CALGARY, Nov. 23, 2017 /CNW/ – Ikkuma Resources Corp. (“Ikkuma” or the “Corporation”) (TSXV: IKM) is pleased to report its financial and operating results for the three and nine months ended September 30, 2017. Selected financial and operational information is set out below and should be read in conjunction with Ikkuma’s interim condensed financial statements and the related management’s discussion and analysis (“MD&A”) for the three and nine months ended September 30, 2017. Ikkuma’s condensed interim financial statements and MD&A are available for review at www.sedar.com and on the Corporation’s website at www.ikkumarescorp.com.
The Corporation’s operating netback in the third quarter of 2017 was eroded by natural gas prices and scheduled seasonal facilities maintenance that took place in the summer months. Quarterly results, however, are expected to be transcended in the future following the previously announced transformational Foothills Acquisition, which is expected to more than triple the size of the Corporation’s production base and to materially increase cash flow per share. The purchase price for the Foothills Acquisition was funded mostly by the sale of existing underutilized facilities for $20 million, see “Infrastructure Disposition” below.
ACQUISITION UPDATE
As previously announced, Ikkuma closed in escrow the acquisition of certain assets (the “Assets”) located in the Alberta Foothills and British Columbia Deep Basin (the “Foothills Acquisition”) on November 14, 2017. The original purchase price of $34.0 million was adjusted to $29.7 million after the exercise of rights of first refusals (“ROFRs”). Notwithstanding the exercise of the ROFRs, the Corporation retained the majority of the anticipated upside of the Foothills Acquisition while the 13% reduction in the adjusted purchase price results in only a 3% decrease in production (approximately 420 BOE/d net), leaving a more accretive asset.
Asset Summary (adjusted for exercise of ROFRs) |
||
Purchase Price (“PP”) |
($mm) |
$29.7 |
Production(1) |
(BOE/d) |
13,850 |
PDP Reserves(1,2) |
(mboe) |
35,096 |
PDP NPV10% (BT)(1,2) |
($mm) |
$168,206 |
2P Reserves(1,2) |
(mboe) |
41,664 |
2P NPV10% (BT) (1,2) |
($mm) |
$202,503 |
Total Land |
(acres) |
396,720 |
Acquisition Metrics (Unadjusted for $20mm infrastructure sale) |
|
PP/BOE/d(1) |
$2,144 |
PP/ Operating Netback(3) |
1.9x |
PP/PDP BOE(2) |
$0.85 |
PP/ PDP NPV10% (BT)(2) |
0.2x |
PP/2P BOE(2) |
$0.71 |
PP/acre |
$74.86 |
(1) Reflects current production. Approximately 4,400 BOE/d of production for the Assets was shut-in by the vendor of the Assets (the “Vendor”) in September 2017. These reserves were included in the PDP volumes at YE2016 (GLJ Report), but the recent production shut-in will require reassignment of PDP reserves at YE2017. |
(2) The Foothills Acquisition assets are based on the Deloitte Report and the GLJ Reports for YE2016. 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 forecast prices in respect of the BC and Other Alberta Assets. Reserves have been subtracted from the Deloitte Report with respect to exercise of ROFRs. |
(3) Operating Netback are non-IFRS measures. See “Non-IFRS Measures”. Operating netback for the Assets is an annualized estimate for the year ending December 31, 2017, based on recent lease operating statements provided by the Vendor using an estimated AECO natural gas price of $2.50/Mcf and assumes a 4% royalty rate, $13.29/BOE operating expenses (including transportation), and $10 million of sulphur revenue per year. Operating netback for the Assets does not include the potential 10-30% field operational cost savings, which are expected to commence upon closing of the Foothills Acquisition. |
The reserves data set forth above 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 December 31, 2016 (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 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 Central Alberta 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.
