CALGARY, Alberta – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company“) (TSX: TVE) is pleased to announce that it has entered into two separate agreements to acquire assets in the Provost and Nipisi areas of Alberta (the “Acquisitions“). The Acquisitions include approximately 2,800 boe/d of low decline (~16%) oil weighted assets under waterflood, along with approximately 38,400 net acres in the Clearwater play of Alberta (the “Assets”) for a total purchase price of approximately $135.3 million, net of proceeds from two newly created gross overriding royalties (“GORR”) on the Clearwater and Slave Point Nipisi assets, subject to certain closing adjustments. The completion of the Acquisitions is subject to customary regulatory approvals.
The Acquisitions will be funded through a $55 million bought deal equity financing, Tamarack’s proforma credit facilities at closing of $325 million and $13.7 million in proceeds from the sale of the newly created GORR.
Brian Schmidt, President & CEO of Tamarack said “The Acquisitions supplement Tamarack’s existing position in the Clearwater fairway and are consistent with our returns focused strategy to enhance the sustainability and resiliency of the Company’s free adjusted funds flow(1) profile with low decline oil production, long reserve life and economic oil-weighted drilling inventory. Pro forma the Acquisitions and financing, Tamarack is well-capitalized and strongly positioned to efficiently execute our development plan.”
- Increases Tamarack’s exposure to assets under waterflood and reduces corporate decline rate
- Approximately 2,250 boe/d(2) of Provost Sparky (“Eyehill”) low decline medium oil under waterflood with four (4.0 net) Sparky primary horizontal wells expected to be on production in March. Tamarack has identified 12 net primary and 29 net waterflood conversion patterns in the area. This medium oil asset is in close proximity to Tamarack’s existing Veteran assets and can benefit from operational efficiencies.
- Approximately 500 boe/d(3) of Nipisi Slave Point low decline light oil under waterflood and an additional 50 boe/d of Nipisi Clearwater oil(4) with two additional Clearwater oil wells currently being brought on production and one well being drilled. Tamarack’s 15-24 Clearwater well, offsetting a portion of the acquired Clearwater lands, produced at an average rate of 278 bbl/d in the month of February.
- Tamarack estimates that its pro forma 2021 corporate decline rate will be reduced to a range of 21 to 23%.
- Complements Tamarack’s Clearwater position in the Greater Nipisi area
- 38,400 net acres of land in the Clearwater with 100 development locations over approximately 39 net sections along with 21 net sections of exploratory acreage.
- Light oil production from the Slave Point provides an opportunity to realize further synergies through blending opportunities with the heavier oil production from the Clearwater
- Internal assessments have identified a portion of the Nipisi Clearwater area as a focus for near term waterflood development due to the geological and oil fluid characteristics
- Enhances Tamarack’s free adjusted funds flow(5) profile
- Tamarack’s pro forma 2021 guidance reflects a $20 million increase in free adjusted funds flow
- Increased inventory of economic, low capital cost drilling inventory (~$1.0 to ~$1.2 million per well) in the Sparky and Clearwater oil plays
- Attractive metrics and positive environmental, social and governance (ESG) contributions
- Existing production of ~2,800 boe/d has a low decline (~16%) and a significant oil and natural gas liquids (“NGL”) weighting (~86%)
- Production base supports an annualized operating field netback(5) of ~$35 million (~$35 per boe) and annualized free adjusted funds flow(5) of $25 million
- Attractive environmental asset profile with minimal asset retirement obligation (“ARO”) of $10.8MM (undiscounted, uninflated).
- Financing structure preserves Tamarack’s strong balance sheet
- Equity financing and concurrent GORR disposition allows Tamarack to maintain significant liquidity under its expected proforma credit facilities of $325 million at closing
- Pro forma the Acquisitions, Tamarack will maintain a strong 2021 year-end net debt to trailing annual adjusted funds flow ratio(5) of less than 1.0x
Overview of the Acquisitions
Tamarack has entered into an asset purchase agreement with a publicly-traded oil and gas company (the “Vendor”), pursuant to which the Company will acquire the Vendor’s working interest in the Nipisi and Provost assets for cash consideration of $106 million with an effective date of February 1, 2021 (the “Asset Acquisition”).
