Kelt Reports Significant Increases in Oil & Gas Reserves and Net Asset Value per Share as at December 31, 2018

February 21, 2019 Globe Newswire

CALGARY, Alberta, Feb. 21, 2019 (GLOBE NEWSWIRE) — 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, 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].

HIGHLIGHTS

[$M unless otherwise stated]	December 31, 2018		December 31, 2017		Change
[$M unless otherwise stated]	% Weight	Amount	% Weight	Amount	Change
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	− 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 [1]		3,209,319		2,261,509	+ 42%
Net Asset Value per share – diluted [$]		15.51		11.06	+ 40%
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.

PRODUCTION

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.

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, 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 [Mbbls]	Gas [MMcf]	Combined [MBOE]	NPV10% BT ($M)	NPV10% BT ($/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	−	7,220	−
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 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)	50.95		3.02		0.771		50.95	3.02	0.771
2018 (historical/future)	65.04	+ 18%	3.11	− 4%	0.772	− 2%	55.00	3.25	0.790
2019 (future)	63.00	− 3%	3.00	− 14%	0.770	− 6%	65.00	3.50	0.820
2020 (future)	67.00	− 4%	3.25	− 19%	0.800	− 6%	70.00	4.00	0.850
2021 (future)	70.00	− 4%	3.50	− 14%	0.800	− 6%	73.00	4.08	0.850
2022 (future)	71.40	− 4%	3.57	− 14%	0.800	− 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 December 31, 2018	Year ended 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

RESERVES RECONCILIATION

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 [Mbbls]	Gas [MMcf]	Combined [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 [1]	(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 [2]	(4,230)	(33,589)	(9,828)
Balance, December 31, 2018 [3]	128,847	1,042,987	302,678
Notes: [1] 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. [2] Sulphur production of 17,371 Lt (174 MMcfe or 29 MBOE) has been excluded in the above table. [3] 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
[ $M unless otherwise stated ]	December 31, 2018	December 31, 2017	Percent Change
P&NG reserves, NPV10% BT	3,128,636	2,111,574	+ 48%
Decommissioning obligations, NPV10% BT [unaudited] [1]	(9,044)	(12,815)	− 29%
Undeveloped land	279,739	239,118	+ 17%
Bank debt, net of working capital [unaudited]	(196,416)	(136,729)	+ 44%
Proceeds from exercise of stock options [2]	6,404	60,361	− 89%
Net asset value	3,209,319	2,261,509	+ 42%
Diluted common shares outstanding (000’s) [2] [3]	206,978	204,410	+ 1%
Net asset value per share ($/share)	15.51	11.06	+ 40%
Notes: [1] 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. [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 $4.64 and $7.19 per common share respectively, as at December 31, 2018 and 2017. All outstanding RSUs are included in diluted common shares outstanding. [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, 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.