Ikkuma Resources Corp. announces transformational Foothills acquisition tripling production to 20,800 BOE/d in conjunction with a $20 million infrastructure sale and a $10 million flow-through equity financing
CALGARY, Aug. 15, 2017 /CNW/ - Ikkuma Resources Corp. ("Ikkuma" or the "Corporation") (TSX VENTURE: IKM) is pleased to announce that it has entered into a purchase and sale agreement (the "Purchase and Sale Agreement") to acquire (the "Acquisition") assets located in the Alberta Foothills as well as in the British Columbia Deep Basin (the "Assets"), effective as of July 1, 2017, for cash consideration of $34,000,000, subject to customary adjustments. The Acquisition is subject to standard industry closing conditions, approval by the TSX Venture Exchange ("TSXV") and the concurrent sale of certain midstream assets by the vendor of the Assets (the "Vendor") to a third party purchaser. The Acquisition is expected to close on or about November 1, 2017.
In conjunction with the Acquisition, the Corporation has entered into a separate purchase and sale agreement to sell 51% of its trunk line and associated facilities (the "Infrastructure Disposition") in its existing northern Alberta Foothills properties to an undisclosed buyer, for a total consideration of $20,000,000, payable in cash. The Infrastructure Disposition has an effective date of September 1, 2017 and is expected to close September 15, 2017, but in any event, prior to the closing of the Acquisition.
The Acquisition will be funded by the proceeds from the Infrastructure Disposition and available cash balances. The Corporation's lenders have provided a $15 million estimate of lending value for the acquired Assets resulting in an expected pro forma unutilized syndicated credit facility of $40 million.
ACQUISITION
The Acquisition is transformational for Ikkuma and will result in a stronger oil and natural gas company focused on the Western Canadian Foothills with a pro forma production base of approximately 20,800 BOE/d (98% natural gas), with significant growth potential. The Acquisition is highly accretive, has a low decline rate, provides increased cash flow, and allows the Corporation to grow within cash flow while remaining focused on developing its Narraway light oil pool.
The Assets are primarily located within the Central Alberta Foothills, northwest of Rocky Mountain House. Other minor assets included in the Acquisition are located in the British Columbia Deep Basin, approximately 100 km southeast of Fort Nelson, on the eastern edge of the Peace River Arch.
The Vendor maintained these properties in a safe and effective manner, a credit to existing field personnel, and Ikkuma is very pleased with the due diligence reviews conducted to date.
Acquisition Highlights (also see tables):
- Pro forma diluted cash flow per share increases 130%.
- Significant growth potential as the Assets provide an extensive, risk-balanced, low cost oil and gas prospect portfolio that nearly doubles the Corporation's present drilling inventory.
- 33.6 MMBOE of proved developed producing ("PDP") reserve additions (246% increase).
- Production additions (220% increase) of 14,300 BOE/d (60% operated), from low decline assets providing sustainable cash flow to exploit the Narraway light oil and other discovered resources.
- Pro forma leverage improves approximately 32%.
- Pro forma Licensee Liability Rating ("LLR") rating of 7.62 (65% improvement).
- The Central Alberta Foothills Assets, representing most of the production included in the Acquisition, have an annual decline rate of 8% resulting in a pro forma annual decline of approximately 11%.
- Significant field operational cost savings have been identified and are expected to be 10-30%.
- Ikkuma's technical team has significant experience with the Assets including the Stolberg Oil Pool.
- The Assets include additional lands within Ikkuma's northern Alberta Foothills light oil pool located at Narraway.
- 398,037 of net developed and undeveloped acres added.
- Adds significant underutilized infrastructure (working interest in 1,327 km of pipelines, 5 major facilities and 10 minor facilities), which can be utilized to exploit bypassed oil and gas zones.
- Majority of the production will flow to a midstream operated plant. Ikkuma has negotiated favourable fees and agreed conditionally to dedicate reserves for a 10 year period.
- The Assets include two additional light oil pools, Cordel and Brown Creek, with infill drilling and secondary oil recovery opportunities.
- The Assets also include 5,100 kilometre lines of 2D and 143 square kilometres of 3D seismic data.
