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Kelt Reports Significant Increases in Oil & Gas Reserves and Net Asset Value per Share as at December 31, 2019


Calgary, Alberta – Kelt Exploration Ltd. (TSX: KEL) (“Kelt” or the “Company”) is pleased to report on its oil & gas reserves and production for the year ended December 31, 2019.

The audit of Kelt’s 2019 annual consolidated financial statements has not been completed and accordingly all financial amounts relating to 2019 referred to in this press release are unaudited and represent management’s estimates. Readers are advised that these financial estimates are subject to audit and may be subject to change.

HIGHLIGHTS

$M unless otherwise stated December 31, 2019 December 31, 2018 Change
% Weight Amount % Weight Amount
Proved plus Probable Reserves
   Oil & NGLs [Mbbls] 47% 216,324 43% 128,847 + 68%
   Gas [MMcf] 53% 1,467,941 57% 1,042,987 + 41%
   Combined [MBOE] 100% 460,981 100% 302,678 + 52%
Oil & NGLs Mix [P+P Reserves, Mbbls]
   Light Oil, Condensate and Pentane 62% 133,150 64% 83,040 + 60%
   Butane 11% 24,282 11% 14,389 + 69%
   Propane 22% 46,746 20% 26,322 + 78%
   Ethane 5% 12,146 5% 5,096 + 138%
   Total Oil & NGLs 100% 216,324 100% 128,847 + 68%
Net Present Value of Reserves [10% BT]
   Proved Developed Producing 514,261 481,113 + 7%
   Proved 1,899,665 1,499,241 + 27%
   Proved plus Probable 3,988,482 3,128,636 + 27%
Annual Average Production
   Oil & NGLs [bbls/d] 46% 13,851 43% 11,589 + 20%
   Gas [Mcf/d] 54% 96,658 57% 92,502 + 4%
   Combined [BOE/d] 100% 29,961 100% 27,006 + 11%
Net Asset Value [1] 4,040,164 3,209,319 + 26%
Net Asset Value per share – diluted [$] 18.78 15.51 + 21%
Note:
[1] Net present value of proved plus probable reserves used in the calculation of net asset value is based on a 10% discount rate, before tax. More detailed information is available in the “Net Asset Value per Share” table provided in this press release. Refer to advisories regarding Non-GAAP Financial Measures and Other Key Performance Indicators. Also refer to Measurements and Abbreviations.

OPERATIONS UPDATE

Kelt achieved a record high calendar year average production in 2019. Average production for 2019 was 29,961 BOE per day, up 11% from average production of 27,006 BOE per day in 2018. Production for 2019 was weighted 46% oil and NGLs and 54% gas. Average production for 2019 was 2% to 5% below the Company’s guidance of 30,500 to 31,500 BOE per day range, primarily due to infrastructure related delays in the Wembley/Pipestone area.

During the fourth quarter of 2019, Kelt took advantage of service accessibility (bi-fuel frac equipment and access to water) and completed three wells at Inga on its 24-well Montney cube pad that were previously planned for the first quarter of 2020. In addition, Kelt had originally planned to install gas compression at Wembley/Pipestone in 2020, however, due to higher than anticipated pipeline pressures relating to infrastructure connecting Kelt’s wells to the Pipestone Sour Deep-Cut Gas Processing Plant, the Company installed compression during the fourth quarter of 2019. Net capital expenditures for 2019 were $315.6 million (unaudited), approximately 7% above budgeted capital expenditures of $296.0 million. In connection with moving forward to 2019 certain capital expenditures planned for 2020, Kelt completed a flow-through equity financing during the fourth quarter of 2019. The Company issued 3.45 million common shares on a flow-through basis in respect of Canadian Development Expenses at a price of $5.05 per share for gross proceeds of $17.4 million.

During the twenty-four months ending March 31, 2020, Kelt will have incurred significant infrastructure capital expenditures that will benefit future production additions from new development wells in its main operating divisions. The Company will have installed approximately 287,000 metres of pipelines ranging from 6-inch to 16-inch pipe that will transport oil, emulsion, water, sweet gas and sour gas from Kelt wells to processing facilities.

