Kelt Reports Significant Increases in Oil and Gas Reserves and Provides an Operations Update

Calgary, Alberta--(Newsfile Corp. - February 16, 2023) - Kelt Exploration Ltd. (TSX: KEL) ("Kelt" or the "Company") reports on its oil & gas reserves and production for the year ended December 31, 2022. 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, 2022. The Company has a Reserves Committee which oversees the selection, qualifications and reporting procedures of the independent qualified reserves evaluator. Reserves effective December 31, 2022 and effective December 31, 2021 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 is expected to be filed on SEDAR on March 3, 2023.

UNAUDITED INFORMATION

All financial and operating information in this press release for the fourth quarter and year ended December 31, 2022, such as FDA&D costs, recycle ratio, net debt, capital expenditures, production and operating netback is based on unaudited estimated results and have not been reviewed by the Corporation's auditors. These estimates are subject to change upon completion of audited financial statements for the year ended December 31, 2022, and changes could be material. Kelt anticipates filing its audited financial statements and related management's discussion and analysis for the year ended December 31, 2022 on SEDAR on March 3, 2023.

RESERVES

Kelt continues to remain active operationally in its three main divisions, resulting in increases in all categories of reserves compared to the previous year.

Superior well performance led to significant positive technical revisions in the December 31, 2022 report. Refer to the table under the paragraph entitled "Reserves Reconciliation" for detailed information relating to reserve changes, by category, during the year.

Summary of Reserves
	December 31, 2022		December 31, 2021		Change
	% Weight	Amount	% Weight	Amount
Proved Developed Producing Reserves
Oil & NGLs [Mbbls]	32%	19,835	31%	13,445	48%
Gas [MMcf]	68%	247,362	69%	182,455	36%
Combined [MBOE]	100%	61,062	100%	43,854	39%
Proved Reserves
Oil & NGLs [Mbbls]	38%	72,254	39%	52,081	39%
Gas [MMcf]	62%	718,911	61%	492,058	46%
Combined [MBOE]	100%	192,073	100%	134,091	43%
Proved plus Probable Reserves
Oil & NGLs [Mbbls]	38%	129,479	41%	104,824	24%
Gas [MMcf]	62%	1,267,931	59%	895,948	42%
Combined [MBOE]	100%	340,801	100%	254,149	34%

 

Proved Developed Producing ("PDP") reserves at December 31, 2022 were 61.1 million BOE, an increase of 39% from 43.9 million BOE at December 31, 2021. Proved reserves at December 31, 2022 were 192.1 million BOE, up 43% from 134.1 million BOE at December 31, 2021. Proved plus Probable ("P+P") reserves increased by 86.7 million BOE or 34% from 254.1 million BOE at December 31, 2021 to 340.8 million BOE at December 31, 2022.

Proved plus Probable Oil and NGL reserves increased by 24% year-over-year and the mix increased favourably to a higher netback stream. Light oil, condensate and pentane plus reserves made up 62% of total Oil & NGL reserves, or 80.1 million barrels, at December 31, 2022 compared to 57% or 59.2 million barrels at December 31, 2021.

Oil & NGLs Mix
	December 31, 2022		December 31, 2021		Change
	% Weight	Amount	% Weight	Amount
Proved plus Probable Reserves [Mbbls]
Light Oil, Condensate and Pentane Plus    (C5+)	62%	80,102	57%	59,178	35%
Butane (C4)	10%	12,969	11%	11,542	12%
Propane (C3)	14%	18,005	15%	15,797	14%
Ethane (C2)	14%	18,403	17%	18,307	1%
Total Oil & NGLs	100%	129,479	100%	104,824	24%
Note: Refer to advisories regarding Measurements and Abbreviations.

 

Complementing a significant increase in the amount of reserves, the value of the reserves also increased with higher forecasted oil and gas prices for future years in the December 31, 2022 evaluation (see "Commodity Prices" table included below).

The WTI crude oil price during 2022 averaged USD $94.80 per barrel, 30% higher than Sproule's 2022 forecast of USD $73.00 per barrel provided in the December 31, 2021 evaluation. Sproule is forecasting an average WTI crude oil price of USD $86.00 per barrel for 2023, a 23% increase from its previous forecast of USD $70.00 per barrel.