Asset Summary
| Purchase Price(1) |
$ |
34,000,000 |
||
| Production at closing (BOE/d)(2) |
14,300 |
|||
| PDP Reserves (MBOE)(3) |
33,579 |
|||
| 2P Reserves (MBOE)(3) |
43,886 |
|||
| PDP Reserves @ 10% ($MM)(4) |
$ |
126.8 |
||
| (1) |
Effective date of July 1, 2017, subject to closing adjustments. |
|||
| (2) |
Current production is 18,700 BOE/d. 4,400 BOE/d of production is expected to be shut-in by the Vendor |
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| (3) |
Gross reserves are the total company working interest in the Assets (operating and non-operating) |
|||
| (4) |
Before tax net present value based on a 10% discount rate and Deloitte's forecast prices as at |
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Metrics (net of undeveloped land and seismic)(1)
| $/PDP BOE |
$ |
1.01 |
||
| $/PDP Mcf |
$ |
0.17 |
||
| $/BOE/d |
$ |
2,369 |
||
| $/Acreage Acquired |
$ |
85.42 |
||
| Purchase price/Operating Netback(1)(2) |
2.2 X |
|||
| (1) |
Based on a purchase price of $34 million and current production of 14,300 BOE/d. The purchase price is |
|||
| (2) |
Operating netback is a non-IFRS measure. See "Non-IFRS Measures" below. |
|||
| (3) |
Operating netback for the Assets is an annualized estimate based on recent lease operating statements |
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Pro Forma Information
| Ikkuma(1) |
Acquisition |
Equity |
Pro Forma |
Increase - |
||||||
| Outstanding shares (MM) |
- Basic |
94,300 |
12,195 |
106,495 |
13% |
|||||
| - Diluted |
111,450 |
12,195 |
123,645 |
11% |
||||||
| Cash flow per share |
- Basic |
$ |
0.09 |
$ |
0.22 |
130% |
||||
| - Diluted |
$ |
0.08 |
$ |
0.19 |
134% |
|||||
| PDP Reserves @ NPV10% ($MM) (3)(4) |
$ |
103.6 |
$ |
126.8 |
$ |
230.4 |
122% |
|||
| PDP Reserves (MMBOE)(3)(5) |
13.6 |
33.6 |
47.2 |
246% |
||||||
| Production (BOE/d)(6) |
6,500 |
14,300 |
20,800 |
220% |
||||||
| Operating Netback ($MM) (7)(8) |
$ |
16.09 |
$ |
15.71 |
$ |
31.80 |
98% |
|||
| Adjusted Debt/ EBITDA on closing (7) |
3.5 X |
2.4 X |
-32% |
|||||||
| Production Base Decline |
16% |
8% |
11% |
-28% |
||||||
| LLR Rating(9) |
4.63 |
10.6 |
7.62 |
65% |
||||||
| Net Developed Land (acres) |
56,883 |
151,767 |
208,650 |
267% |
||||||
| Net Undeveloped Land (acres) |
177,037 |
246,270 |
423,307 |
139% |
||||||
| Total Land (acres) |
233,920 |
398,037 |
631,957 |
170% |
||||||
| (1) |
The reserves information contained herein in respect of Ikkuma's reserves are based upon an independent report prepared by Sproule Associates Limited ("Sproule") dated March 15, 2017 and effective as of December 31, 2016 (the "Sproule Report") based on the price forecast prepared by Sproule for December 31, 2016 which is the average of the pricing, inflation and exchange rate forecasts of three independent reserve evaluators, namely, Sproule, GLJ and McDaniel's & Associates Consultants Ltd. |
||||||||
| (2) |
See "Equity Financing" below. |
||||||||
| (3) |
Only developed reserves were evaluated for the Acquisition. |
||||||||
| (4) |
Before tax net present value based on a 10% discount rate and the Deloitte Price Forecast in respect of the Central Alberta Foothills Assets and the GLJ Price Forecast in respect of the BC and Other Alberta Assets. Estimated values of future net revenues do not represent the fair market value of the reserves. See "Acquisition Reserves" below. |
||||||||
| (5) |
