Kelt Reports Significant Increases in Oil & Gas Reserves and Net Asset Value per Share as at December 31, 2018
Kelt Exploration Ltd. (TSX:KEL.TO) ("Kelt" or the "Company") is pleased to report on its oil & gas reserves and production for the year ended December 31, 2018.
[Kelt's audit of its 2018 annual consolidated financial statements has not been completed and accordingly all financial amounts relating to 2018 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].
[$M unless otherwise stated] December 31, 2018 December 31, 2017 Change % Weight Amount % Weight Amount Proved plus Probable Reserves Oil & NGLs [Mbbls] 43% 128,847 43% 101,788 + 27% Gas [MMcf] 57% 1,042,987 57% 802,875 + 30% Combined [MBOE] 100% 302,678 100% 235,601 + 28% Net Present Value of Reserves (10% BT) Proved Developed Producing 481,113 422,932 + 14% Proved 1,499,241 1,093,236 + 37% Proved plus Probable 3,128,636 2,111,574 + 48% Properties (P+P Reserves, NPV 10% BT) Inga/Fireweed 61% 1,906,732 55% 1,156,731 + 65% Pouce Coupe/Progress 19% 605,787 27% 578,737 + 5% La Glace/Wembley/Pipestone 12% 368,250 7% 154,592 + 138% Oak/Flatrock 2% 62,218 1% 21,721 + 186% Other Properties 6% 185,649 10% 199,793 â?' 7% Total Company 100% 3,128,636 100% 2,111,574 + 48% Annual Average Production Oil & NGLs [bbls/d] 43% 11,589 42% 9,242 + 25% Gas [Mcf/d] 57% 92,502 58% 77,330 + 20% Combined [BOE/d] 100% 27,006 100% 22,130 + 22% Net Asset Value  3,209,319 2,261,509 + 42% Net Asset Value per share - diluted [$] 15.51 11.06 + 40% Note:  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.
Kelt achieved a record high calendar year average production in 2018. Average production for 2018 was 27,006 BOE per day, up 22% from average production of 22,130 BOE per day in 2017. Production for 2018 was weighted 43% oil and NGLs and 57% gas.
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, 2018. 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, 2018 and at December 31, 2017 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, 2019.
The Company's net present value of proved plus probable reserves at December 31, 2018, discounted at 10% before tax, was $3.1 billion, an increase of 48% from $2.1 billion at December 31, 2017, despite lower forecasted oil and gas prices for the future years in the December 31, 2018 evaluation (see "Commodity Prices" table included below). Sproule's forecasted commodity prices for 2019 used to determine the net present value of the Company's reserves at December 31, 2018, are USD 63.00 per barrel for WTI oil and USD 3.00 per MMBtu for NYMEX Henry Hub natural gas. As a result of the Company's gas market diversification strategy, Kelt is forecasting that less than 20% of its 2019 gas production will be sold into the western Canadian gas markets. The remaining forecasted gas production for 2019 is expected to be sold into the higher netback Dawn, Malin, Sumas and Chicago markets under existing contracts.
Proved developed producing reserves at December 31, 2018 were 40.7 million BOE, an increase of 8% from 37.9 million BOE at December 31, 2017. Total proved reserves at December 31, 2018 were 158.4 million BOE, up 19% from 133.0 million BOE at December 31, 2017. Proved plus probable reserves increased by 28% from 235.6 million BOE at December 31, 2017 to 302.7 million BOE at December 31, 2018.