The NYMEX Henry Hub natural gas price during 2022 averaged USD $6.56 per MMBtu, 64% higher than Sproule's 2022 forecast of USD $4.00 per MMBtu provided in the December 31, 2021 evaluation. Sproule is forecasting an average NYMEX Henry Hub natural gas price of USD $5.00 per MMBtu for 2023, an increase of 43% from its previous forecast of USD $3.50 per MMBtu.

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

Commodity Prices
	December 31, 2022 Evaluation						December 31, 2021 Evaluation
	WTI Cushing Crude Oil [USD/bbl]		NYMEX Henry Hub Natural Gas [USD/MMBtu]		CAD/USD Exchange [CAD]		WTI Cushing Crude Oil [USD/bbl]		NYMEX Henry Hub Natural Gas [USD/MMBtu]	CAD/ USD Exchange [CAD]
Calendar Year	Price	Change	Price	Change	Rate	Change	Price		Price	Rate
2018 (historical)	64.94		3.04		1.297		64.94		3.04	1.297
2019 (historical)	56.98		2.62		1.326		56.98		2.62	1.326
2020 (historical)	39.24		2.08		1.340		39.24		2.08	1.340
2021 (historical)	68.03		3.74		1.253		68.03		3.74	1.253
2022 (historical/future)	94.80	30%	6.56	64%	1.302	4%	73.00		4.00	1.250
2023 (future)	86.00	23%	5.00	43%	1.333	7%	70.00		3.50	1.250
2024 (future)	84.00	24%	4.50	38%	1.250	0%	68.00		3.25	1.250
2025 (future)	80.00	15%	4.25	28%	1.250	0%	69.36		3.32	1.250
2026 (future)	81.60	15%	4.34	28%	1.250	0%	70.75		3.38	1.250
2027 (future)	83.23	15%	4.42	28%	1.250	0%	72.16		3.45	1.250
Note: Percent change in the above table shows the change in price used in the December 31, 2022 evaluation compared to the price used in the December 31, 2021 evaluation for the respective calendar years from 2022 to 2027.

 

The Company's net present value of P+P reserves at December 31, 2022, discounted at 10% before tax, was $3,430 million, an increase of 60% from $2,144 million at December 31, 2021. On a barrel of oil equivalent basis, the net present value of P+P reserves at December 31, 2022 was $10.06 per BOE, up 19% from $8.43 per BOE at December 31, 2021.

The following table outlines a summary of the net present value of the Company's reserves by category as at December 31, 2022 and at December 31, 2021:

Value of Reserves
	December 31, 2022		December 31, 2021		Percent Change in NPV
	NPV10% BT [$M]	NPV $/BOE	NPV10% BT [$M]	NPV $/BOE
Proved Developed Producing	841,642	13.78	519,977	11.86	62%
Proved	1,927,081	10.03	1,125,576	8.39	71%
Proved plus Probable	3,430,114	10.06	2,143,646	8.43	60%

 

At December 31, 2022, Kelt had 192.0 million common shares issued and outstanding. The net present value of reserves per share at December 31, 2022 were as follows:

• $4.38 per share for Proved Developed Producing reserves;

• $10.04 per share for Proved reserves; and

• $17.87 per share for Proved plus Probable reserves.

Results from Kelt's drilling program during the year replaced 2022 production multiple times in each of its reserve categories. The Company replaced total 2022 production 2.7 times on a PDP basis, 6.8 times on a Proved basis and 9.7 times on a P+P basis.

The following table shows the 2022 production replacement by reserve category:

Reserves Replacement
[MBOE]	Proved Developed Producing	Proved	Proved plus Probable
Reserve Additions, net	27,138	67,912	96,582
2022 Production [1]	9,930	9,930	9,930
Reserves Replacement	273%	684%	973%
Note: [1] Sulphur production of 6,686 Lt (67 MMcfe or 11 MBOE) has been excluded from 2022 production in the above table.

 

2022 CAPITAL EXPENDITURES

Capital expenditures for 2022 were $317.5 million, net after property dispositions of $2.6 million. The Company drilled 28.4 net wells (25.4 wells in Alberta and 3.0 wells in British Columbia) and completed 32.1 net wells (29.1 wells in Alberta and 3.0 wells in British Columbia). Kelt added additional gas compression and enlarged its oil facilities at Pouce Coupe and Spirit River and built various oil and gas gathering pipelines at Wembley/Pipestone. Capital expenditures for 2022 include equipment and facilities purchased into inventory. In anticipation of potential supply chain bottlenecks, Kelt actively procured casing, tubing, valves, instrumentation and other equipment into inventory in order to facilitate a timely execution of the Company's 2023 drilling program. Kelt had an equipment and facility inventory balance of $27.8 million at December 31, 2022.