Gross reserves are the total company working interest in the Assets (operating and non-operating) before deduction of royalties and without including any royalty interest receivable on the Assets. Gross reserve estimates are based on the Deloitte Report (as at June 30, 2017 in respect of the Central Alberta Foothills Assets) and the GLJ Reports (as at December 31, 2016 in respect of the BC and Other Alberta Assets). See "Acquisition Reserves" below. |
||||||||
| (6) |
Based on current production. Excludes 4,400 BOE/d of production that is expected to be shut-in by the Vendor in September 2017. |
||||||||
| (7) |
Debt, EBITDA and Operating Netback are non-IFRS measures. See "Non-IFRS Measures" below. |
||||||||
| (8) |
Operating netback is an annualized estimate based historical lease operating statements and using an estimated natural gas price of $2.50/Mcf AECO. |
||||||||
| (9) |
LLR (Licensee Liability Rating, AER Directive 006). |
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ACQUISITION RESERVES
The reserves data set forth below are based on an independent reserves evaluation of certain oil and gas assets in the Foothills area of Alberta (the "Central Alberta Foothills Assets"), effective June 30, 2017 (the "Deloitte Report") prepared by Deloitte LLP ("Deloitte") and independent reserves assessments on the Assets other than the Central Alberta Foothills Assets (the "BC and Other Alberta Assets") effective December 31, 2016 (the "GLJ Reports") prepared by GLJ Petroleum Consultants Ltd. ("GLJ") for the Vendor. The Deloitte Report is based on certain factual data supplied by the Vendor. Deloitte reviewed the land data provided by the Vendor as it related to any producing wells but accepted the working interest presented in the well lists as factual with no further review for the non-producing wells.
The GLJ Reports, as delivered by the Vendor, contain details regarding crude oil, natural gas liquids and natural gas reserves and the net present values before income tax of future net revenue using forecast prices and costs as set out in the GLJ Reports. The GLJ Reports have been prepared in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI-51-101"). The GLJ Reports are based on the GLJ Price Forecast, which is available on GLJ's website. The Deloitte Report was also prepared in accordance with NI 51-101; however, Deloitte was instructed to evaluate proved and probable developed reserves only. No effort was made by Deloitte to assess proved developed non-producing or undeveloped reserves. As such, only proved and probable developed reserves are provided for the Foothills Assets. The Deloitte Report is based on the Deloitte Price Forecast, which is available on Deloitte's website. The information regarding the Assets set forth herein is in respect of all of the Assets. All of the reserves associated with the Assets are in Canada and, specifically, in Alberta and British Columbia.
In certain of the tables set forth below, the columns may not add due to rounding. In addition, the net present values in the tables set forth below do not include capital gas cost allowance as these are determined on a corporate basis.
All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. 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. The recovery and reserve estimates of crude oil, natural gas liquids 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 natural gas liquids reserves may be greater or less than the estimates provided herein. Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any royalty interests) unless noted otherwise. See "Forward-Looking Statements and Information and Cautionary Statements" below for a statement of principal assumptions and risks that may apply.