In 2017, Kelt made an application to the British Columbia Infrastructure Royalty Credit Program and was approved for its planned infrastructure build in certain parts of its Inga/Fireweed property relating to expenditures totaling approximately $38.6 million. The Government of British Columbia approved a recovery of approximately 39% of Kelt’s infrastructure expenditures or $15.0 million through reduced future royalties payable relating to 20 horizontal Montney wells associated with the infrastructure. The Company has drilled and completed 10 of the Montney wells at Inga and has commenced drilling operations on the remaining 10 Montney wells at Fireweed. To date, the Company has recovered approximately $1.3 million under this program.

In 2019, Kelt made an application to the British Columbia Clean Growth Infrastructure Royalty Credit Program and was approved for its planned infrastructure build in certain parts of its Oak/Flatrock property relating to expenditures totaling approximately $49.5 million. The Government of British Columbia has approved a recovery of approximately 37% of Kelt’s infrastructure expenditures or $18.5 million through reduced future royalties payable relating to 22 horizontal Montney wells associated with the infrastructure. The Company drilled and completed two of these wells in 2019 and is currently drilling another nine Montney well program at Oak during the first half of 2020.

Kelt’s commodity price forecast for 2020 differs from those used by Sproule Associates Limited (“Sproule”). Kelt’s forecasted WTI crude oil price for 2020 is US$52.00 per barrel (unchanged from its previous forecast). The Company has taken measures to secure a portion of its adjusted funds from operations in 2020 by entering into the following oil related swaps:

  • Fixed the WTI price on 6,000 barrels per day for the first quarter of 2020 at CA$75.63 per barrel (equivalent to US$57.30 per barrel at Kelt’s 2020 forecasted CAD/USD exchange rate of 1.320);
  • Fixed the WTI price on 3,000 barrels per day for the second quarter of 2020 at CA$79.40 per barrel (equivalent to US$60.15 per barrel at Kelt’s 2020 forecasted CAD/USD exchange rate of 1.320); and
  • Fixed the WTI to MSW basis differential on 3,000 barrels per day for the second quarter of 2020 at CA$6.40 per barrel (equivalent to US$4.85 per barrel at Kelt’s 2020 forecasted CAD/USD exchange rate of 1.320).

The Company has reduced its NYMEX Henry Hub natural gas forecast for 2020 to US$2.25 per MMBtu, down 18% from its previous forecast. Kelt estimates that the CAD/USD exchange rate will average 1.320 (US$0.758), up 1% from its previous forecast of 1.307 (US$0.765).

After taking into consideration these revised commodity price forecasts for 2020 and including the hedging contracts, Kelt is forecasting 2020 adjusted funds from operations of $225.0 million, down 4% from its previous forecast. In addition, Kelt has reduced its 2020 capital expenditure forecast from $235.0 million to $225.0 million, in part to reflect the planned 2020 expenditures that were brought forward and incurred in 2019.

RESERVES

Kelt retained Sproule Associates Limited (“Sproule”), an independent qualified reserve evaluator to prepare a report on its oil and gas reserves. The report is effective as of December 31, 2019. The Company has a Reserves Committee which oversees the selection, qualifications and reporting procedures of the independent qualified reserves evaluator. Reserves as at December 31, 2019 and at December 31, 2018 were determined using the guidelines and definitions set out under National Instrument 51-101 (“NI 51-101”). Additional reserves disclosure as required under NI 51-101 will be included in Kelt’s Annual Information Form which will be filed on SEDAR on or before March 31, 2020.

The Company’s net present value of proved plus probable reserves at December 31, 2019, discounted at 10% before tax, was $4.0 billion, an increase of 27% from $3.1 billion at December 31, 2018, despite lower forecasted oil and gas prices for the future years in the December 31, 2019 evaluation (see “Commodity Prices” table included below). Sproule’s forecasted commodity prices for 2020 used to determine the net present value of the Company’s reserves at December 31, 2019, are USD 61.00 per barrel for WTI oil and USD 2.80 per MMBtu for NYMEX Henry Hub natural gas.