FUTURE DEVELOPMENT CAPITAL EXPENDITURES

Future development capital ("FDC") expenditures of $1,210.1 million are included in the evaluation for Proved reserves and are expected to be incurred over five years as follows: $227.6 million in 2023, $269.9 million in 2024, $264.2 million in 2025, $201.8 million in 2026 and $246.6 million in 2027. FDC expenditures of $2,044.2 million are included in the evaluation of P+P reserves and are expected to be incurred over five years as follows: $323.6 million in 2023, $393.6 million in 2024, $418.0 million in 2025, $442.6 million in 2026 and $466.4 million in 2027.

The following table outlines FDC expenditures and future wells to be drilled by province, included in the December 31, 2022 reserve evaluation with comparatives from the December 31, 2021 report:

Future Development Capital Expenditures
	December 31, 2022 Proved Reserves			December 31, 2022 P+P Reserves
	FDC [$MM]	Net Wells	FDC/well [$MM]	FDC [$MM]	Net Wells	FDC/well [$MM]
Alberta Montney wells	887.0	111.8	7.9	1,423.5	181.8	7.8
British Columbia Montney wells	177.3	23.0	7.7	281.7	36.0	7.8
Alberta Charlie Lake wells	96.4	16.9	5.7	182.5	31.2	5.8
Other formations	24.8	7.1	3.5	108.4	21.0	5.2
Other expenditures (includes completing DUCs)	24.6	─		48.1	─
Total FDC Expenditures	1,210.1	158.8		2,044.2	270.0
	December 31, 2021 Proved Reserves			December 31, 2021 P+P Reserves
	FDC [$MM]	Net Wells	FDC/well [$MM]	FDC [$MM]	Net Wells	FDC/well [$MM]
Alberta Montney wells	585.6	86.8	6.7	1,091.1	158.3	6.9
British Columbia Montney wells	52.6	9.0	5.8	129.5	22.0	5.9
Alberta Charlie Lake wells	35.7	8.5	4.2	82.8	19.6	4.2
Other formations	41.7	14.5	2.9	74.6	22.2	3.4
Other expenditures (includes completing DUCs)	38.7	─		42.9	─
Total FDC Expenditures	754.3	118.8		1,420.9	222.1

 

FINDING, DEVELOPMENT, ACQUISITION & DISPOSITION COSTS

Capital expenditures, after acquisitions and dispositions, in 2022 were $317.5 million compared to $213.5 million in 2021. The change in FDC costs required to develop P+P reserves was $623.3 million ($494.3 million in 2021) and the change in FDC costs required to develop Proved reserves was $455.8 million ($217.6 million in 2021).

During 2022, the Company's total capital costs resulted in net P+P reserve additions of 96.6 million BOE; net Proved reserve additions of 67.9 million BOE; and net PDP reserve additions of 27.1 million BOE. As a result, the P+P finding, development, acquisition and disposition ("FDA&D") cost per BOE was $9.74; the Proved FDA&D cost per BOE was $11.39; and the PDP FDA&D cost per BOE was $11.65.

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 (or divestment). It accomplishes this by comparing the operating netback per BOE to the same period's reserve FDA&D cost per BOE. With significant construction of facilities and infrastructure along with historic cumulative land acquisitions, Kelt is positioned to achieve further efficiencies in production additions and finding and development costs over the upcoming years, as the Company continues to transition from exploration and resource delineation to development and multi-well pad drilling.