| SUMMARY OF OIL AND GAS RESERVES |
|||||||||||||||||
| as of June 30, 2017 (Deloitte)(3) |
|||||||||||||||||
| FORECAST PRICES AND COSTS |
|||||||||||||||||
| CENTRAL ALBERTA FOOTHILLS ASSETS |
|||||||||||||||||
| Light and Medium |
Conventional |
Liquids/NGLs(6) |
Total(5)(6) |
||||||||||||||
| Reserves Category |
Gross(1) |
Net(2) |
Gross(1) |
Net(2) |
Gross(1) |
Net(2) |
Gross(1) |
Net(2) |
|||||||||
| PROVED |
|||||||||||||||||
| Developed Producing |
351.3 |
274.7 |
170.6 |
153.2 |
184.5 |
110.2 |
28,972 |
25,925 |
|||||||||
| Developed |
- |
- |
- |
- |
- |
- |
- |
- |
|||||||||
| Undeveloped |
- |
- |
- |
- |
- |
- |
- |
- |
|||||||||
| TOTAL PROVED |
351.3 |
274.7 |
170.6 |
153.2 |
184.5 |
110.2 |
28,972 |
25,925 |
|||||||||
| TOTAL PROBABLE |
113.3 |
83.0 |
52.9 |
45.2 |
54.8 |
32.7 |
8,976 |
7,646 |
|||||||||
| TOTAL PROVED |
464.6 |
357.7 |
223.5 |
198.4 |
239.3 |
142.9 |
37,948 |
33,571 |
|||||||||
| (1) |
Reserves have been presented on a "gross" basis which is defined as the Company's working interest share in the reserves in the Central Alberta Foothills Assets (operating and non-operating) before deduction of royalties and without including any royalty interest receivable on the Central Alberta Foothills Assets. |
| (2) |
Net reserves are defined as the gross working interest reserves in the Central Alberta Foothills Assets (operating and non-operating) less all Crown, freehold, and overriding royalties and interests owned by others. |
| (3) |
Based on the Deloitte Price Forecast. |
| (4) |
Includes solution gas. |
| (5) |
Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. |
| (6) |
Columns may not add due to rounding. |
| SUMMARY OF OIL AND GAS RESERVES |
|||||||||||||||||
| as of December 31, 2016 (GLJ)(2) |
|||||||||||||||||
| FORECAST PRICES AND COSTS |
|||||||||||||||||
| BC AND OTHER ALBERTA ASSETS |
|||||||||||||||||
| Light and Medium |
Conventional |
Liquids/NGLs(6) |
Total(5)(6) |
||||||||||||||
| Reserves Category |
Gross(1) (Mbbl) |
Net(2) |
Gross(1) (MMcf) |
Net(2) (MMcf) |
Gross(1) (Mbbl) |
Net(2) (Mbbl) |
Gross(1) (MBOE) |
Net(2) (MBOE) |
|||||||||
| PROVED |
|||||||||||||||||
| Developed Producing |
- |
- |
26,152 |
23,659 |
249 |
175 |
4,607 |
4,117 |
|||||||||
| Developed |
- |
- |
- |
- |
- |
- |
- |
- |
|||||||||
| Undeveloped |
- |
- |
- |
- |
- |
- |
- |
- |
|||||||||
| TOTAL PROVED |
- |
- |
26,152 |
23,659 |
249 |
175 |
4,607 |
4,117 |
|||||||||
| TOTAL PROBABLE |
- |
- |
7,583 |
6,864 |
66 |
50 |
1,331 |
1,195 |
|||||||||
| TOTAL PROVED |
- |
- |
33,735 |
30,523 |
316 |
225 |
5,938 |
5,312 |
|||||||||
| (1) |
Reserves have been presented on a "gross" basis which is defined as the Company's working interest share in the reserves in the BC and Other Alberta Assets (operating and non-operating) before deduction of royalties and without including any royalty interest receivable on the BC and Other Alberta Assets. |
| (2) |
Net reserves are defined as the gross working interest reserves in the BC and Other Alberta Assets (operating and non-operating) less all Crown, freehold, and overriding royalties and interests owned by others. |
| (3) |
Based on the GLJ Price Forecast. |
| (4) |
Includes solution gas. |
| (5) |
Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. |
| (6) |
Columns may not add due to rounding. |
| SUMMARY OF OIL AND GAS RESERVES |
|||||||||||||||||
| as of December 31, 2016 (GLJ); June 30, 2017 (Deloitte)(3) |
|||||||||||||||||
| FORECAST PRICES AND COSTS |
|||||||||||||||||
| ALL PROPERTIES |
|||||||||||||||||
| Light and Medium |
Conventional |
Liquids/NGLs (6) |
Total(5)(6) |
||||||||||||||
| Reserves Category |
Gross(1) (Mbbl) |
Net(2) (Mbbl) |
Gross(1) (Bcf) |
Net(2) (Bcf) |
Gross(1) (Mbbl) |
Net(2) (Mbbl) |
Gross(1) (MBOE) |
Net(2) (MBOE) |
|||||||||
| PROVED |
|||||||||||||||||
| Developed Producing |
351 |
275 |
197 |
177 |
434 |
285 |
33,579 |
30,042 |
|||||||||
| Developed |
- |
- |
- |
- |
- |
- |
- |
- |
|||||||||
| Undeveloped |
- |
- |
- |
- |
- |
- |
- |
- |
|||||||||
| TOTAL PROVED |
351 |
275 |
197 |
177 |
434 |
285 |
33,579 |
30,042 |
|||||||||
| TOTAL PROBABLE |
113 |
83 |
61 |
52 |
121 |
83 |
10,307 |
8,841 |
|||||||||
| TOTAL PROVED PLUS PROBABLE |
465 |
358 |
257 |
229 |
555 |
368 |
43,886 |
38,883 |
|||||||||
| (1) |
Reserves have been presented on a "gross" basis which is defined as the Company's working interest share in the reserves in the Assets (operating and non-operating) before deduction of royalties and without including any royalty interest receivable on the Assets. |