Proved developed producing reserves at December 31, 2019 were 48.9 million BOE, an increase of 20% from 40.7 million BOE at December 31, 2018. Total proved reserves at December 31, 2019 were 224.6 million BOE, up 42% from 158.4 million BOE at December 31, 2018. Proved plus probable reserves increased by 52% from 302.7 million BOE at December 31, 2018 to 461.0 million BOE at December 31, 2019.

The following table outlines a summary of the Company’s reserves by category at December 31, 2019:

Summary of Reserves
Oil & NGLs
[Mbbls]
Gas
[MMcf]
Combined
[MBOE]
NPV10% BT
[$M]
NPV10% BT
[$/BOE]
Proved Developed Producing 21,522 163,994 48,854 514,261 10.53
Total Proved 103,292 727,740 224,582 1,899,665 8.46
Total Proved plus Probable 216,324 1,467,941 460,981 3,988,482 8.65

The following table shows the change in reserves year-over-year by reserve category:

Change in Reserves
[MBOE] December 31, 2019 December 31, 2018 Percent Change
Proved Developed Producing 48,854 40,702 + 20%
Total Proved 224,582 158,443 + 42%
Total Proved plus Probable 460,981 302,678 + 52%

FUTURE DEVELOPMENT CAPITAL EXPENDITURES

Future development capital (“FDC”) expenditures of $1,379 million are included in the evaluation for total proved reserves and are expected to be incurred over five years as follows: $149 million in 2020, $328 million in 2021, $337 million in 2022, $384 million in 2023 and $181 million in 2024. FDC expenditures of $2,454 million are included in the evaluation of proved plus probable reserves and are expected to be incurred over seven years as follows: $163 million in 2020, $381 million in 2021, $400 million in 2022, $454 million in 2023, $451 million in 2024, $345 million in 2025 and $260 million in 2026.

The following table outlines FDC expenditures and future wells to be drilled by province, included in the December 31, 2019 and December 31, 2018 proved plus probable reserve evaluations:

Future Development Capital Expenditures – Proved plus Probable Reserves
December 31, 2019 December 31, 2018
FDC [$M] Net Wells FDC [$M] Net Wells
Alberta Montney wells 581,614 101.3 331,835 59.3
British Columbia Montney wells 1,463,797 270.0 743,803 140.0
Total Montney wells 2,045,411 371.3 1,075,638 199.3
Other formations (including Doig/Charlie Lake) 355,148 85.4 355,088 76.6
Other expenditures 53,888 43,372
Total FDC Expenditures 2,454,447 456.8 1,474,098 275.9

OPERATING DIVISIONS

Kelt has five operating divisions. The Inga/Fireweed division is primarily a light oil/condensate-rich gas Montney play with condensate-rich gas Doig development potential. The Pouce Coupe/Progress division has light oil and liquids-rich gas development potential in the Montney, Doig, Charlie Lake and Halfway formations. The Wembley/Pipestone division is primarily a light oil/condensate-rich gas Montney play.

The Oak/Flatrock division is the least developed in the Company’s portfolio. Kelt has three producing Montney wells in this division and expects to drill nine Upper Montney wells and one Middle Montney well at Oak/Flatrock in 2020. The Grande Cache division is primarily a Cretaceous gas development area.

Operating Divisions
Proved Reserves [MBOE] Proved
NPV 10% BT [$M]
Proved + Probable Reserves [MBOE] Proved + Probable
NPV 10% BT [$M]
Montney Acres [Sections]
Inga/Fireweed 139,345 1,331,209 301,361 2,877,302 139,963 [219]
Pouce Coupe/Progress 47,179 352,056 75,539 583,639 36,239 [57]
Wembley/Pipestone 30,157 212,561 62,716 472,156 107,155 [167]
Other Properties [1] [2] 7,901 3,839 21,365 55,385 233,851 [365]
Total Company 224,582 1,899,665 460,981 3,988,482 517,208 [808]
Notes:
[1] Other properties includes the Oak/Flatrock division, the Grande Cache division and miscellaneous minor properties.
[2] Of the Montney rights included in other properties, 204,988 acres (320 sections) are in the Oak/Flatrock division.