The following table outlines a summary of the Company's reserves by category at December 31, 2018:
Summary of Reserves Oil & NGLs Gas Combined NPV10% BT NPV10% BT [Mbbls] [MMcf] [MBOE] ($M) ($/BOE) Proved Developed Producing 15,386 151,889 40,701 481,113 11.82 Proved Developed Non-producing 3,985 20,191 7,350 94,995 12.92 Proved Undeveloped 44,356 396,218 110,392 923,133 8.36 Total Proved 63,727 568,298 158,443 1,499,241 9.46 Probable Additional 65,120 474,689 144,235 1,629,395 11.30 Total Proved plus Probable 128,847 1,042,987 302,678 3,128,636 10.34
The following table shows the change in reserves year-over-year by reserve category:
Change in Reserves [MBOE] December 31, 2018 December 31, 2017 Percent Change Proved Developed Producing 40,701 37,858 + 8% Proved Developed Non-producing 7,350 2,833 + 159% Proved Undeveloped 110,392 92,282 + 20% Total Proved 158,443 132,973 + 19% Probable Additional 144,235 102,628 + 41% Total Proved plus Probable 302,678 235,601 + 28%
Future development capital ("FDC") expenditures of $872 million are included in the evaluation for total proved reserves and are expected to be spent as follows: $82 million in 2019, $200 million in 2020, $206 million in 2021, $125 million in 2022, $110 million in 2023 and $149 million thereafter.
FDC expenditures of $1,474 million are included in the evaluation of proved plus probable reserves and are expected to be spent as follows: $145 million in 2019, $310 million in 2020, $306 million in 2021, $246 million in 2022, $205 million in 2023 and $262 million thereafter.
The following table outlines FDC expenditures and future wells to be drilled by province, included in the December 31, 2018 and December 31, 2017 proved plus probable reserve evaluations:
Future Development Capital Expenditures - Proved plus Probable Reserves December 31, 2018 December 31, 2017 FDC ($M) Net Wells FDC ($M) Net Wells Alberta Montney HZ wells 331,835 59.3 175,728 37.3 British Columbia Montney HZ wells 743,803 140.0 638,203 102.5 Total Montney HZ Wells 1,075,638 199.3 813,931 139.8 Other formations - HZ wells 355,088 76.6 342,441 74.5 Other expenditures 43,372 â?' 7,220 â?' Total FDC Expenditures 1,474,098 275.9 1,163,592 214.3
The WTI oil price during 2018 averaged USD 65.04 per barrel, 18% higher than Sproule's 2018 forecast provided in the December 31, 2017 evaluation. Sproule is forecasting an average WTI oil price of USD 63.00 per barrel in 2019, a 3% decline from 2018. The NYMEX gas price during 2018 averaged USD 3.11 per MMBtu, 4% lower than Sproule's 2018 forecast provided in the December 31, 2017 evaluation. Sproule is forecasting an average NYMEX gas price of USD 3.00 per MMBtu in 2019, a 4% decline from 2018.
The following table outlines forecasted future prices that Sproule has used in their evaluation of the Company's reserves:
Commodity Prices December 31, 2018 Evaluation December 31, 2017 Evaluation WTI Cushing NYMEX USD/CAD WTI Cushing NYMEX USD/CAD Crude Oil Henry Hub Exchange Crude Oil Henry Hub Exchange [USD/bbl] [USD/MMBtu] [USD] [USD/bbl] [USD/MMBtu] [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) 50.95 3.02 0.771 50.95 3.02 0.771 2018 (historical/future) 65.04 + 18% 3.11 â?' 4% 0.772 â?' 2% 55.00 3.25 0.790 2019 (future) 63.00 â?' 3% 3.00 â?' 14% 0.770 â?' 6% 65.00 3.50 0.820 2020 (future) 67.00 â?' 4% 3.25 â?' 19% 0.800 â?' 6% 70.00 4.00 0.850 2021 (future) 70.00 â?' 4% 3.50 â?' 14% 0.800 â?' 6% 73.00 4.08 0.850 2022 (future) 71.40 â?' 4% 3.57 â?' 14% 0.800 â?' 6% 74.46 4.16 0.850 Note: Percent change in the above table shows the change in price used in the December 31, 2018 evaluation compared to the price used in the December 31, 2017 evaluation for the respective calendar years from 2018 to 2022.
During 2018, the Company's capital expenditures, net of dispositions, resulted in proved plus probable reserve additions of 76.9 million BOE, resulting in 2P finding, development and acquisition ("FD&A") costs of $7.75 per BOE, including FDC expenditures. Proved reserve additions in 2018 were 35.3 million BOE, resulting in 1P FD&A costs of $10.80 per BOE, including FDC expenditures.