| (2) |
Net reserves are defined as the gross working interest reserves in the Assets (operating and non-operating) less all Crown, freehold, and overriding royalties and interests owned by others. |
| (3) |
In respect of the BC and Other Alberta Assets, based on the GLJ Reports using the GLJ Price Forecast and in respect of the Central Alberta Foothills Assets, based on the Deloitte Report using the Deloitte Price Forecast. |
| (4) |
Includes solution gas. |
| (5) |
Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. |
| (6) |
Columns may not add due to rounding. |
| SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE |
|||||||||||||
| as of December 31, 2016 (GLJ)(1) |
|||||||||||||
| BC AND OTHER ALBERTA ASSETS |
|||||||||||||
| FORECAST PRICES AND COSTS |
|||||||||||||
| Before Income Taxes |
Unit Value Before |
||||||||||||
| Reserves Category |
0 |
5 |
10 |
15 |
20 |
||||||||
| PROVED |
|||||||||||||
| Developed Producing |
42,856 |
33,431 |
27,406 |
23,286 |
20,316 |
6.66 |
|||||||
| Developed |
- |
- |
- |
- |
- |
- |
|||||||
| Undeveloped |
- |
- |
- |
- |
- |
- |
|||||||
| TOTAL PROVED |
42,856 |
33,431 |
27,406 |
23,286 |
20,316 |
6.66 |
|||||||
| TOTAL PROBABLE |
13,659 |
7,892 |
5,097 |
3,572 |
2,660 |
4.24 |
|||||||
| TOTAL PROVED PLUS PROBABLE |
56,515 |
41,323 |
32,503 |
26,858 |
22,976 |
6.11 |
|||||||
| (1) |
Based on the GLJ Price Forecast. |
| SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE |
|||||||||||||
| as of June 30, 2017 (Deloitte)(1) |
|||||||||||||
| CENTRAL ALBERTA FOOTHILLS ASSETS |
|||||||||||||
| FORECAST PRICES AND COSTS |
|||||||||||||
| Before Income Taxes |
Unit Value Before |
||||||||||||
| Reserves Category |
0 (MM$) |
5 (MM$) |
10 (MM$) |
15 (MM$) |
20 (MM$) |
||||||||
| PROVED |
|||||||||||||
| Developed Producing |
180 |
129 |
99 |
80 |
67 |
3.83 |
|||||||
| Developed |
- |
- |
- |
- |
- |
- |
|||||||
| Undeveloped |
- |
- |
- |
- |
- |
- |
|||||||
| TOTAL PROVED |
180 |
129 |
99 |
80 |
67 |
3.83 |
|||||||
| TOTAL PROBABLE |
97 |
50 |
29 |
19 |
13 |
3.81 |
|||||||
| TOTAL PROVED PLUS PROBABLE |
277 |
179 |
129 |
99 |
81 |
3.83 |
|||||||
| (1) |
Based on the Deloitte Price Forecast. |
| SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE |
|||||||||||||
| as of December 31, 2016 (GLJ); June 30, 2017 (Deloitte)(1) |
|||||||||||||
| ALL ACQUISITION PROPERTIES |
|||||||||||||
| FORECAST PRICES AND COSTS |
|||||||||||||
| Before Income Taxes |
Unit Value Before |
||||||||||||
| Reserves Category |
0 |
5 |
10 |
15 |
20 |
||||||||
| PROVED |
|||||||||||||
| Developed Producing |
222.9 |
162.7 |
126.8 |
103.6 |
87.6 |
4.22 |
|||||||
| Developed |
- |
- |
- |
- |
- |
- |
|||||||
| TOTAL PROVED |
222.9 |
162.7 |
126.8 |
103.6 |
87.6 |
4.22 |
|||||||
| TOTAL PROBABLE |
110.3 |
57.4 |
34.2 |
22.6 |
16.1 |
3.86 |
|||||||
| TOTAL PROVED PLUS PROBABLE |
333.1 |
220.1 |
161.0 |
126.2 |
103.7 |
4.14 |
|||||||
| (1) |
In respect of the BC and Other Alberta Assets, based on the GLJ Reports using the GLJ Price Forecast and in respect of the Central Alberta Foothills Assets, based on the Deloitte Report using the Deloitte Price Forecast. |
EQUITY FINANCING
The Corporation is also pleased to announce that it has commenced a non-brokered private placement of 12,195,122 flow-through shares at a price of $0.82 per/share for gross proceeds of $10 million (the "Offering"). The Offering will consist of common shares issued on a "flow-through" basis in respect of Canadian exploration expenses under the Income Tax Act (Canada) (the "Flow-Through Shares"). The gross proceeds from the Offering will be used by Ikkuma to incur eligible Canadian exploration expenses ("Qualifying Expenditures") prior to December 31, 2018. Ikkuma will renounce the Qualifying Expenditures to subscribers of the Flow-Through Shares for the fiscal year ended December 31, 2017.
The completion of the Offering is subject to a number of conditions, including, without limitation, receipt of all regulatory approvals, including approval of the TSXV. Closing of the Offering is expected to occur on or about September 1, 2017. The Flow-through Shares issued pursuant to the Offering will be subject to a statutory hold period of four months plus one day from the closing of the Offering, in accordance with applicable securities legislation.
