Recovery | 15,814 | 2,375 | - | - | 5,011 |
| Technical Revisions | (16,396) | (2,075) | (2,267) | (45) | (5,230) |
| Discoveries | - | - | - | - | - |
| Acquisitions | 574 | 81 | - | - | 177 |
| Dispositions | - | - | - | - | - |
| Economic Factors | (720) | (61) | (800) | (34) | (348) |
| Production | (9,844) | (1,219) | (827) | (41) | (3,038) |
| December 31, 2019 | 200,982 | 22,751 | 10,515 | 356 | 58,356 |
(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 Costs
In 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 $21.20 per boe. Finding and development costs for proved and proved plus probable reserves for 2019 and the last three years are presented below.
| 2019 | 2017 - 2019 Totals/Average | |||||||||||||||
| Proved Producing | Total Proved | Total Proved plus Probable | Proved Producing | Total Proved | Total Proved plus Probable | |||||||||||
| Capital ($ thousands) | ||||||||||||||||
| Exploration and Development ("E&D") Costs | 28,849 | 28,849 | 28,849 | 238,727 | 238,727 | 238,727 | ||||||||||
| Change in FDC related to E&D | 354 | 21,610 | 1,400 | 487 | 196,993 | 313,156 | ||||||||||
| Total E&D Costs | 29,203 | 50,459 | 30,249 | 239,214 | 435,720 | 551,883 | ||||||||||
| Acquisition 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 Costs | 17,666 | 38,922 | 18,712 | 225,924 | 422,430 | 538,593 | ||||||||||
| Reserves (mboe) | ||||||||||||||||
| Total Reserve Discoveries, Extensions & Revisions(1) | 999 | 1,603 | (567 | ) | 9,456 | 20,423 | 31,398 | |||||||||
| Total Acquisitions and Dispositions | - | 124 | 177 | 0 | 124 | 177 | ||||||||||
| Total Reserve Additions | 999 | 1,727 | (391 | ) | 9,456 | 20,547 | 31,575 | |||||||||
| E&D, including change in FDC related to E&D (F&D) | 29.24 | 31.48 | n/a | 23.50 | 21.33 | 17.58 | ||||||||||
| E&D and A&D, including change in FDC (F,D&A) | 17.69 | 22.54 | n/a | 23.89 | 20.56 | 17.06 | ||||||||||
(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 Value
The 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 Probable | ||
| Discounted (10%) net present value of reserves | $365,398 | ||
| Undeveloped land | $26,787 | ||
| Mark-to-market value of hedging contracts | $6,329 | ||
| Total assets value | $398,515 | ||
| Total debt plus working capital deficiency | ($155,297) | ||
| Net asset value | $243,218 | ||
| Common shares outstanding | 18,430,418 | ||
| Net asset value per share | $13.20 | ||
| YE2019 NAV per share | $21.30 | ||
| % change | (38%) |
BOARD CHANGES
In 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 LLC
Shawn 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.
| 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 | DARWIN LITTLE | |
| President & CEO | CFO | |
Forward-Looking Statements. This news release contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relate to future events or the Company’s future performance and are based upon the Company’s internal assumptions and expectations. All statements other than statements of present or historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “should”, “believe”, "intends”, “forecast”, “plans”, “guidance”, “budget” and similar expressions.
More particularly and without limitation, this release contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crude oil and natural gas prices, future exchange rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general and administrative costs and interest expense, expectations as to capital expenditures and net debt, planned capital spending, future liquidity and Delphi’s ability to fund ongoing capital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for oil and gas commodities, timing and success of development and exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure, treatment under governmental regulatory regimes and tax laws and future environmental regulations.
Furthermore, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitable in the future.
The forward-looking statements and information contained in this release are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which the forward-looking statements and information contained in this release are based: satisfaction of all conditions to completion of the Recapitalization Transaction; the timely receipt of required regulatory, shareholder, noteholder, lender and other approvals; the stability of the global and national economic environment, the stability of and commercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management’s expectations, production levels of Delphi being consistent with management’s expectations, the absence of significant project delays, the stability of oil and gas prices, the absence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, including operating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oil and natural gas volumes, prices and availability of oilfield services and equipment being consistent with management’s expectations, the availability of, and competition for, among other things, pipeline capacity, skilled personnel and drilling and related services and equipment, results of development and exploitation activities that are consistent with management’s expectations, weather affecting Delphi’s ability to develop and produce as expected, contracted parties providing goods and services on the agreed timeframes, Delphi’s ability to manage environmental risks and hazards and the cost of complying with environmental regulations, the accuracy of operating cost estimates, the accurate estimation of oil and gas reserves, future exploitation, development and production results and Delphi’s ability to market oil and natural gas successfully to current and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that the Company relies on to produce its wells, that existing wells continue to meet production expectations and any future wells scheduled to come on in the coming year meet timing and production expectations.
Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply and demand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of material variances from previously communicated expectations.
Financial outlook information contained in this release about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this release should not be used for purposes other than for which it is disclosed.
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 and such forward-looking statements should not be unduly relied upon. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent known and unknown risks and uncertainties. Delphi’s actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Delphi will derive therefrom. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary 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 from others for scarce resources, the ability to access sufficient capital from internal and external sources, changes in governmental regulation of the oil and gas industry 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 the Company’s most recent Annual Information Form and other reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
Readers are cautioned that the foregoing list of factors is not exhaustive. Furthermore, the forward-looking statements contained in this release are made as of the date of this release 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. The forward-looking statements contained in this release are expressly qualified in their entirety by this cautionary statement.
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 to the Canadian Securities Administrators’ National Instrument 51-101 when boes are disclosed. Boes may be misleading, particularly if used in isolation.
As per CSA Staff Notice 51-327 initial test results and initial production performance should be considered preliminary data and such data is not necessarily indicative of long-term performance or of ultimate recovery. “IP” is an abbreviation for “Initial Production” and represents average production rates over the indicated time period in producing days.
Non-GAAP Measures. The release contains the terms “adjusted funds flow”, “adjusted funds flow per share”, “net debt”, “net debt to adjusted funds flow ratio”, “marketing income”, “operating netbacks”, “total cash revenues”, “cash netbacks,” and “netbacks” which are not recognized measures under GAAP. 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 and costs of production. Management uses adjusted funds flow 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, abandonment obligations and to repay debt. Adjusted funds flow is a non-GAAP measure and has been defined by the Company as cash flow from operating activities before decommissioning expenditures and changes in non-cash working capital from operating activities. The Company also presents adjusted funds flow 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 adjusted funds flow 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 GAAP. Delphi has defined total cash revenues as the sum of crude oil and natural gas revenues, marketing revenue (excluding Permanent Assignment Transaction) and realized gains on risk management contracts. Management uses this measure to assess the revenues from operations and risk mitigation activities. The Company has defined net debt as the sum of bank debt, senior secured notes and the long term portion of unutilized take-or-pay contract and leases plus/minus working capital deficit/surplus excluding the current portion of the fair value of financial instruments. Net debt is used by management to monitor remaining availability under its credit facilities. Marketing income is defined as the margin earned on the sale of purchased third party natural gas volumes and premiums received on the assignment of a portion of committed capacity on the Alliance pipeline system to a third party. Management considers marketing income important measures of the Company’s ability to mitigate the cost of excess committed capacity. Operating netbacks have been defined as revenue plus marketing income less royalties, transportation and operating costs. Cash netbacks have been defined as operating netbacks less interest on bank debt and senior secured notes, finance charges associated with lease obligations, general and administrative costs and cash costs related to the Company’s restricted share units. Netbacks are generally discussed and presented on a per boe basis.