Offering Details
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Under Review / Erikson National Energy Inc.
Erikson National Energy Inc.
Corporate DivestitureBid Deadline: March 2, 2023
12:00 PM
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OVERVIEW
Erikson National Energy Inc. (“Erikson” or the “Company”) has engaged Sayer Energy Advisors to assist Erikson with a sale of the shares of the Company.
Erikson is a private junior oil and natural gas company with assets located in the Wildboy and Greater Fort St. John areas of British Columbia (the “Properties”).
The Properties consist primarily of operated, high working interest shale natural gas production from several formations including the Baldonnel, Charlie Lake, Debolt, Halfway, Jean-Marie and Muskwa formations.
In the Greater Fort St. John area, the Company has working interests in the Buick Creek, Fireweed, Fort St. John, Laprise, Roseland and Stoddart areas.
The Company’s average daily sales production in the fourth quarter of 2022 consisted of approximately 18.1 MMcf/d of natural gas and 22 barrels of oil and natural gas liquids per day (3,043 boe/d).
Operating income net to Erikson from the Properties for the year ended September 30, 2022 was approximately $602,000 per month, or $7.2 million on an annualized basis.
As at September 30, 2022, Erikson’s working capital deficit was approximately $4.6 million. Additional corporate information relating to Erikson will be provided to parties upon execution of a confidentiality agreement.
Erikson has been reactivating operations since acquiring the Properties in June 2020.
The Company has 100% owned midstream facilities capable of over 140 MMcf/d of natural gas throughput.
Erikson has significant upside in drilled, uncompleted inventory ready for execution. Erikson commissioned Deloitte LLP to provide independent resource estimation and economic evaluations of the Muskwa, Evie, Bluesky, Spirit River, Shunda and Debolt formations for the Properties effective September 30, 2022.
Deloitte has identified “risked contingent development pending” (best case) natural gas resources of 8.6 Bcf equivalent of resource potential in the Spirit River Formation in the Greater Fort St. John Area, 35.7 Bcf equivalent in the Muskwa and Evie formations at Wildboy, 7.3 Bcf equivalent in the Shunda and Debolt formations, accessible as up-hole opportunities in existing wells at Wildboy, and 8.3 Bcf equivalent in the Bluesky Formation across both areas. Copies of the resource estimation reports are available in the virtual data room for companies that execute a confidentiality agreement.
Erikson is a private junior oil and natural gas company with assets located in the Wildboy and Greater Fort St. John areas of British Columbia (the “Properties”).
The Properties consist primarily of operated, high working interest shale natural gas production from several formations including the Baldonnel, Charlie Lake, Debolt, Halfway, Jean-Marie and Muskwa formations.
In the Greater Fort St. John area, the Company has working interests in the Buick Creek, Fireweed, Fort St. John, Laprise, Roseland and Stoddart areas.
The Company’s average daily sales production in the fourth quarter of 2022 consisted of approximately 18.1 MMcf/d of natural gas and 22 barrels of oil and natural gas liquids per day (3,043 boe/d).
Operating income net to Erikson from the Properties for the year ended September 30, 2022 was approximately $602,000 per month, or $7.2 million on an annualized basis.
As at September 30, 2022, Erikson’s working capital deficit was approximately $4.6 million. Additional corporate information relating to Erikson will be provided to parties upon execution of a confidentiality agreement.
Erikson has been reactivating operations since acquiring the Properties in June 2020.
The Company has 100% owned midstream facilities capable of over 140 MMcf/d of natural gas throughput.
Erikson has significant upside in drilled, uncompleted inventory ready for execution. Erikson commissioned Deloitte LLP to provide independent resource estimation and economic evaluations of the Muskwa, Evie, Bluesky, Spirit River, Shunda and Debolt formations for the Properties effective September 30, 2022.
Deloitte has identified “risked contingent development pending” (best case) natural gas resources of 8.6 Bcf equivalent of resource potential in the Spirit River Formation in the Greater Fort St. John Area, 35.7 Bcf equivalent in the Muskwa and Evie formations at Wildboy, 7.3 Bcf equivalent in the Shunda and Debolt formations, accessible as up-hole opportunities in existing wells at Wildboy, and 8.3 Bcf equivalent in the Bluesky Formation across both areas. Copies of the resource estimation reports are available in the virtual data room for companies that execute a confidentiality agreement.
Overview Map Showing the Location of Erikson's Properties
Production Overview
The Company’s average daily sales production in the fourth quarter of 2022 consisted of approximately 18.1 MMcf/d of natural gas and 22 barrels of oil and natural gas liquids per day (3,043 boe/d).