Estimated capital expenditures, after minor dispositions, in 2018 were $285 million (unaudited). The Company considers the calculated FD&A costs in 2018 to be a very good result considering it incurred expenditures drilling several exploration wells in its new Montney core areas at Oak in British Columbia and at Wembley/Pipestone in Alberta, in addition to incurring significant infrastructure expenditures constructing the Inga 2-10 Facility during 2018. Despite significant facility expenditures in 2018, Kelt was able to show a 2P recycle ratio of 2.7 times.
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 purchase and construction of facilities and infrastructure in 2017 and 2018, 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 transition to development/pad drilling.
The following table provides detailed calculations relating to FD&A costs for 2018 and 2017:
Year ended Year ended December 31, 2018 December 31, 2017 Proved Reserves Capital expenditures [$000's] (2018 unaudited) 285,498 127,977 Change in FDC costs required to develop reserves [$000's] 95,548 187,459 Total capital costs [$000's] 381,046 315,436 Reserve additions, net [MBOE] 35,298 32,837 FD&A cost, including FDC [$/BOE] 10.80 9.61 Operating netback [$/BOE] (2018 unaudited) 20.56 15.92 Recycle ratio - proved 1.9 x 1.7 x Proved plus Probable Reserves Capital expenditures [$000's] (2018 unaudited) 285,498 127,977 Change in FDC costs required to develop reserves [$000's] 310,506 215,976 Total capital costs [$000's] 596,004 343,953 Reserve additions, net [MBOE] 76,905 49,592 FD&A cost, including FDC [$/BOE] 7.75 6.94 Operating netback [$/BOE] (2018 unaudited) 20.56 15.92 Recycle ratio - proved plus probable 2.7 x 2.3 x
Kelt's 2018 capital investment program resulted in net reserve additions that replaced 2017 production by a factor of 7.8 times on a proved plus probable basis.
A reconciliation of Kelt's proved plus probable reserves is provided in the table below:
Proved plus Probable Reserves Oil & NGLs Gas Combined [Mbbls] [MMcf] [MBOE] Balance, December 31, 2017 101,788 802,875 235,600 Extensions and infill drilling 41,733 217,403 77,967 Technical revisions (excluding reclassifications) and economic factors 1,020 45,084 8,534 Technical revisions - reclassifications  (10,605) 13,171 (8,410) Acquisitions 56 212 91 Dispositions (915) (2,169) (1,276) Additions, after dispositions ("Net additions") 31,289 273,701 76,906 Less: 2018 Production  (4,230) (33,589) (9,828) Balance, December 31, 2018  128,847 1,042,987 302,678 Notes:  Under Kelt's new long-term processing arrangements in British Columbia, the Company expects to reject C2 recoveries. As a result, the higher gas recoveries are expected to provide better economics based on current commodity prices.  Sulphur production of 17,371 Lt (174 MMcfe or 29 MBOE) has been excluded in the above table.  Sulphur reserves of 26,800 Lt (268 MMcfe or 45 MBOE) have been excluded in the above table.
In the December 31, 2018 Sproule evaluation, 10.6 million barrels of ethane were reclassified to an equivalent 13.2 Bcf of gas to reflect the future long-term gas processing arrangement at Inga/Fireweed whereby recoveries of ethane will be rejected and instead Kelt will sell its gas at a higher heat content. Previously, ethane recoveries were sold at an equivalent Station 2 gas price. Under the new arrangement, Kelt expects to sell the higher heat content gas under its existing gas marketing contracts at Chicago and Sumas, which is expected to result in higher netbacks when compared to the prior arrangement.
