ROK Resources announces record production, 2023 year-end reserves, and provides first-half 2024 guidance – Canadian Energy News, Top Headlines, Commentaries, Features & Events

2023 Operational Highlights

Record Average Production of 4,650 boepd in December: Daily average production in December of 4,650 boepd (60% liquids), which exceeded the Company’s 2023 exit production target range of 4,300 – 4,500 boepd and represents a 35% increase in production compared to December 2022 daily average;
Organically Increased Production by Over 50% in 6-Months: Following two asset transactions, previously announced on January 24, 2023 and March 23, 2023, the Company grew from 2,950 boepd to 4,650 boepd in 6-months;
Core Area Drilling Inventory Growth: Added 10 proved drilling locations in core operating areas in Southeast Saskatchewan after successful Frobisher results across multiple fields;
Drilled the #1 Daily Average Oil Well in Saskatchewan in December: The Company’s 6-25 Glen Ewen Frobisher well averaged 392 bopd¹¹ in the month of December;
Operating Cost Reduction: With a focus on operational efficiencies in Q4 2023, the Company reduced total operating cost per boe by approximately 20% compared to Q3 2023, resulting in operating costs below $30/boe in Q4 2023;
Exceeded Q4 2024 Funds from Operations forecast: Estimated¹⁰ Funds from Operations of $10 million in Q4 2023, exceeding the Company’s forecast by 16% despite weaker commodity pricing;
Net Debt: The Company will exit 2023 with an estimated¹⁰ Net Debt of $14.5 million (or Adjusted Net Debt of $18.5 million). This represents a 59%, or $20.8 million, reduction in Net Debt year over year; and
Commitment to ESG: The Company increased its original asset retirement obligation budget and invested approximately $2.3 million to reduce environmental liabilities which represents 10% of its estimated inactive asset retirement obligation.

2023 Corporate Reserves

The Company is pleased to announce the results of its independent reserves evaluation. The evaluation for the Company as at December 31, 2023 was conducted by McDaniel & Associates (“McDaniel“) of Calgary and was conducted in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluators Handbook (“COGEH“) and National Instrument 51-101 – Standards for Disclosure of Oil and Gas Activities (“NI 51-101“).

Reserves Evaluation Highlights

Proved oil and gas reserves (“1P“) of 13,399 Mboe and Net Present Value of 1P reserves discounted at 10% (“NPV10“) of $129.8 million;
Proved plus probable oil and gas reserves (“2P“) of 21,054 Mboe and Net Present Value of 2P reserves discounted at 10% of $237.5 million;
Total 1P Basic NAV⁸ of $0.53/share and 2P Basic NAV⁸ of $1.02/share, a YoY increase of 12% and 17%, respectively, and excludes any value attributed to the Company’s current hedges, undeveloped land, and lithium prospect;
Total 1P Diluted NAV⁹ of $0.33/share and 2P Diluted NAV⁹ of $0.63/share, a YoY increase of 15% and 22%, respectively, and excludes any value attributed to the Company’s current hedges, undeveloped land, and lithium prospect;
Finding, Development and Acquisition (“FD&A“)⁷ costs, including changes in Future Development Capital (“FDC“)³, of:
- 1P: $13.69/boe
- 2P: $11.20/boe
Finding and Development (“F&D“)⁷ costs, including changes in Future Development Capital (“FDC“)³, of:
- PDP: $22.24/boe
- 1P: $25.82/boe
- 2P: $42.98/boe
With an estimated¹⁰ 2023 average Operating Netback of $24.37/boe, inclusive of hedge gain, finding, development and acquisition recycle ratios of:
- 1P: 1.78
- 2P: 2.18