The Company’s average daily sales production in the fourth quarter of 2022 consisted of approximately 18.1 MMcf/d of natural gas and 22 barrels of oil and natural gas liquids per day (3,043 boe/d).
Gross Production Group Plot of Erikson's Natural Gas Wells
Reserves Overview
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Properties contained remaining proved plus probable reserves of 115.2 Bcf of natural gas and 392,000 barrels of oil and natural gas liquids (19.6 million boe), with an estimated net present value of $105.2 million using forecast pricing at a 10% discount.
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Properties contained remaining proved plus probable reserves of 115.2 Bcf of natural gas and 392,000 barrels of oil and natural gas liquids (19.6 million boe), with an estimated net present value of $105.2 million using forecast pricing at a 10% discount.
Erikson commissioned Deloitte to provide independent resource estimation and economic evaluations of the Muskwa, Evie, Bluesky, Spirit River, Shunda and Debolt formations for the Properties effective September 30, 2022. Copies of the resource estimation reports are available in the virtual data room for companies that execute a confidentiality agreement.
Marketing Overview
Natural gas sales from Wildboy go directly into the NOVA Gas Transmission Line system at the Bootis Hill meter station #2709 via a 50% owned pipeline with Tidewater Midstream and Infrastructure Ltd. A purchase option for the 50% operated interest has been exercised by Erikson to increase its interest to 100%. Canadian Energy Regulator approvals for the transfer are anticipated in the first half of 2023. Erikson currently holds 573 e3m3/d of firm service on the NOVA Gas Transmission Line system, and receives AECO pricing for natural gas produced from Wildboy.
Natural gas production from the Greater Fort St. John area goes directly into the North River Midstream Operations LP infrastructure.
Seismic
The Company does not own any proprietary seismic data.
Asset Retirement Obligation Overview
On April 1, 2022, the BC Oil & Gas Commission (“BCOGC”) implemented its requirements for the Permittee Capability Assessment (“PCA”) program as a replacement to the Liability Management Rating program. The PCA assesses each permit holder’s corporate health against the liability associated with their Dormant, Inactive, and Marginal sites (referred to as DIM Liability) to determine corrective action requirements. These may include additional security requirements under Section 30 of the Oil and Gas Activities Act or closure work on sites that have reached the end of their productive potential. Erikson’s PCA score was calculated to be 81.99. Erikson anticipates having an updated PCA score in early February which will be provided to parties that execute a confidentiality agreement.
On July 30, 2022, Erikson submitted a proposed asset retirement obligation (“ARO”) work plan for the balance of the 2022 calendar year as part of its compliance with the BCOGC’s PCA program. The work program included a progress summary for the applicable activities. The summary includes downhole abandonment projects in the Fort St. John area and pipeline and well reactivations in the Stoddart area. In September 2022, the BCOGC ordered Erikson to post additional security. Erikson continues to manage its ARO obligations and communicate these plans with the BCOGC.
Further ARO work is to be continued in 2023. A summary spreadsheet of the Erikson assets classified for the inactive and dormant well program requirements as well as the details of the work program and the progress summary are available in the virtual data room for parties that execute a confidentiality agreement.
The chart below shows a capital schedule for the Company’s identified ARO work.
Marketing Overview
Natural gas sales from Wildboy go directly into the NOVA Gas Transmission Line system at the Bootis Hill meter station #2709 via a 50% owned pipeline with Tidewater Midstream and Infrastructure Ltd. A purchase option for the 50% operated interest has been exercised by Erikson to increase its interest to 100%. Canadian Energy Regulator approvals for the transfer are anticipated in the first half of 2023. Erikson currently holds 573 e3m3/d of firm service on the NOVA Gas Transmission Line system, and receives AECO pricing for natural gas produced from Wildboy.
Natural gas production from the Greater Fort St. John area goes directly into the North River Midstream Operations LP infrastructure.
Seismic
The Company does not own any proprietary seismic data.
Asset Retirement Obligation Overview
On April 1, 2022, the BC Oil & Gas Commission (“BCOGC”) implemented its requirements for the Permittee Capability Assessment (“PCA”) program as a replacement to the Liability Management Rating program. The PCA assesses each permit holder’s corporate health against the liability associated with their Dormant, Inactive, and Marginal sites (referred to as DIM Liability) to determine corrective action requirements. These may include additional security requirements under Section 30 of the Oil and Gas Activities Act or closure work on sites that have reached the end of their productive potential. Erikson’s PCA score was calculated to be 81.99. Erikson anticipates having an updated PCA score in early February which will be provided to parties that execute a confidentiality agreement.