NET ASSET VALUE
Kelt's net asset value at December 31, 2018 was $15.51 per share, up 40% from the previous year. Details of the calculation are shown in the table below:
Net Asset Value per Share [ $M unless otherwise stated ] December 31, December 31, Percent 2018 2017 Change P&NG reserves, NPV10% BT 3,128,636 2,111,574 + 48% Decommissioning obligations, NPV10% BT [unaudited]  (9,044) (12,815) â?' 29% Undeveloped land 279,739 239,118 + 17% Bank debt, net of working capital [unaudited] (196,416) (136,729) + 44% Proceeds from exercise of stock options  6,404 60,361 â?' 89% Net asset value 3,209,319 2,261,509 + 42% Diluted common shares outstanding (000's)   206,978 204,410 + 1% Net asset value per share ($/share) 15.51 11.06 + 40% Notes:  The net present value of decommissioning obligations included above is incremental to the amount included in the present value of P&NG reserves as evaluated by Sproule.  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 $4.64 and $7.19 per common share respectively, as at December 31, 2018 and 2017. All outstanding RSUs are included in diluted common shares outstanding.  The 5% convertible debentures that mature on May 31, 2021 are convertible to common shares at $5.50 per share. At the December 31, 2018 closing price of $4.64 per share, 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. At the December 31, 2017 closing price of $7.19, the convertible debentures are "in-the-money" and 16.3 million shares issuable upon conversion 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, funds from operations and profit. Please refer to the cautionary statement on forward-looking statements and information set out below.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS AND INFORMATION
This press release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "forecast", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information or statements. In particular, this press release contains forward-looking statements pertaining to the following: the forecasted future commodity prices used by Sproule in their evaluation, markets for future gas production, future development capital expenditures, expectations, exploration and development activities and future drilling plans, including future drilling locations, achieving further efficiencies in production additions and FDC expenditures over the upcoming years as Kelt continues to transition to development/pad drilling, better economics resulting from rejecting ethane recoveries and selling higher heat content gas under existing gas marketing contracts at Chicago and Sumas, expected to result in higher netbacks. Statements relating to "reserves" or "resources" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
Although Kelt believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Kelt cannot give any assurance that they will prove to be correct. Kelt has made assumptions regarding, but not limited to: existing production sales contracts remaining in place, future commodity prices, timing and amount of capital expenditures, future production expenses, future cash flow, future debt levels and future production volumes. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ 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 (e.g., 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 reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses; failure to obtain necessary regulatory approvals for planned operations; health, safety and environmental risks; uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures; volatility of commodity prices, currency exchange rate fluctuations; imprecision of reserve estimates; and competition from other explorers) as well as general economic conditions, stock market volatility; and the ability to access sufficient capital. We caution that the foregoing list of risks and uncertainties is not exhaustive.
In addition, the reader is cautioned that historical results are not necessarily indicative of future performance. The forward-looking statements contained herein are made as of the date hereof and the Company does not intend, and does not assume any obligation, to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise unless expressly required by applicable securities laws.
Certain information set out herein is "financial outlook" within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure regarding Kelt's reasonable expectations as to the anticipated results of its proposed business activities. Readers are cautioned that this financial outlook may not be appropriate for other purposes.
NON-GAAP FINANCIAL MEASURES AND OTHER KEY PERFORMANCE INDICATORS
This press release contains certain financial measures, as described below, which do not have standardized meanings prescribed by GAAP. In addition, this press release contains other key performance indicators ("KPI"), financial and non-financial, that do not have standardized meanings under the applicable securities legislation. As these non-GAAP financial measures and KPI are commonly used in the oil and gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used.
"Operating income" is calculated by deducting royalties, production expenses and transportation expenses from petroleum and natural gas ("P&NG") revenue, net of the cost of purchases and after realized gains or losses on associated financial instruments. The Company refers to operating income expressed per unit of production as an "operating netback".