In 2022, the Company achieved historically high recycle ratios for all three of its major reserve categories. The P+P recycle ratio was 3.5 times (compared to 2.6 times in 2021); the Proved recycle ratio was 3.0 times (compared to 2.4 times in 2021); and the PDP recycle ratio was 2.9 times (compared to 2.3 times in 2021). The following tables provides detailed calculations relating to FDA&D costs and recycle ratios for 2022 and 2021:

FDA&D Costs and Recycle Ratios
	Year ended December 31, 2022	Year ended December 31, 2021
Proved Developed Producing Reserves
Capital expenditures, net of dispositions [$M]	317,540	213,511
Change in FDC costs required to develop reserves [$M]	(1,427)	1,402
Total capital costs [$M]	316,113	214,913
Reserve additions, net of dispositions [MBOE]	27,138	21,896
FDA&D cost, including FDC [$/BOE]	11.65	9.82
Operating netback [$/BOE]	33.98	22.29
PDP recycle ratio	2.9 x	2.3 x

 

FDA&D Costs and Recycle Ratios
	Year ended December 31, 2022	Year ended December 31, 2021
Proved Reserves
Capital expenditures, net of dispositions [$M]	317,540	213,511
Change in FDC costs required to develop reserves [$M]	455,788	217,631
Total capital costs [$M]	773,328	431,142
Reserve additions, net of dispositions [MBOE]	67,912	45,784
FDA&D cost, including FDC [$/BOE]	11.39	9.42
Operating netback [$/BOE]	33.98	22.29
Proved recycle ratio	3.0 x	2.4 x
Proved plus Probable Reserves
Capital expenditures, net of dispositions [$M]	317,540	213,511
Change in FDC costs required to develop reserves [$M]	623,296	494,307
Total capital costs [$M]	940,836	707,818
Reserve additions, net of dispositions [MBOE]	96,582	83,015
FDA&D cost, including FDC [$/BOE]	9.74	8.53
Operating netback [$/BOE]	33.98	22.29
P+P recycle ratio	3.5 x	2.6 x

 

RESERVES RECONCILIATION

Kelt's 2022 capital investment program, including dispositions, resulted in proved plus probable reserve additions of 96.6 million BOE, that replaced 2022 production by a factor of 9.7 times.

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

Proved plus Probable Reserves Reconciliation
	Oil & NGLs [Mbbls]	Gas [MMcf]	Combined [MBOE]
Balance, December 31, 2021	104,824	895,948	254,149
Discoveries, extensions and infill drilling	27,642	299,841	77,616
Technical revisions	(2,051)	74,868	10,426
Economic factors	3,254	37,918	9,573
Acquisitions	129	502	213
Dispositions	(782)	(2,786)	(1,246)
Additions, net of dispositions	28,192	410,343	96,582
Less: 2022 Production [1]	(3,537)	(38,360)	(9,930)
Balance, December 31, 2022	129,479	1,267,931	340,801
Note: [1] Sulphur production of 6,686 Lt (67 MMcfe or 11 MBOE) has been excluded from 2022 production 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. Kelt added 10.4 million BOE of P+P reserves resulting from positive technical revisions.

NET ASSET VALUE

Kelt's calculated net asset value per share at December 31, 2022 was $17.87, 257% above the $5.01 closing trading price of the Company's common shares on the Toronto Stock Exchange on December 30, 2022.

Details of the net asset value calculation are shown in the table below:

Net Asset Value per Share
	$ M	$/share
Proved reserves, NPV10% BT [1]	1,927,081	9.65
Probable reserves, NPV10% BT [1]	1,503,033	7.53
Undeveloped land [2]	129,396	0.65
Net debt [3]	(9,789)	(0.05)
Proceeds from exercise of stock options [4]	18,353	0.09
Net asset value	3,568,074	17.87
Diluted common shares outstanding (000's) [4]	199,706
Notes: [1] Includes the net present value of the liability relating to the Company's estimated future decommissioning obligations. [2] Lands that do not have existing production, however, do have reserves assigned either as proved undeveloped well locations or probable well locations, have been excluded from the undeveloped land value. [3] Based on the Company's estimated net debt at December 31, 2022. [4] 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 $5.01 on December 31, 2022. All outstanding RSUs are included in diluted common shares outstanding.

 

PRODUCTION

Kelt's average production for 2022 was 27,236 BOE per day, up 30% from average production of 20,987 BOE per day in 2021. Production for 2022 was weighted 36% oil and NGLs and 64% gas. Average production for the fourth quarter of 2022 was 28,036 BOE per day, weighted 35% oil and NGLs and 65% gas.