Summary of Oil & Gas Reserves⁶ as of Dec 31, 2023

Reserves – Total Company Interest			Light and Medium Oil	Conventional Natural Gas		Natural Gas Liquids	Total
			Mbbl	MMcf		Mbbl	Mboe
Total Proved Developed Producing			2,722	14,345		658.7	5,772
Total Proved			7,275	27,196		1,591	13,399
Total Probable			3,654	18,257		958	7,655
Total Proved plus Probable			10,930	45,453		2,549	21,054
Summary of Net Present Values as of Dec 31, 2023 (Before Income Tax)^2,3,4,5

Before Tax Present Value (M$)			Undiscounted	5%		10%	15%
Total Proved Developed Producing			-7,381	35,472		44,271	44,954
Total Proved			151,004	150,724		129,815	109,449
Total Probable			202,109	144,143		107,712	83,459
Total Proved plus Probable			353,113	294,867		237,527	192,907
Price Forecast² (Sproule, GLJ, McDaniel Average), Jan 1, 2024

Year	F/X	WTI	Cromer Medium		Alberta AECO
	USD/CAD	USD/bbl	CAD/bbl		CAD/Mmbtu
2024	0.75	73.67	88.03		2.20
2025	0.75	74.98	90.02		3.37
2026	0.76	76.14	90.95		4.05
2027	0.76	77.66	92.77		4.13
2028	0.76	79.22	94.63		4.21
2029	0.76	80.80	96.52		4.30
2030	0.76	82.42	98.45		4.38
2031	0.76	84.06	100.42		4.47
2032	0.76	85.74	102.43		4.56
2033	0.76	87.46	104.48		4.65

Reconciliation of Total Company Reserves

	Total Light & Medium Crude			Total Natural Gas			Total Natural Gas Liquids			BOE
FACTORS	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
FACTORS	Mbbl	Mbbl	Mbbl	MMcf	MMcf	MMcf	Mbbl	Mbbl	Mbbl	Mboe	Mboe	Mboe
Open Dec 31, 2022	6,480	3,460	9,940	16,157	14,126	30,283	554	503	1,057	9,727	6,317	16,044
Acquisitions	3,768	1,704	5,472	11,792	5,406	17,198	1,084	498	1,582	6,816	3,104	9,920
Dispositions	-2,946	-874	-3,820		0		-70	-16	-86	-3,016	-890	-3,906
Economic Factors	57	28	84	170	-24	146	6	-2	4	91	21	112
Extensions/Improved Rec.	521	169	689	1,365	243	1,608	94	16	110	842	225	1,067
Technical Revisions	258	-777	-519	655	-1,612	-958	80	-56	25	449	-1,101	-652
Transfer to PDP	-111	-51	-162	34	124	158	-8	16	8	-112	-14	-127
Production	-751	-3	-754	-2,975	-8	-2,983	-150	-1	-151	-1,399	-5	-1,404
Close Dec 31, 2023	7,275	3,655	10,930	27,196	18,257	45,453	1,591	958	2,549	13,399	7,655	21,054

Notes:

Reserves from Acquisition may differ from previous disclosure due to well underperformance or out performance.
The inflation rate is 0% in 2024, 2% per year in 2025 and 2% per year starting in 2026.
Estimated future undiscounted development costs, in dollars, at December 31, 2023 were CAD $142.7 million for proved reserves and CAD $184.7 million for proved plus probable reserves.
Report includes well and facility abandonment and reclamation costs of CAD $101.8 million (with inflation) for the proved plus probable case.
The net present values disclosed may not represent fair market value.
Totals may not add exactly due to rounding.
Development and Exploration capex in 2023 was $29.7 million.
Basic Net Asset Value (“Basic NAV“) includes NPV10 of 1P and 2P reserves, respectively, less estimated¹⁰ net debt balance of $14.5 million as of December 31, 2023, divided by 218,418,315 outstanding common shares.
Diluted Net Asset Value (“Diluted NAV“) includes NPV10 of 1P and 2P reserves, respectively, less estimated¹⁰ net debt balance of $14.5 million as of December 31, 2023, divided by 351,420,192 fully-diluted common shares.
Estimated prior to finalizing year-end audited financial statements.
Published by ATB Capital Markets Institutional Research: Energy Producers, on January 28, 2024

First-Half 2024 Guidance

With the current softening of the North American oil and natural gas markets, the Company will utilize the first six months of 2024 to focus on: (i) debt reduction, (ii) improving operational efficiencies, (iii) strategic well reactivations and optimizations, and (iv) advancement of the lithium project. The 1H 2024 capital budget is comprised of $4.0 – $4.5 million, approximately 60% of which is dedicated to well reactivations and recompletions in core operating areas in Southeast Saskatchewan.