On July 30, 2022, Erikson submitted a proposed asset retirement obligation (“ARO”) work plan for the balance of the 2022 calendar year as part of its compliance with the BCOGC’s PCA program. The work program included a progress summary for the applicable activities. The summary includes downhole abandonment projects in the Fort St. John area and pipeline and well reactivations in the Stoddart area. In September 2022, the BCOGC ordered Erikson to post additional security. Erikson continues to manage its ARO obligations and communicate these plans with the BCOGC.
Further ARO work is to be continued in 2023. A summary spreadsheet of the Erikson assets classified for the inactive and dormant well program requirements as well as the details of the work program and the progress summary are available in the virtual data room for parties that execute a confidentiality agreement.
The chart below shows a capital schedule for the Company’s identified ARO work.
WILDBOY
NTS 094-P-05 - 094-P-16
At Wildboy, Erikson holds primarily 100% operated working interests in over 1,000 natural gas spacing units of land. Production from Wildboy is primarily from the Bluesky, Debolt, Jean Marie and Muskwa formations. Erikson has identified upside through infill drilling in the Jean Marie Formation as well as recompletions in the Bluesky Formation. The Company also believes there is potential for significant drilling in the Muskwa, Evie and Otterpark shales with over 2.3 Tcf of contingent natural gas resources.
The Company holds a 100% interest in midstream facilities capable of over 140 MMcf/d of natural gas throughput at Wildboy.
Average daily sales production net to the Company from Wildboy in the fourth quarter of 2022 was approximately 16.6 MMcf/d of natural gas and 18 barrels of natural gas liquids per day (2,777 boe/d).
At Wildboy, Erikson holds primarily 100% operated working interests in over 1,000 natural gas spacing units of land. Production from Wildboy is primarily from the Bluesky, Debolt, Jean Marie and Muskwa formations. Erikson has identified upside through infill drilling in the Jean Marie Formation as well as recompletions in the Bluesky Formation. The Company also believes there is potential for significant drilling in the Muskwa, Evie and Otterpark shales with over 2.3 Tcf of contingent natural gas resources.
The Company holds a 100% interest in midstream facilities capable of over 140 MMcf/d of natural gas throughput at Wildboy.
Average daily sales production net to the Company from Wildboy in the fourth quarter of 2022 was approximately 16.6 MMcf/d of natural gas and 18 barrels of natural gas liquids per day (2,777 boe/d).
Wildboy, British Columbia
Gross Production Group Plot of Erikson's Natural Gas Wells
The Wildboy property has an extensive gathering system and processing infrastructure as outlined in the plat below.
Wildboy Upside Resource Potential
Erikson believes the Muskwa, Otter Park and Evie shales are a significant resource for the Company, as shown on the following well logs. Total discovered natural gas resources initially in place of approximately 7.9 Tcf have been calculated on Erikson’s lands. The Company has eight horizontal wells that have been drilled but not completed in this shale resource: six targeting the Muskwa, one in the Otter Park and one targeting the Evie. Plans to complete these wells are ongoing. Deloitte has classified the volume estimates from these wells as “risked contingent development pending” with resources potential of up to 35.7 Bcf equivalent.
In addition, Deloitte has identified “risked contingent development pending” natural gas resources of up to 7.3 Bcf equivalent in the Shunda and Debolt formations accessible as up-hole opportunities in existing wells at Wildboy. Deloitte has identified 8.3 Bcf equivalent in the Bluesky Formation across both the Wildboy and Greater Fort St. John areas.
Erikson believes the Muskwa, Otter Park and Evie shales are a significant resource for the Company, as shown on the following well logs. Total discovered natural gas resources initially in place of approximately 7.9 Tcf have been calculated on Erikson’s lands. The Company has eight horizontal wells that have been drilled but not completed in this shale resource: six targeting the Muskwa, one in the Otter Park and one targeting the Evie. Plans to complete these wells are ongoing. Deloitte has classified the volume estimates from these wells as “risked contingent development pending” with resources potential of up to 35.7 Bcf equivalent.
In addition, Deloitte has identified “risked contingent development pending” natural gas resources of up to 7.3 Bcf equivalent in the Shunda and Debolt formations accessible as up-hole opportunities in existing wells at Wildboy. Deloitte has identified 8.3 Bcf equivalent in the Bluesky Formation across both the Wildboy and Greater Fort St. John areas.
Erikson Helmet 00/C-054-G/094-P-10/0 - Muskwa/Otter Park/Evie Type Log
Erikson has unbooked resource potential on its lands at Wildboy including the following.