Production for 2022 compared to 2021 is summarized in the following table:

Production
	December 31, 2022		December 31, 2021		Change
	% Weight	Amount	% Weight	Amount
Annual Average Production
Oil & NGLs [bbls/d]	36%	9,689	37%	7,846	23%
Gas [Mcf/d]	64%	105,280	63%	78,846	34%
Combined [BOE/d]	100%	27,236	100%	20,987	30%

 

OPERATIONS UPDATE

During the first half of 2022, Kelt determined that additional gas processing capacity expected to be made available to the Company in the Wembley/Pipestone area at a third-party facility was postponed until later in 2023 or early in 2024. As a result, during the second half of 2022, Kelt's drilling program was focused on its Charlie Lake play at Spirit River and Wembley where production rates are weighted towards high netback light oil. The Company expanded its gas compression and oil handling facilities at Spirit River to accommodate production growth.

The start-up of the expanded facility was delayed to January 2023 due to the extreme cold weather experienced in December 2022. Initial production rates from the Charlie Lake wells that have recently been brought on-stream have exceeded type curve expectations.

The gross 100% working interest IP30 rates (estimated sales volumes) are summarized as follows:

• Spirit River 103/4-1 (sfc 4-5) : 1,318 BOE/d (71% oil and NGLs) : 100% Kelt

• Spirit River 102/12-1 (sfc 4-5) : 1,386 BOE/d (76% oil and NGLs) : 100% Kelt (IP13 - on-stream Feb/1/2023)

• Spirit River 100/2-22 (sfc 8-27) : 1,332 BOE/d (86% oil and NGLs) : 96% Kelt

• Spirit River 100/9-25 (sfc 8-27) : 1,052 BOE/d (47% oil and NGLs) : 100% Kelt

• Wembley 100/1-24 (sfc 16-26) : 1,499 BOE/d (72% oil and NGLs) : 60% Kelt

At Pouce Coupe North, the Company has assembled 32 net sections of Charlie Lake rights and has drilled its first horizontal well in the area. In addition, Kelt re-completed nine vertical wells in the Charlie Lake formation at Pouce Coupe North. These wells were brought on production in late January and in February into an expanded gas compression and oil battery facility. Additional activity in the area is planned for 2023.

Based on field estimates, total Company production for the month of January is estimated to be approximately 31,000 BOE per day weighted 38% oil and NGLs and 62% gas. Three additional Charlie Lake wells are expected to be brought on-stream in February 2023, two at Spirit River (sfc 4-8) and one at Wembley (sfc 16-8).

Kelt is pleased with the success of its drilling program in 2022 and the corresponding results that are reflected in significant growth in oil and gas reserves during the year. The Company remains optimistic about the energy industry and its ability to provide shareholders with high rates of return on capital deployed. Kelt expects to continue to reinvest cash flow into developing its high-quality Montney and Charlie Lake plays.

Management looks forward to providing shareholders with its 2022 year-end financial results on March 3, 2023.

For further information, please contact:
Kelt Exploration Ltd., Suite 300, 311 - 6^th 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.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS AND INFORMATION

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.

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 for the timing of new wells to be brought on-stream, exploration and development activities and future drilling plans, expectations for high rates of return on capital deployed, achieving further efficiencies in production additions, and Kelt's intention to transition to increased development and pad drilling. 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, royalty rates, tax regulations, 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.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves, and the future net revenue attributed to such reserves, including many factors beyond the control of Kelt. The reserves and associated future net revenue information set forth in this press release are estimates only. In general, estimates of economically recoverable oil, natural gas and NGLs reserves and the future net revenue therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserves recovery, the timing and amount of capital expenditures, marketability of oil, natural gas and NGLs, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For these reasons, estimates of the economically recoverable oil, natural gas and NGLs reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenue associated with reserves prepared by different engineers, or by the same engineer at different times, may vary.

Kelt's actual production, revenue, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Corporation's reserves estimated by the Corporation's independent qualified reserves evaluators represent the fair market value of those reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. Actual oil, natural gas and NGLs reserves may be greater than or less than the estimates provided herein, and variances could be material.

With respect to the disclosure of reserves contained herein relating to portions of Kelt's properties, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. In this press release, unless otherwise stated all references to "reserves" are to Kelt's gross company reserves before deduction of royalties and without including and royalty interests of Kelt.

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 AND OTHER FINANCIAL MEASURES

This press release contains certain non-GAAP financial measures and other specified financial measures, as described below, which do not have standardized meanings prescribed by GAAP and do not have standardized meanings under the applicable securities legislation. As these non-GAAP, and other specified financial measures 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.