Tamarack has signed a letter of intent and binding exclusivity agreement with Woodcote Petroleum Inc. (“Woodcote”) pursuant to which, subject to the execution of a definitive agreement, the Company will acquire all of the issued and outstanding shares of Woodcote, a private company with a 100% operated working interest in Greater Nipisi (the “Corporate Acquisition”) for aggregate consideration of $43 million comprised of $32 million in cash and $11 million in common shares to be issued at a deemed price of $ 2.25/share.
The Acquisitions are expected to close on or about March 25, 2021 subject to certain regulatory and other approvals and the satisfaction or waiver of customary closing conditions.
In conjunction with the Acquisitions, Tamarack has entered into two separate agreements to sell a gross overriding royalty (GORR) on the Clearwater and Slave Point Nipisi portion of the Assets for gross proceeds of $13.7 million.
|Purchase Price (net of royalty proceeds)(1)(2)||$135.3 million|
Oil and NGL Weighting
2021 Estimated Asset Decline Rate
|Drilling Locations(4)||174 gross (166.6 net)|
|Annual Decline Rate(5)||16%|
|Annualized Operating Field Netback(6)||$35.0 million|
|Proved Developed Producing Reserves (7)(8)
Reserve Life Index(9)
|Total Proved Plus Probable Reserves (7)(10)
Reserve Life Index(9)
|Future Development Capital(11)||$7.75/boe|
|Total ARO (Undiscounted) (12)||~$10.8 million|
Pro Forma 2021 Guidance
To reflect the contribution from the Assets effective February 1, 2021, Tamarack has elected to increase its 2021 capital program and guidance as follows:
|Preliminary 2021 Guidance(13)||Tamarack January 2021 Guidance||Tamarack
|Capital Budget ($MM)(15)||105 – 110||105 – 110||125 – 130|
|Average Production (boe/d)(16)||23,000||23,000||26,000|
|% Oil and NGL||64||64||66 – 68|
|Adjusted Funds Flow ($MM)(17)||135 – 140||170 – 175||215 – 220|
|Free Adjusted Funds Flow ($MM)(17)||30 – 35||65 – 70||85 – 90|
|Net Debt to Trailing Adj. Funds Flow ($MM)(17)||<1.5x||<1.0x||<1.0x|
|Corporate Decline Rate (%)(18)||22 – 24||22 – 24||21 – 23|
Tamarack has entered into an agreement with a syndicate of underwriters led by National Bank Financial Inc. and Peters & Co. Limited (the “Underwriters“), pursuant to which the Underwriters have agreed to purchase for resale to the public, on a bought-deal basis, 24.45 million common shares (“Common Shares“) of Tamarack at a price of $2.25 per Common Share for gross proceeds of approximately $55.0 million (the “Offering“). The Underwriters will have an option to purchase up to an additional 15% of the Common Shares issued under the Offering at a price of $2.25 per Common Share to cover over-allotments exercisable in whole or in part at any time until 30 days after the closing.
The Common Shares issued pursuant to the Offering will be distributed by way of a short form prospectus in all provinces of Canada (excluding Québec) and may also be placed privately in the United States to Qualified Institutional Buyers (as defined under Rule 144A under the United States Securities Act of 1933, as amended (the “U.S. Securities Act“)) pursuant to an exemption under Rule 144A, and may be distributed outside Canada and the United States on a basis which does not require the qualification or registration of any of the Company’s securities under domestic or foreign securities laws. Completion of the Offering is subject to customary closing conditions, including the receipt of all necessary regulatory approvals, including the approval of the TSX. Closing of the Offering is expected to occur on March 25, 2021.
Board of Directors Appointment
Tamarack is pleased to announce the appointment of Mr. John Rooney to its Board of Directors. Mr. Rooney is a Calgary-based entrepreneurial executive with a technical background in finance and is Chairman of Kara Technologies Inc, an organization dedicated to the development of next-generation technology for the economic production of low emissions fuels. Prior thereto, Mr. Rooney founded and ran a number of public oil and gas companies including: Northern Blizzard Resources Inc. (Chairman & CEO); Tusk Energy Corporation (CEO); Zenas Energy Inc. (President & CEO); Blizzard Energy Inc. (President & CEO); and Equatorial Energy Inc. (multiple executive roles).