Four existing pad sites with completions in the Muskwa Formation:
24G-/094-P-10 Padsite (4.5 MMcf/d potential production) has seven producers and two wells with uphole recompletion potential targeting the Jean Marie zone.
64G-/094-P-10 Padsite (2.5 MMcf/d potential production) has three producers, two suspended wells and upside potential of three drilled but uncompleted wells in the Muskwa Formation.
51G-/094-P-10 Padsite (3.4 MMcf/d potential production) has five producers and four suspended wells.
55A-/094-P-10 Padsite has eight drilled but uncompleted wells as unbooked upside. Two drilled but uncompleted wells have been drilled and cased in the Evie and Otter Park intervals. Completion of the currently drilled uncompleted wells would validate two additional resource horizons.
Erikson proposes that it would do a slick water fracture treatment in the horizontal Muskwa gas wells. The Company previously estimated a $3.6 million cost for this treatment per well.
Further details on the upside including a listing of the potential reactivations are available in the virtual data room for companies that execute a confidentiality agreement.
Jean Marie Formation
The late Devonian Jean Marie Formation at Wildboy was formed in a back barrier reef environment and the development area is within the ‘Helmet’ Jean Marie ‘F’ Pool and Jean Marie ‘A’ Pool, which has over 1.4 Tcf of natural gas production to date.
Four existing pad sites with completions in the Muskwa Formation:
24G-/094-P-10 Padsite (4.5 MMcf/d potential production) has seven producers and two wells with uphole recompletion potential targeting the Jean Marie zone.
64G-/094-P-10 Padsite (2.5 MMcf/d potential production) has three producers, two suspended wells and upside potential of three drilled but uncompleted wells in the Muskwa Formation.
51G-/094-P-10 Padsite (3.4 MMcf/d potential production) has five producers and four suspended wells.
55A-/094-P-10 Padsite has eight drilled but uncompleted wells as unbooked upside. Two drilled but uncompleted wells have been drilled and cased in the Evie and Otter Park intervals. Completion of the currently drilled uncompleted wells would validate two additional resource horizons.
Erikson proposes that it would do a slick water fracture treatment in the horizontal Muskwa gas wells. The Company previously estimated a $3.6 million cost for this treatment per well.
Further details on the upside including a listing of the potential reactivations are available in the virtual data room for companies that execute a confidentiality agreement.
Jean Marie Formation
The late Devonian Jean Marie Formation at Wildboy was formed in a back barrier reef environment and the development area is within the ‘Helmet’ Jean Marie ‘F’ Pool and Jean Marie ‘A’ Pool, which has over 1.4 Tcf of natural gas production to date.
The following well logs from the well Erikson Helmet 00/A-059-G/094-P-11/0 show the Jean Marie Formation at Wildboy with up to eight metres of net pay.
Erikson Helmet 00/A-059-G/094-P-11/0
Jean Marie Type Log
Jean Marie Type Log
The Jean Marie has been historically produced through vertical drilling in the area. Erikson believes that infill drilling of multi-lateral open hole horizontal wells will reduce overall costs to drill, complete, equip and tie-in wells. The Company has identified up to 60 potential locations.
The Jean Marie net pay at Wildboy is shown on the following map.
The Jean Marie net pay at Wildboy is shown on the following map.
Development of the back barrier play is proposed by drilling crowfoot pads similar to the analogous pool by NTE Energy Canada Ltd. in the Sierra area to the south. The Company has identified 16 three-well crowfoot pads on its lands estimated to recover approximately 24 Bcf of natural gas total, or 1.5 Bcf per crowfoot pad. The red wells on the following map show existing Jean Marie production.
Wildboy Jean Marie Back Barrier Development Area
Bluesky Formation
At Wildboy, the Company has identified potential to frac 28 wells in the Bluesky Formation. The Company has identified a number of restart and recompletion upside candidates in the Bluesky Formation. In addition, Erikson has also identified 38 prospects in the Shunda Formation, of which 13 overlap with the Bluesky.
At Wildboy, the Company has identified potential to frac 28 wells in the Bluesky Formation. The Company has identified a number of restart and recompletion upside candidates in the Bluesky Formation. In addition, Erikson has also identified 38 prospects in the Shunda Formation, of which 13 overlap with the Bluesky.
The Bluesky unconformably overlies the Shunda in certain areas of Wildboy where the Mississippian reservoirs are sealed by the Lower Cretaceous formations as shown on the following log. The Debolt Formation subcrops in certain areas in the southwest of Wildboy.