The Company will provide second half 2024 guidance in the second quarter of 2024. Subject to a less volatile commodity price environment, the second half of 2024 is expected to include an active drilling program aimed at expediting growth and reducing F&D costs in core operating areas, with a continued emphasis on Frobisher drilling. Strategic Midale development may also occur, however pressure maintenance will become a focus in the Company’s more mature Midale pools. Within the Kaybob area, the Company will remain positioned to deploy capital on its Cardium oil and Montney gas development, should economics justify an investment.

Highlights of First-Half 2024 Guidance

Capital Discipline: After an active 2H 2023, achieving a daily average production rate in December of 4,650 boepd, the Company will pursue a reduced capital budget in 1H 2024 and expects to average ~4,000 boepd (61% liquids);
Expedited Debt Reduction: Direct generated funds towards further debt reduction with an estimated $13 – $15 million in Adjusted Net Debt at the end of first-half 2024, which represents a 20% – 30% reduction from estimated¹⁰ 2023 exit Adjusted Net Debt; and
Efficient Use of Capital: $2.1 to $2.6 million allocated to 15 – 20 reactivations and recompletions, which is expected to yield capital efficiencies of $5,000 to $10,000 per boepd.

About ROK

ROK is primarily engaged in exploring for petroleum and natural gas development activities in Alberta and Saskatchewan. It has offices located in both Regina, Saskatchewan, Canada and Calgary, Alberta, Canada. ROK’s common shares are traded on the TSX Venture Exchange under the trading symbol “ROK”.

By way of update, the National Instrument 43-101 Preliminary Economic Assessment, previously outlined in the Company’s January 9^th, 2024 press release, has been filed on SEDAR+ (www.sedarplus.ca).

For further information, please contact:

Cameron Taylor, Chairman and Chief Executive Officer
Bryden Wright, President and Chief Operating Officer
Jared Lukomski, Senior Vice President, Land & Business Development
Lynn Chapman, Chief Financial Officer
Phone: (306) 522-0011
Email: [email protected]
Website: www.rokresources.ca

Non-IFRS Measures

The non-IFRS measures referred to above do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and, therefore, may not be comparable to similar measures used by other companies. Management uses this non-IFRS measurement to provide its shareholders and investors with a measurement of the Company’s financial performance and are not intended to represent operating profits nor should they be viewed as an alternative to cash provided by operating activities, net income or other measures of financial performance calculated in accordance with IFRS. 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 and operating expense from total sales revenue. Total sales revenue is comprised of oil and gas sales. The Company refers to Operating Income expressed per unit of production as an “Operating Netback”. “Operating Income Profit Margin” is calculated by the Company as Operating Income as a percentage of oil and natural gas sales. “Funds from Operations” is calculated by adding other income and realized gains/losses on commodity contracts (“hedging”) to Operating Income. “Net Debt” includes all indebtedness of the Company, such as the Credit Facility and Lease Obligations (each as defined within the Company’s interim condensed financial statements for the nine months ended September 30, 2023), net of Adjusted Working Capital. “Adjusted Working Capital” is calculated as current assets less current liabilities, excluding current portion of debt and lease liability as defined on the Company’s statement of financial position within the Company’s interim condensed financial statements for the nine months ended September 30, 2023. “Adjusted Net Debt” is calculated by removing the “mark-to-market fair value of the current portion of risk management contracts” and “lease obligations” (each as defined within the Company’s interim condensed financial statements for the nine months ended September 30, 2023) from Net Debt.