In addition to his strong working knowledge of the oil and gas industry, Mr. Rooney brings exceptional value to the Tamarack Board of Directors through his more than 20 years of public, private and not-for-profit directorships. He also brings a unique stakeholder and sustainability perspective from his five years as director with Export Development Canada and his current role with Kara Technologies. Mr. Rooney is a Chartered Accountant and a Chartered Business Valuator.
Peters & Co. Limited is acting as financial advisor to Tamarack with respect to the Asset Acquisition and strategic advisor with respect to the Corporate Acquisition.
National Bank Financial Inc. is acting as financial advisor to Tamarack with respect to the GORR and the Corporate Acquisition.
ATB and CIBC are acting as strategic advisors to Tamarack with respect to the Asset Acquisition.
Stikeman Elliott LLP is acting as counsel to Tamarack with respect to the Acquisitions, the GORR and the Financing.
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company committed to long-term growth and the identification, evaluation, and operation of resource plays in the Western Canadian Sedimentary Basin. Tamarack’s strategic direction is focused on two key principles: (i) targeting repeatable and relatively predictable plays that provide long-life reserves; and (ii) using a rigorous, proven modeling process to carefully manage risk and identify opportunities. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily in the Cardium, Clearwater and Viking fairways in Alberta that are economic over a range of oil and natural gas prices. With this type of portfolio and an experienced and committed management team, Tamarack intends to continue delivering on its strategy to maximize shareholder returns while managing its balance sheet.
For additional information, please contact
President & CEO
Tamarack Valley Energy Ltd.
VP Finance & CFO
Tamarack Valley Energy Ltd.
|AECO||the natural gas storage facility located at Suffield, Alberta connected to TC Energy’s Alberta System|
|bbls/d||barrels per day|
|boe||barrels of oil equivalent|
|boe/d||barrels of oil equivalent per day|
|IFRS||International Financial Reporting Standards as issued by the International Accounting Standards Board|
|MMboe||million barrels of oil equivalent|
|MMcf/d||million cubic feet per day|
|MSW||Mixed sweet blend, the benchmark for conventionally produced light sweet crude oil in Western Canada|
|WTI||West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade|
This press release is not an offer of the securities for sale in the United States. The securities offered have not been, and will not be, registered under the U.S. Securities Act or any U.S. state securities laws and may not be offered or sold in the United States absent registration or an available exemption from the registration requirement of the U.S. Securities Act and applicable U.S. state securities laws. This press release shall not constitute an offer to sell or the solicitation of an offer to buy, nor shall there be any sale of these securities, in any jurisdiction in which such offer, solicitation or sale would be unlawful.
Notes to Press Release
- The aggregate consideration to be paid by Tamarack in respect of the Acquisitions is estimated to be $149 million, less $13.7 million in GORR proceeds, for net purchase price of $135 million, before customary closing adjustments, comprised of $124.3 in cash and $11 million in common shares to be issued a deemed price of $2.25/share.
- The Company expects purchase price adjustments, which include estimated cash flows, capital expenditures and interest from the effective date of the Acquisition, being February 1, 2021, to the closing date of the Acquisitions, anticipated to be on or about March 25, 2021. Purchase price adjustment may also be adjusted as a result of the exercise of any rights of first refusal.
- Average production in the month of February 2021 from the Assets was approximately 2,800 boe/d, consisting of 2,370 bbl/d of oil (85%), 50 bbl/d of NGL (2%) and 2,280 MMcf/d of natural gas (14%).
- See “Drilling Locations” for additional details.
- The annual decline rate is based on the proved developed producing reserves (“PDP“) and has been calculated by deducting February 2021 average production estimated February 2022 average production of, divided by the February 2021 average production. See note (7), below.
- Annualized operating field netback is based on current production and estimated operating field netback of $34.89/boe. Operating field netback is a non-IFRS measure. See “Non-IFRS Measures” for additional details.
- Proved developed producing reserves (“PDP“) and total proved plus probable reserves (“TPP“) are internally estimated by the Company’s internal qualified reserve evaluators (“QRE“) and prepared in accordance with National Instrument 51-101 – Standards of Disclosure of Oil and Gas Activities (“NI 51-101“) and the most recent publication of the Canadian Oil and Gas Evaluations Handbook (“COGEH“). “Internally estimated” means an estimate that is derived by the Company’s internal QRE and prepared in accordance with NI 51-101. All internal estimates contained in this press release have been prepared effective as of March 1, 2021. Reserves values are based on working interest reserves of the Assets before deduction of royalties and without including any of royalty interest reserves.