Erikson Helmet 00/C-098-K/094-P-11/0
Bluesky/Shunda Type Log
Bluesky/Shunda Type Log
Wildboy Facilities
The Company has a 100% working interest in the Wildboy Gas Plant located at D-075-A/094-P-11 with capacity of 140 MMcf/d.
The Company has an interest in the following facilities at Wildboy.
The Company has a 100% working interest in the Wildboy Gas Plant located at D-075-A/094-P-11 with capacity of 140 MMcf/d.
The Company has an interest in the following facilities at Wildboy.
Wildboy Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Wildboy property contained remaining proved plus probable reserves of 106.1 Bcf of natural gas and 75,000 barrels of natural gas liquids (17.8 million boe), with an estimated net present value of $92.7 million using forecast pricing at a 10% discount.
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Wildboy property contained remaining proved plus probable reserves of 106.1 Bcf of natural gas and 75,000 barrels of natural gas liquids (17.8 million boe), with an estimated net present value of $92.7 million using forecast pricing at a 10% discount.
GREATER FORT ST. JOHN AREA
Township 82, Range 17W6 - NTS 094-H-05
In the Greater Fort St. John area, the Company has working interests in the Buick Creek, Fireweed, Fort St. John, Laprise, Roseland and Stoddart areas, as shown on the following map.
In the Greater Fort St. John area, the Company has working interests in the Buick Creek, Fireweed, Fort St. John, Laprise, Roseland and Stoddart areas, as shown on the following map.
Greater Fort St. John Production Overview
Average daily sales production net to the Company from the Greater Fort St. John Area in the fourth quarter of 2022 was approximately 1.6 MMcf/d of natural gas and four barrels of natural gas liquids per day (266 boe/d).
Average daily sales production net to the Company from the Greater Fort St. John Area in the fourth quarter of 2022 was approximately 1.6 MMcf/d of natural gas and four barrels of natural gas liquids per day (266 boe/d).
*shut-in
**Stoddart is currently scheduled to be reactivated in the first quarter of 2023
**Stoddart is currently scheduled to be reactivated in the first quarter of 2023
Greater Fort St. John, British Columbia
Gross Production Group Plot of Erikson's Natural Gas Wells
Greater Fort St. John Upside Resource Potential
In the Greater Fort St. John Area, where Erikson has sufficient infrastructure to process and sell its natural gas, Deloitte has identified “risked contingent development pending” (best case) of 8.6 Bcf equivalent of resource potential in the Spirit River Formation. Additional resource potential exists in the Bluesky Formation.
Greater Fort St. John Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Greater Fort St. John area contained remaining proved plus probable reserves of 9.2 Bcf of natural gas and 317,000 barrels of oil and natural gas liquids (1.8 million boe), with an estimated net present value of $12.5 million using forecast pricing at a 10% discount.
In the Greater Fort St. John Area, where Erikson has sufficient infrastructure to process and sell its natural gas, Deloitte has identified “risked contingent development pending” (best case) of 8.6 Bcf equivalent of resource potential in the Spirit River Formation. Additional resource potential exists in the Bluesky Formation.
Greater Fort St. John Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Greater Fort St. John area contained remaining proved plus probable reserves of 9.2 Bcf of natural gas and 317,000 barrels of oil and natural gas liquids (1.8 million boe), with an estimated net present value of $12.5 million using forecast pricing at a 10% discount.
FIREWEED/BUICK CREEK
NTS 094-A-11 – 094-A-14
At Fireweed/Buick Creek, Erikson holds operated working interests ranging from 56.25% to 100% in approximately 100 spacing units of land.
Average daily production sales net to the Company from Fireweed in the fourth quarter of 2022 was approximately 666 Mcf/d of natural gas and four barrels per day of condensate (115 boe/d).
The Buick Creek wells are currently shut-in pending an engineering assessment for potential reactivation.
At Fireweed/Buick Creek, Erikson holds operated working interests ranging from 56.25% to 100% in approximately 100 spacing units of land.
Average daily production sales net to the Company from Fireweed in the fourth quarter of 2022 was approximately 666 Mcf/d of natural gas and four barrels per day of condensate (115 boe/d).
The Buick Creek wells are currently shut-in pending an engineering assessment for potential reactivation.
Fireweed, British Columbia
Gross Production Group Plot of Erikson's Natural Gas Wells
Buick Creek, British Columbia
Gross Production Group Plot of Erikson's Natural Gas Wells
Fireweed/Buick Creek Upside
Bluesky Formation
The Company has identified potential to frac five wells at Fireweed and eight wells at Buick Creek in the Bluesky Formation.