Advisory Services
Desjardins Capital Markets (and its partner Deloitte)., GMP FirstEnergy and TD Securities Inc. acted as financial advisors to Ikkuma with respect to the Acquisition.
About Ikkuma Resources Corp.
Ikkuma Resources Corp. is a diversified junior public oil and gas company listed on the TSXV under the symbol "IKM", with holdings in both conventional and unconventional projects in Western Canada. The technical team has worked together for over a decade in the Foothills Region of Western Canada, through two successful, publicly traded companies. The unique skills and repeat success at exploiting a complex, potentially prolific play type are fundamental ingredients for a successful growth-oriented company in Western Canada. Corporate information can be found at: www.ikkumarescorp.com.
Forward-Looking Statements and Information and Cautionary Statements
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", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward‑looking statements or information. In particular the press release contains forward-looking statements and information relating to the completion of the Acquisition and the timing thereof; the completion of the Infrastructure Disposition and the timing thereof; the completion of the Offering and the timing thereof; the use of proceeds of the Offering; the funding of the purchase price of the Assets; the Corporation's expectation that the borrowing base under its credit facilities will be increased following the completion of the Acquisition; the anticipated benefits to be obtained as a result of the Acquisition; the performance characteristics of the Assets and the anticipated potential of the Asset; the anticipated shut-in of 4,400 BOE/d by the Vendor in September 2017 (exclusive of the 14,351 production included among the Assets); and the impact of the Acquisition on the Corporation's production, reserves, inventory and financial condition. Although Ikkuma believes that the expectations and assumptions on which the forward‑looking statements and information are based are reasonable, undue reliance should not be placed on the forward‑looking statements and information because Ikkuma cannot give any assurance that they will prove to be correct. Since forward‑looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. The forward-looking statements and information is based on certain key expectations and assumptions made by management, including expectations and assumptions concerning: the satisfaction of all conditions to the closing of the Acquisition, Infrastructure Disposition and Offering and on the time frames contemplated; the Corporation's ability to develop the Assets and obtain the benefits thereof; the ability to efficiently integrate the Assets; prevailing and future commodity prices, exchange rate, interest rates, inflation rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; reserves volumes; anticipated timing and results of capital expenditures in carrying out planned activities; the state of the economy and the exploration and production business; the regulatory framework regarding royalties, taxes and environmental laws; results of operations; performance; business prospectus and opportunities. Actual results could differ materially from those currently anticipated due to a number of factors and risk. These include but are not limited to: failure to complete the Acquisition in all material respects in accordance with the Purchase and Sale Agreement; failure to complete the Infrastructure Disposition in all material respects in accordance with its related purchase and sale agreement; failure to obtain in a timely manner, regulatory, stock exchange and other required approvals in connection with the Acquisition, the Infrastructure Disposition and the Offering; the failure to realize the anticipated benefits of the Acquisition; unforeseen difficulties in integrating the Assets in the Corporation's operations, 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. The Corporation cautions that the foregoing list of risks and uncertainties is not exhaustive. These risks and other risks are set out in more detail in Ikkuma's Annual Information Form for the year ended December 31, 2016. The recovery and reserve estimates contained in this press release are estimates only and there is no guarantee that the estimated reserves will be recovered.