- PDP consisting of 3.8 MMbbl of oil (89%), 0.1 MMbbl of NGL (1%) and 2.4 MMcf of natural gas (10%).
- Reserve life index (“RLI“) is calculated by dividing PDP or TPP, as applicable, by estimated current production of the Assets of 2,800 boe/d. See “Non-IFRS Measures” for additional details. See note (3) for a breakdown of estimated current production from the Assets by product type and note (7) for further information regarding reserves estimates.
- TPP consisting of 9.8 MMbbl of oil (89%), 0.1 MMbbl of NGL (1%) and 6.1 MMcf of natural gas (10%).
- Future development capital presented above is based on reserves attributable to the Assets and represents expectations for the remainder of 2021. Future development capital is a non-IFRS measure. See “Non-IFRS Measures” for additional details.
- 2021 abandonment and reclamation obligations internally estimated by Tamarack’s QRE and prepared in accordance with NI 51-101 and COGEH. See note (7), above.
- Tamarack’s pre-Acquisition guidance shown under “Tamarack Pre-Acquisition” has been revised from previous guidance publicly disclosed in the Company’s press release dated January 11, 2021 and reproduced under “Tamarack January 2021 Guidance“. For purposes of this table, the guidance has been revised to isolate the impact of the Acquisitions on Tamarack’s 2021 guidance, based on current assumptions for forecast commodity prices, specifically: US$57.50/bbl WTI; US$4.25/bbl MSW/WTI differential; US$12.00/bbl WSC/WTI differential; $2.70/GJ AECO; and a USD/CAD exchange rate of $1.27.
- Assumes a March 25, 2021 closing date for the Acquisitions.
- Capital budget includes exploration and development (“E&D”) capital, ARO, ESG initiatives, facilities, land and seismic.
- Annualized production. Production guidance prior to the completion of the Acquisitions shown under “Tamarack Pre-Acquisition” is the midpoint of guidance and consists of approximately 56% oil, 8% NGL and 36% natural gas. Production guidance post completion of the Acquisitions shown under “Tamarack Post-Acquisition” consists of approximately 59% oil, 7% NGL and 34% natural gas. Percentage change is based on the midpoint of production guidance.
- Adjusted Funds Flow, Free Adjusted Funds Flow and Net Debt to Trailing Adjusted Funds Flow are non-IFRS measures. See “Non-IFRS Measures“.
- The annual decline rate is calculated as March 2021 to March 2022.
Disclosure of Oil and Gas Information
Unit Cost Calculation. For the purpose of calculating unit costs, natural gas volumes have been converted to a boe using six thousand cubic feet equal to one barrel unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with NI 51-101. Boe may be misleading, particularly if used in isolation.
Reserves Disclosure. All reserves information in this press release relating to Assets are internally estimated by the Company’s’ QRE effective March 1, 2021 in accordance with NI 51-101 and the COGEH. The estimates of reserves and future net revenue for the Acquisitions may not reflect the same confidence level as estimates of reserves and future net revenue for all of Tamarack’s properties, due to the effects of aggregation.
All reserve references in this press release are “gross reserves”. Gross reserves are a company’s total working interest reserves before the deduction of any royalties payable by such company and before the consideration of such 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 Tamarack’s crude oil, NGL and natural gas reserves, including those of the Assets, provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater than or less than the estimates provided herein.
Drilling Locations. This press release discloses drilling locations with respect to the Assets in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Company’s internal reserves evaluation as prepared by a member of management who is a qualified reserves evaluator in accordance with NI 51-101 effective March 3, 2021 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s assumptions as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the total 174 (166.6 net) drilling locations identified herein, 38 (35.3 net) are proved locations, eight (8.0 net) are probable locations and 128 (123.3 net) are unbooked locations. Of the 108 (105.5 net) locations specifically identified in the Nipisi area, all 108 (105.5 net) locations are unbooked. Unbooked locations have been identified by management as an estimation of Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information assuming completion of the Acquisitions. Assuming completion of the Acquisitions, there is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations considered for future development will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by the drilling of existing wells by the Vendor in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.