Bluesky Formation
The Company has identified potential to frac five wells at Fireweed and eight wells at Buick Creek in the Bluesky Formation.
Erikson Et Al N Buick 00/B-044-F/094-A-14/0
Bluesky, Cadomin & Baldonnel Type Log
Bluesky, Cadomin & Baldonnel Type Log
The following map shows the wells which have produced from the Bluesky Formation at Fireweed/Buick Creek.
At Fireweed, the Company has identified potential to frac five wells in the Bluesky Formation which are illustrated with red circles on the following map.
Erikson has identified upside potential of approximately 1.0 Bcf of natural gas per well.
Erikson has identified upside potential of approximately 1.0 Bcf of natural gas per well.
At Buick Creek, the Company has identified potential to frac eight wells in the Bluesky Formation which are illustrated with red circles on the following maps.
Erikson has identified upside potential of approximately 1.0 Bcf of natural gas per well.
Erikson has identified upside potential of approximately 1.0 Bcf of natural gas per well.
Fireweed/Buick Creek Facilities
At Fireweed, The Company holds a 100% working interest in a compressor located at A-057-A/094-A-13.
Fireweed/Buick Creek Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Fireweek/Buick Creek property contained remaining proved plus probable reserves of 3.4 Bcf of natural gas and 66,000 barrels of natural gas liquids (636,000 boe), with an estimated net present value of $3.8 million using forecast pricing at a 10% discount.
At Fireweed, The Company holds a 100% working interest in a compressor located at A-057-A/094-A-13.
Fireweed/Buick Creek Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Fireweek/Buick Creek property contained remaining proved plus probable reserves of 3.4 Bcf of natural gas and 66,000 barrels of natural gas liquids (636,000 boe), with an estimated net present value of $3.8 million using forecast pricing at a 10% discount.
Fireweed/Buick Creek Well List
Click here to download the complete well list in Excel.
Click here to download the complete well list in Excel.
ROSELAND
Township 88, Range 19 W6
At Roseland, the Company holds 75%-100% operated working interests in approximately 12 sections of land.
Average daily sales production net to the Company from Roseland in the fourth quarter of 2022 was approximately 478 Mcf/d of natural gas (80 boe/d).
At Roseland, Erikson has 13 producing wells with one single well battery. The Roseland area is a sweet natural gas field.
At Roseland, the Company holds 75%-100% operated working interests in approximately 12 sections of land.
Average daily sales production net to the Company from Roseland in the fourth quarter of 2022 was approximately 478 Mcf/d of natural gas (80 boe/d).
At Roseland, Erikson has 13 producing wells with one single well battery. The Roseland area is a sweet natural gas field.
Roseland, British Columbia
Gross Production Group Plot of Erikson’s Natural Gas Wells
Roseland Upside
Spirit River Formation
The Company has identified upside in the Spirit River Formation on its lands at Roseland/Buick Creek as shown on the following map. Erikson has identified 10 wells with upside potential of approximately 1.0 Bcf of natural gas per well.
Spirit River Formation
The Company has identified upside in the Spirit River Formation on its lands at Roseland/Buick Creek as shown on the following map. Erikson has identified 10 wells with upside potential of approximately 1.0 Bcf of natural gas per well.
The well Erikson Buick 00/05-30-088-19W6/0 has produced over 1.0 Bcf of natural gas from the Spirit River Formation. Prior to being shut-in in January 2018, the 05-30 well was producing natural gas at an average rate of approximately 90 Mcf/d.
Erikson Buick 00/05-30-088-19W6/0
Spirit River Type Log
Spirit River Type Log
Roseland Facilities
The Roseland facilities are located at 11-23-088-19W6.
The facility has two compressors, dehydrator, inlet separator and one two-hundred-barrel production tank. Suction pressure ranges from 250-350 Kpa pending sales line pressures.
Sales natural gas is compressed via a high-pressure reciprocal compressor and sent directly to North River Midstream.
The Company completed an overhaul of one of the compressors in 2021.
Roseland Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Roseland property contained remaining proved plus probable reserves of 1.6 Bcf of natural gas and 29,000 barrels of natural gas liquids (300,000 boe), with an estimated net present value of $1.3 million using forecast pricing at a 10% discount.
The Roseland facilities are located at 11-23-088-19W6.
The facility has two compressors, dehydrator, inlet separator and one two-hundred-barrel production tank. Suction pressure ranges from 250-350 Kpa pending sales line pressures.
Sales natural gas is compressed via a high-pressure reciprocal compressor and sent directly to North River Midstream.
The Company completed an overhaul of one of the compressors in 2021.