In addition, the reader is cautioned that historical results are not necessarily indicative of future performance. The forward-looking statements and information contained in this press release are made as of the date hereof and Ikkuma undertakes no obligation to update publicly or revise any forward‑looking statement or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Certain information set out herein may be considered as "financial outlook" or "future oriented financial information" within the meaning of applicable securities laws. Financial outlook or future oriented financial information in this press release was made as of the date of this press release. The purpose of this financial outlook is to provide readers with disclosure regarding Ikkuma's reasonable expectations as to the anticipated results of its proposed business activities for the periods indicated. Readers are cautioned that the financial outlook may not be appropriate for other purposes.
Non-IFRS Measures
This press release provides certain financial measures that do not have a standardized meaning prescribed by IFRS. These non-IFRS financial measures may not be comparable to similar measures presented by other issuers. Operating netback, EBITDA and Adjusted Debt are not recognized measures under IFRS. Management uses certain industry benchmarks such as operating netback to analyze financial and operating performance. This benchmark as presented does not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. Operating netback equals total petroleum and natural gas sales, realized gains and losses on commodity contracts, less royalties, operating costs and transportation costs calculated on a BOE basis. Management considers operating netback an important measure to evaluate its operational performance as it demonstrates its field level profitability relative to current commodity prices. EBITDA is comprised of earnings before interest, taxes depreciation and amortization and adjustments for other non-cash items. Adjusted Debt is the aggregate of the principal amount of the Term Loan, drawn amounts on credit facilities, and outstanding letters of credit with the bank less unrestricted cash. Reconciliations of operating netback and debt to the most directly comparable measures specified under IFRS are contained in the Corporation's management discussion and analysis, copies of which are available on SEDAR.
Oil and Gas Advisory
Certain pro forma reserve information has been presented herein. The estimates of the Corporation's reserves and the estimates of the reserves associated with the Central Alberta Foothills Assets and the BC and Other Alberta Assets were estimated at different dates and have been based on different assumptions in respect of commodity pricing among other metrics. As a result, the presentation of the Corporation's reserves on a consolidated pro forma basis or the presentation of the Assets, as a whole, would not reflect the actual combined estimated of the Corporation's reserves and the Assets, or the Assets, as a whole, at December 31, 2016 and should not necessarily be viewed as predictive of the Corporation's reserves and future production once the Acquisition is completed.
In this press release, the abbreviation BOE means a barrel of oil equivalent derived by converting gas to oil in the ratio of 6 Mcf of gas to 1 bbl of oil (6 Mcf:1 bbl). BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf:1 bbl, utilizing a conversion ratio on a 6 Mcf of gas to 1 bbl of oil basis may be misleading as an indication of value.
Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.
SOURCE Ikkuma Resources Corp.
Tim de Freitas, President & CEO; Carrie Yuill, VP Finance & CFO; Ikkuma Resources Corp., 2700, 605-5th Avenue S.W. Calgary, AB, T2P 3H5, Phone: 403-261-5900, Fax: 403-261-5902.
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