COMMODITY PRICE FORECAST

The WTI oil price during 2019 averaged USD 56.98 per barrel, 10% lower than Sproule’s 2019 forecast provided in the December 31, 2018 evaluation. Sproule is forecasting an average WTI oil price of USD 61.00 per barrel in 2020, a 9% decline from its previous forecast. The NYMEX gas price during 2019 averaged USD 2.62 per MMBtu, 13% lower than Sproule’s 2019 forecast provided in the December 31, 2018 evaluation. Sproule is forecasting an average NYMEX gas price of USD 2.80 per MMBtu in 2020, a 14% decline from its previous forecast.

The following table outlines forecasted future prices that Sproule has used in their evaluation of the Company’s reserves:

Commodity Prices
December 31, 2019 Evaluation December 31, 2018 Evaluation
WTI Cushing
Crude Oil
[USD/bbl]
NYMEX
Henry Hub
[USD/MMBtu]
USD/CAD
Exchange
[USD]
WTI Cushing Crude Oil
[USD/bbl]
NYMEX
Henry Hub
[USD/MMBtu]
USD/CAD
Exchange
[USD]
2015 (historical) 48.80 2.63 0.783 48.80 2.63 0.783
2016 (historical) 43.32 2.55 0.755 43.32 2.55 0.755
2017 (historical) 50.88 3.07 0.770 50.88 3.07 0.770
2018 (historical) 64.94 3.04 0.771 64.94 3.04 0.771
2019 (historical/future) 56.98 − 10% 2.62 − 13% 0.754 − 2% 63.00 3.00 0.770
2020 (future) 61.00 − 9% 2.80 − 14% 0.760 − 5% 67.00 3.25 0.800
2021 (future) 65.00 − 7% 3.00 − 14% 0.770 − 4% 70.00 3.50 0.800
2022 (future) 67.00 − 6% 3.25 − 9% 0.800 0% 71.40 3.57 0.800
2023 (future) 68.34 − 6% 3.32 − 9% 0.800 0% 72.83 3.64 0.800
Note:
Percent change in the above table shows the change in price used in the December 31, 2019 evaluation compared to the price used in the December 31, 2018 evaluation for the respective calendar years from 2019 to 2023.

FINDING, DEVELOPMENT & ACQUISITION COSTS

During 2019, the Company’s capital expenditures, net of dispositions, resulted in proved plus probable reserve additions of 169.2 million BOE, resulting in 2P finding, development and acquisition (“FD&A”) costs of $7.66 per BOE, including FDC expenditures. Proved reserve additions in 2019 were 77.1 million BOE, resulting in 1P FD&A costs of $10.68 per BOE, including FDC expenditures.

Estimated capital expenditures, after minor dispositions, in 2019 were $315.6 million (unaudited). The Company considers the calculated FD&A costs in 2019 to be a very good result considering it incurred significant infrastructure expenditures during 2019. Kelt was able to show a 2P recycle ratio of 2.5 times for the year.

The recycle ratio is a measure for evaluating the effectiveness of a company’s re-investment program. The ratio measures the efficiency of capital investment. It accomplishes this by comparing the operating netback per BOE to the same period’s reserve FD&A cost per BOE. With the construction of facilities and infrastructure in 2018 and 2019, along with land acquisitions during both years, Kelt has positioned itself to achieve further efficiencies in production additions and finding and development costs over the upcoming years, as it continues to proceed with development and pad drilling.