Roseland Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Roseland property contained remaining proved plus probable reserves of 1.6 Bcf of natural gas and 29,000 barrels of natural gas liquids (300,000 boe), with an estimated net present value of $1.3 million using forecast pricing at a 10% discount.
Roseland Well List
Click here to download the complete well list in Excel.
Click here to download the complete well list in Excel.
LAPRISE
NTS 094 – H – 05
At Laprise, Erikson holds an 85% operated working interest in two natural gas wells producing from the Baldonnel and Charlie Lake formations. The Laprise property is contract operated.
Average daily sales production net to the Company from Laprise in the fourth quarter of 2022 was approximately 403 Mcf/d of natural gas (67 boe/d).
At Laprise, Erikson holds an 85% operated working interest in two natural gas wells producing from the Baldonnel and Charlie Lake formations. The Laprise property is contract operated.
Average daily sales production net to the Company from Laprise in the fourth quarter of 2022 was approximately 403 Mcf/d of natural gas (67 boe/d).
Laprise, British Columbia
Gross Production Group Plot of Erikson’s Natural Gas Wells
The following wells logs show the Baldonnel reservoir for the well Erikson Et Al Laprise 00/B-099-F/094-H-05/0 at Laprise. The well is producing natural gas from both the Baldonnel and Charlie Lake formations.
Erikson Et Al Laprise 00/B-099-F/094-H-05/0
Baldonnel/Charlie Lake Type Log
Baldonnel/Charlie Lake Type Log
Laprise Facilities
The Company does not have ownership in any facilities at Laprise.
Laprise Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Laprise property contained remaining proved plus probable reserves of 1.7 Bcf of natural gas and 30,000 barrels of natural gas liquids (316,000 boe), with an estimated net present value of $2.1 million using forecast pricing at a 10% discount.
The Company does not have ownership in any facilities at Laprise.
Laprise Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Laprise property contained remaining proved plus probable reserves of 1.7 Bcf of natural gas and 30,000 barrels of natural gas liquids (316,000 boe), with an estimated net present value of $2.1 million using forecast pricing at a 10% discount.
Laprise Well List
Click here to download the complete well list in Excel.
Click here to download the complete well list in Excel.
STODDART
Township 86-87, Range 18-19 W6
At Stoddart, Erikson holds a 100% operated working interest in approximately 9.25 sections of land.
The Stoddart property is currently shut-in. Erikson is planning to re-activate the property in the first quarter of 2023. Historical production from the property is from the Baldonnel, Charlie Like and Coplin formations.
Prior to being shut-in, production from Stoddart averaged approximately 900 Mcf/d of natural gas and 25 barrels of oil per day (175 boe/d). Natural gas is sent to North River Midstream for further processing. The natural gas at Stoddart is about 270 ppm H2S.
At Stoddart, Erikson holds a 100% operated working interest in approximately 9.25 sections of land.
The Stoddart property is currently shut-in. Erikson is planning to re-activate the property in the first quarter of 2023. Historical production from the property is from the Baldonnel, Charlie Like and Coplin formations.
Prior to being shut-in, production from Stoddart averaged approximately 900 Mcf/d of natural gas and 25 barrels of oil per day (175 boe/d). Natural gas is sent to North River Midstream for further processing. The natural gas at Stoddart is about 270 ppm H2S.
Stoddart, British Columbia
Gross Production Group Plot of Erikson's Natural Gas Wells
Stoddart Upside
Spirit River Formation
The Company has identified upside in the Spirit River Formation on its lands at Stoddart as shown on the following map. Erikson has identified three wells with upside potential of approximately 1.0 Bcf of natural gas per well.
Spirit River Formation
The Company has identified upside in the Spirit River Formation on its lands at Stoddart as shown on the following map. Erikson has identified three wells with upside potential of approximately 1.0 Bcf of natural gas per well.
The well Erikson Montney 00/14-25-086-19W6/0 has produced over 1.1 Bcf of natural gas from the Baldonnel Formation. The Spirit River reservoir is shown in the following well logs.
Erikson Montney 00/14-25-086-19W6/0
Spirit River Type Log
Spirit River Type Log
Stoddart Facilities
The Erikson Stoddart 06-11-086-19W6 facility consists of a compressor with a booster compressor on site.
Stoddart Reserves
Deloitte LLP (“Deloitte”) prepared an independent reserves evaluation of Erikson’s Properties (the “Deloitte Report”) as part of its year-end reporting. The Deloitte Report is effective September 30, 2022 using Deloitte’s forecast pricing as at October 1, 2022.