NON-GAAP FINANICAL MEASURES

Operating netback

Operating netback is a non-GAAP measure calculated by deducting royalties, production expenses and transportation expenses from petroleum and natural gas sales, net of the cost of purchases and after realized gains or losses on associated financial instruments. The Company also presents operating netbacks on a per BOE basis which allows management to better analyze performance against prior periods, on a comparable basis, and is a key industry performance measure of operational efficiency.

Capital Expenditures

"Capital expenditures, net of A&D" is a measure the Company uses to monitor its investment in exploration and evaluation, and in investment in property plant and equipment. The most directly comparable GAAP measure is "Cash provided by investing activities".

"Future development capital" means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Future development capital excludes capitalized administration costs.

Net asset value

"Net asset value" is calculated by adding the present value of proved plus probable petroleum and natural gas reserves discounted at 10% before tax, undeveloped land value, proceeds from exercise of stock options, and net bank debt (surplus). "Net asset value per common share" is calculated by dividing the "Net Asset Value" 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 Kelt common shares as at the calculation date. The diluted number of common shares outstanding includes common shares issuable upon conversion of the convertible debentures that are "in-the-money" based on the closing price of Kelt common shares as at the calculation date. Management believes that the "Net Asset Value" provides a useful measure to analyze the comparative change in the Company's estimated value on a normalized basis.

See the "Net Asset Value" section of this press release which provides the calculation of the net asset value.

CAPITAL MANAGEMENT MEASURES

Net Debt

"Net debt" is equal to bank debt, accounts payable and accrued liabilities, net of cash and cash equivalents, accounts receivables and accrued sales and prepaid expenses and deposits. The Company believes that using a "Net debt" non-GAAP measure, which excludes non-cash derivative financial instruments, non-cash lease liabilities, and non-cash decommissioning obligations, provides investors with more useful information to understand the Company's cash liquidity risk.

NON-GAAP RATIOS

"Finding, development, acquisition and disposition" ("FDA&D") cost is the sum of capital expenditures incurred in the period, less proceeds from the disposition of assets during the period and the change in future development capital ("FDC") required to develop reserves. FDA&D cost per BOE is determined by dividing current period net reserve additions into the corresponding period's FDA&D cost. Readers are cautioned that the aggregate of capital expenditures incurred in the year, comprised of exploration and development costs and acquisition costs, and proceeds from the disposition of assets, and the change in estimated FDC generally will not reflect total FDA&D costs related to net reserve additions in the year.

"Reserves Replacement" is calculated by dividing the current year's reserve additions by the current year's production. Management believes this ratio provides useful information in comparing the rate of reserve growth to the Company's most recent annual production.

"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 FDA&D cost per BOE.

SUPPLEMENTARY FINANICAL MEASURES

Initial Production Rates

This press release includes production rates for certain wells over short periods of time (i.e. IP 30). In determining production for the purposes of calculating an IP30 rate, Kelt's IP30 rate excludes downtime. Short term production rates are preliminary, subject to a high degree of predictive uncertainty, and not determinative of the rates at which those or other wells will continue to produce and thereafter decline. Short term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. Production over a longer period will experience natural declines, which can be high and may not be consistent over a longer period. Actual results will differ from those realized during an initial production period and the differences may be material.

MEASUREMENTS

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 plus, butane, propane and ethane. References to "gas" in this discussion include natural gas and sulphur.

ABBREVIATIONS

TSX	the Toronto Stock Exchange
KEL	trading symbol for Kelt Exploration Ltd. on the TSX
GAAP	Generally Accepted Accounting Principles
SEDAR	the System for Electronic Document Analysis and Retrieval
PDP	proved developed producing
P+P	proved plus probable
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 HH	the Henry Hub natural gas pipeline delivery location for futures contracts on the New York Mercantile Exchange
WTI	West Texas Intermediate
USD	United States dollars
CAD	Canadian dollars
$	Canadian dollars
$M	thousand dollars
$MM	million dollars
P&NG	petroleum and natural gas
FDA&D	finding, development, acquisition and disposition
FDC	future development capital
NPV	net present value
NPV 10%	net present value discounted at ten percent
BT	before tax
IP30	initial production from a well for the first 30 days (720 operating hours)
IP13	initial production from a well for the first 13 days (312 operating hours)

 

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/155002