The following table provides detailed calculations relating to FD&A costs for 2019 and 2018:

Year ended
December 31, 2019
Year ended
December 31, 2018
Proved Reserves
Capital expenditures [$000’s] (2019 unaudited) 315,624 285,498
Change in FDC costs required to develop reserves [$000’s] 507,348 95,548
Total capital costs [$000’s] 822,972 381,046
Reserve additions, net [MBOE] 77,053 35,298
FD&A cost, including FDC [$/BOE] 10.68 10.80
Operating netback [$/BOE] (2019 unaudited) 18.89 20.56
Recycle ratio – proved 1.8 x 1.9 x
Proved plus Probable Reserves
Capital expenditures [$000’s] (2019 unaudited) 315,624 285,498
Change in FDC costs required to develop reserves [$000’s] 980,349 310,506
Total capital costs [$000’s] 1,295,973 596,004
Reserve additions, net [MBOE] 169,217 76,905
FD&A cost, including FDC [$/BOE] 7.66 7.75
Operating netback [$/BOE] (2019 unaudited) 18.89 20.56
Recycle ratio – proved plus probable 2.5 x 2.7 x

RESERVES RECONCILIATION

Kelt’s 2019 capital investment program resulted in net proved plus probable reserve additions that replaced 2019 production by a factor of 15.5 times.

A reconciliation of Kelt’s proved plus probable reserves is provided in the table below:

Proved plus Probable Reserves
Oil & NGLs
[Mbbls]
Gas
[MMcf]
Combined
[MBOE]
Balance, December 31, 2018 128,847 1,042,987 302,678
Extensions and infill drilling 86,910 437,634 159,849
Technical revisions and economic factors 5,574 21,953 9,233
Acquisitions 49 515 135
Dispositions
Additions, after dispositions (“Net additions”) 92,533 460,102 169,217
Less: 2019 Production [1] (5,056) (35,148) (10,914)
Balance, December 31, 2019 216,324 1,467,941 460,981
Note:
[1] Sulphur production of 13,186 Lt (132 MMcfe or 22 MBOE) has been excluded in the above table.

Continued outperformance of existing producing wells compared with the previous year’s forecasts resulted in significant positive technical revisions to both producing wells and offsetting future development locations. Notably, in Inga/Fireweed, the Upper Montney type curve was adjusted upward and the results from the 2019 drilling program increased the overall play maturity resulting in additional proved plus probable reserve bookings.

NET ASSET VALUE

Kelt’s net asset value at December 31, 2019 was $18.78 per share, up 21% from the previous year. Details of the calculation are shown in the table below:

Net Asset Value per Share
[ $M unless otherwise stated ] December 31, 2019 December 31, 2018 Percent Change
P&NG proved plus probable reserves, NPV10% BT [1] 3,988,482 3,119,592 + 28%
Undeveloped land 350,617 279,739 + 25%
Net bank debt [unaudited] (328,080) (196,416) + 67%
Proceeds from exercise of stock options [2] 29,145 6,404 + 355%
Net asset value 4,040,164 3,209,319 + 26%
Diluted common shares outstanding (000’s) [2] [3] 215,187 206,978 + 4%
Net asset value per share ($/share) 18.78 15.51 + 21%
Notes:
[1] Includes the net present value of the Company’s estimated decommissioning obligations. Approximately $9.0 million of incremental decommissioning obligation costs were deducted from the amount included in the present value of P&NG reserves as evaluated by Sproule as at December 31, 2018.
[2] The calculation of proceeds from exercise of stock options and the diluted number of common shares outstanding only include stock options that are “in-the-money” based on the closing price of KEL of $4.87 and $4.64 per common share respectively, as at December 31, 2019 and 2018. All outstanding RSUs are included in diluted common shares outstanding.
[3] The 5% convertible debentures that mature on May 31, 2021 are convertible to common shares at $5.50 per share. At the December 31, 2019 closing price of $4.87 per share, the convertible debentures are “out-of-the-money” and 19.4 million shares issuable at a 5% discount are included in diluted common shares outstanding. At the December 31, 2018 closing price of $4.64, the convertible debentures are “out-of-the-money” and 20.4 million shares issuable at a 5% discount are included in diluted common shares outstanding.

Changes in forecasted commodity prices and variances in production estimates can have a significant impact on estimated reserves values, adjusted funds from operations and profit. Please refer to the cautionary statement on forward-looking statements and information set out below.



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