Deloitte estimated that, as of September 30, 2022, the Stoddart property contained remaining proved plus probable reserves of 2.2 Bcf of natural gas and 154,000 barrels of oil and natural gas liquids (525,000 boe), with an estimated net present value of $4.6 million using forecast pricing at a 10% discount.
Stoddart Well List
Click here to download the complete well list in Excel.
Click here to download the complete well list in Excel.
FORT ST. JOHN
Township 82-83, Range 17-18 W6
At Fort St. John, Erikson holds a 100% operated working interest in 14 sections of land as well as a 25% working interest in the producing well 200/D-081-K/094-A-11/00 operated by Bonavista Energy Corporation.
All of Erikson’s operated wells at Fort St. John are currently shut-in and the Company is in the process of abandoning the property. All the pipelines as well as seven wells were abandoned as of the fourth quarter of 2022.
Average daily sales production net to the Company from Fort St. John in the fourth quarter of 2022 was approximately 24 Mcf/d of natural gas per day (four boe/d).
At Fort St. John, Erikson holds a 100% operated working interest in 14 sections of land as well as a 25% working interest in the producing well 200/D-081-K/094-A-11/00 operated by Bonavista Energy Corporation.
All of Erikson’s operated wells at Fort St. John are currently shut-in and the Company is in the process of abandoning the property. All the pipelines as well as seven wells were abandoned as of the fourth quarter of 2022.
Average daily sales production net to the Company from Fort St. John in the fourth quarter of 2022 was approximately 24 Mcf/d of natural gas per day (four boe/d).
Fort St. John Reserves
Deloitte evaluated the Fort St. John property as part of the Deloitte Report and no reserves were assigned.
Fort St. John Well List
Click here to download the complete well list in Excel.
Deloitte evaluated the Fort St. John property as part of the Deloitte Report and no reserves were assigned.
Fort St. John Well List
Click here to download the complete well list in Excel.
PROCESS & TIMELINE
Sayer Energy Advisors is accepting proposals relating to the process until 12:00 pm on Thursday March 2, 2023.
Sayer Energy Advisors does not conduct a "second-round" bidding process; the intention is to attempt to conclude a
transaction with the party submitting the most acceptable proposal at the conclusion of the process.
transaction with the party submitting the most acceptable proposal at the conclusion of the process.
Sayer Energy Advisors is accepting proposals from interested parties until
noon on Thursday March 2, 2023.
NOTE REGARDING A SAYER PROCESS
On each and every offering brochure generated by Sayer, you will note the sentence “Sayer Energy Advisors does not conduct a “second-round” bidding process; the intention is to attempt to conclude a sale of the Company with the party submitting the most acceptable proposal at the conclusion of the process.” What this means is that Sayer will not go back to multiple parties at the same time after bids are received, asking them all for a second bid. We determine which party submitted the most acceptable proposal and then we attempt to negotiate acceptable terms with that party in a “one-off” situation.
If the process involves a cash sale of a property or company and the party which submitted the most acceptable proposal has met our client’s threshold value, that offer will be accepted. If this proposal does not meet our client’s threshold value, then we will advise that party that the offer is not quite what our client was expecting, and we will ask them to increase the offer. If that offer is not acceptable to our client, we will then move down to the party which submitted the next most acceptable proposal and we will then work with that party to attempt to meet our client’s threshold value.
In the extremely rare circumstance where two or more parties submit virtually identical proposals, we will contact all parties, we will advise them of this situation and we will ask them to submit a revised proposal. Once these are received, we will work with the party which has submitted the most acceptable proposal.If the process involves a cash sale of a property or company and the party which submitted the most acceptable proposal has met our client’s threshold value, that offer will be accepted. If this proposal does not meet our client’s threshold value, then we will advise that party that the offer is not quite what our client was expecting, and we will ask them to increase the offer. If that offer is not acceptable to our client, we will then move down to the party which submitted the next most acceptable proposal and we will then work with that party to attempt to meet our client’s threshold value.
CONFIDENTIALITY AGREEMENT
Parties wishing to receive access to the confidential information with detailed information relating to this opportunity should execute the Confidentiality Agreement and return one copy to Sayer Energy Advisors by courier, email (tpavic@sayeradvisors.com) or fax (403.266.4467).Included in the confidential information is the following: summary land information, the Deloitte Report, the Deloitte resource estimation reports, ARO information, most recent net operations summary and other relevant corporate, financial and technical information.
Download Confidentiality Agreement
To receive further information on the Company please contact Tom Pavic, Ben Rye or Sydney Birkett at 403.266.6133.