“Funds Flow” includes all cash from (used in) operating activities and is calculated before the change in non-cash working capital. “Funds Flow Basic ($/share)” and “Funds Flow Diluted ($/share)” are calculated by dividing Funds Flow by the weighted average number of basic shares and weighted average number of diluted shares outstanding, respectively, for the relevant period. These are considered key measures of operating performance and capital management as they demonstrate the Company’s ability to generate the cash necessary to repay debt and fund capital investments. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, each of these provide useful measures of ROK’s ability to generate cash that are not subject to short-term movements in non-cash operating working capital.

Conversion Measures

Production volumes and reserves are commonly expressed on a barrel of oil equivalent (“boe“) basis whereby natural gas volumes are converted at the ratio of 6 thousand cubic feet (“Mcf“) to 1 barrel of oil (“bbl“). Although the intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants, boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In recent years, the value ratio based on the price of crude oil as compared to natural gas has been significantly higher than the energy equivalency of 6:1 and utilizing a conversion of natural gas volumes on a 6:1 basis may be misleading as an indication of value.

Reserve Disclosure

All reserves information in this press release was prepared by an independent reserve evaluator, effective December 31, 2023, using the reserve evaluators December 31, 2023 forecast prices and costs in accordance with National Instrument 51-101 – Standards of Disclosure of Oil and Gas Activities (“NI 51-101“) and the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook“). All reserve references in this press release are “Company gross reserves“. Company gross reserves are the Company’s total working interest reserves before the deduction of any royalties payable by the Company and before the consideration of the Company’s royalty interests. It should not be assumed that the present worth of estimated future cash flow of net revenue presented herein represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of the Assets and ROK’s crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGLs reserves may be greater than or less than the estimates provided herein.

Abbreviations

bbls/d bopd		barrels per day barrels per day
boepd		barrels oil equivalent per day
IP		Initial Production
NGLs		Natural Gas Liquids
Mboe Mg/l		Thousands of barrels of oil equivalent Milligrams per Litre
MMboe		Millions of barrels of oil equivalent
PDP		Proved Developed Producing
TP		Total Proved Reserves
TPP		Total Proved and Probable Reserves
WTI CA$ US$		West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade Canadian dollars U.S. dollars

Cautionary Statement Regarding Forward-Looking Information

This news release includes certain “forward-looking statements” under applicable Canadian securities legislation that are not historical facts. Forward-looking statements involve risks, uncertainties, and other factors that could cause actual results, performance, prospects, and opportunities to differ materially from those expressed or implied by such forward-looking statements. Forward-looking statements in this news release include, but are not limited to, statements with respect to the Company’s objectives, goals, or future plans and the expected results thereof. Forward-looking statements are necessarily based on several estimates and assumptions that, while considered reasonable, are subject to known and unknown risks, uncertainties and other factors which may cause actual results and future events to differ materially from those expressed or implied by such forward-looking statements. Such factors include but are not limited to general business, economic and social uncertainties; litigation, legislative, environmental, and other judicial, regulatory, political and competitive developments; delay or failure to receive board, shareholder or regulatory approvals; those additional risks set out in ROK’s public documents filed on SEDAR+ at www.sedarplus.ca; and other matters discussed in this news release. Although the Company believes that the assumptions and factors used in preparing the forward-looking statements are reasonable, undue reliance should not be placed on these statements, which only apply as of the date of this news release, and no assurance can be given that such events will occur in the disclosed time frames or at all. Except where required by law, the Company disclaims any intention or obligation to update or revise any forward-looking statement, whether because of new information, future events, or otherwise.

Neither the Exchange nor its Regulation Services Provider (as that term is defined in the policies of the Exchange) accepts responsibility of the adequacy or accuracy of this release.

SOURCE: ROK Resources Inc.

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