"Adjusted funds from operations" is calculated as cash provided by operating activities before changes in non-cash operating working capital, and adding back (if applicable): transaction costs associated with acquisitions and dispositions, provisions for potential credit losses, and settlement of decommissioning obligations. Adjusted funds from operations per common share is calculated on a consistent basis with profit (loss) per common share, using basic and diluted weighted average common shares as determined in accordance with GAAP. Adjusted funds from operations and operating income or netbacks are used by Kelt as key measures of performance and are not intended to represent operating profits nor should they be viewed as an alternative to cash provided by operating activities, profit or other measures of financial performance calculated in accordance with GAAP.
"Finding, development and acquisition" ("FD&A") cost is the sum of capital expenditures incurred in the period and the change in future development capital ("FDC") required to develop reserves. FD&A cost per BOE is determined by dividing current period net reserve additions into the corresponding period's FD&A cost. Readers are cautioned that the aggregate of capital expenditures incurred in the year, comprised of exploration and development costs and acquisition costs, and the change in estimated FDC generally will not reflect total FD&A costs related to reserves additions in the year.
"Recycle ratio" is a measure for evaluating the effectiveness of a company's re-investment program. The ratio measures the efficiency of capital investment by comparing the operating netback per BOE to FD&A cost per BOE.
"Net asset value per share" is calculated by adding the net present value of P&NG reserves, undeveloped land value and proceeds from exercise of stock options, less the net present value of decommissioning obligations and bank debt, net of working capital, and dividing by the diluted number of common shares outstanding. 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 common shares as at the calculation date. All outstanding RSUs are included in diluted common shares outstanding. The diluted number of common shares outstanding includes common shares to be issuable upon conversion of the convertible debentures. Common shares to be issued upon conversion are calculated based on the conversion price if the convertible debentures are "in-the-money" based on the closing price of KEL common shares as at the calculation date or they are calculated based on 95% of the closing price of KEL common shares as at the calculation date, if the convertible debentures are "out-of-the-money".
MEASUREMENTS AND ABBREVIATIONS
All dollar amounts are referenced in thousands of Canadian dollars, except when noted otherwise. This press release contains various references to the abbreviation BOE which means barrels of oil equivalent. Where amounts are expressed on a BOE basis, natural gas volumes have been converted to oil equivalence at six thousand cubic feet per barrel and sulphur volumes have been converted to oil equivalence at 0.6 long tons per barrel. The term BOE may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead and is significantly different than the value ratio based on the current price of crude oil and natural gas. This conversion factor is an industry accepted norm and is not based on either energy content or current prices. Such abbreviation may be misleading, particularly if used in isolation. References to "oil" in this press release include crude oil and field condensate. References to "natural gas liquids" or "NGLs" include pentane, butane, propane, and ethane. References to "gas" in this discussion include natural gas and sulphur.
TSX the Toronto Stock Exchange KEL trading symbol for Kelt Exploration Ltd. on the Toronto Stock Exchange bbls barrels bbls/d barrels per day Mbbls thousand barrels Mcf thousand cubic feet Mcf/d thousand cubic feet per day MMcf million cubic feet MMcfe million cubic feet equivalent MMcf/d million cubic feet per day MMBtu million British thermal units GJ gigajoule Lt long ton BOE barrel of oil equivalent MBOE thousand barrels of oil equivalent BOE/d barrel of oil equivalent per day NGLs natural gas liquids C2 ethane C3 propane C4 butane C5+ pentane plus all other heavier natural gas liquids AECO Alberta Energy Company "C" Meter Station of the NOVA Pipeline System NYMEX New York Mercantile Exchange WTI West Texas Intermediate USD United States dollars CAD Canadian dollars $ Canadian dollars $M thousand dollars GAAP Generally Accepted Accounting Principles P&NG petroleum and natural gas FD&A finding, development and acquisition FDC future development capital NPV net present value NPV 10% net present value discounted at ten percent BT before tax
For further information, please contact:
Kelt Exploration Ltd., Suite 300, 311 - 6 Avenue SW, Calgary, Alberta, Canada T2P 3H2
David J. Wilson, President and Chief Executive Officer (403) 201-5340, or
Sadiq H. Lalani, Vice President and Chief Financial Officer (403) 215-5310.
Or visit our website at www.keltexploration.com.