INFRASTRUCTURE DISPOSITION
In October 2017, the Corporation closed its previously announced disposition of 51% of its trunk line and associated facilities (the “Infrastructure Disposition”) located in the northern Alberta Foothills for cash consideration of $20.1 million, subject to customary adjustments. The Infrastructure Disposition has an effective date of September 1, 2017.
THIRD QUARTER HIGHLIGHTS
- Completed the non-brokered private placement of 15,091,221 flow-through shares at a price of $0.82 per/share for gross proceeds of $12.5 million (the “Offering”). The Offering consisted 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.
- Production for the quarter averaged 5,707 BOE/d reflecting the impact of planned and unplanned pipeline and facility outages. Production capacity is at approximately 6,500 to 7,100 BOE/d.
- Funds used in operations totaled $1.1 million in the quarter due to the decrease in natural gas pricing, transaction costs of $0.7 million and one-time personnel costs of $0.2 million. The Corporation is proactively managing pricing decisions to gain exposure to natural gas pricing outside of the volatile daily AECO market.
(Expressed in thousands of Canadian dollars except |
Three months ended |
Nine months ended September 30, |
|||||||
2017 |
2016 |
2017 |
2016 |
||||||
OPERATIONS |
|||||||||
Average daily production |
|||||||||
Natural gas (mcf/d) |
33,208 |
34,487 |
35,220 |
38,009 |
|||||
Light oil (bbls/d) |
52 |
– |
53 |
– |
|||||
NGL’s (bbl/d) |
120 |
118 |
121 |
91 |
|||||
Total equivalent (BOE/d) |
5,707 |
5,866 |
6,043 |
6,426 |
|||||
Average prices and operating netback |
|||||||||
Natural gas ($/mcf) |
$ |
1.47 |
$ |
2.34 |
$ |
2.36 |
$ |
1.85 |
|
Light oil ($/bbl) |
53.26 |
– |
57.21 |
– |
|||||
NGL ($/bbl) |
30.05 |
21.81 |
33.40 |
23.01 |
|||||
Revenue ($/BOE) |
9.75 |
14.21 |
15.02 |
11.44 |
|||||
Realized gain on commodity contracts ($/BOE) |
4.43 |
3.39 |
1.58 |
5.29 |
|||||
Royalties ($/BOE) |
(0.38) |
0.41 |
(0.33) |
(0.04) |
|||||
Operating expenses ($/BOE) |
(9.42) |
(9.01) |
(8.60) |
(8.46) |
|||||
Transportation costs ($/BOE) |
(1.67) |
(1.72) |
(1.91) |
(1.78) |
|||||
Operating netback (1) ($/BOE) |
$ |
2.71 |
$ |
7.28 |
$ |
5.76 |
$ |
6.45 |
|
FINANCIAL |
|||||||||
Oil and natural gas sales |
$ |
5,120 |
$ |
7,670 |
$ |
24,777 |
$ |
20,142 |
|
Funds flow from operations (1,2) |
$ |
(1,143) |
$ |
2,563 |
$ |
3,749 |
$ |
7,154 |
|
Per share – basic and diluted |
$ |
(0.01) |
$ |
0.03 |
$ |
0.04 |
$ |
0.08 |
|
Loss |
$ |
(3,394) |
$ |
(1,952) |
$ |
(1,828) |
$ |
(8,966) |
|
Per share – basic and diluted |
$ |
(0.03) |
$ |
(0.02) |
$ |
(0.02) |
$ |
(0.10) |
|
Capital expenditures |
$ |
10,050 |
$ |
4,111 |
$ |
21,207 |
$ |
7,920 |
|
Property acquisitions |
$ |
– |
$ |
27 |
$ |
– |
$ |
2,761 |
|
Debt (3) |
$ |
33,406 |
$ |
26,132 |
$ |
33,406 |
$ |
26,132 |
|
Shares outstanding (000) |
109,335 |
94,244 |
109,335 |
94,244 |
|||||
Weighted average shares outstanding |
|||||||||
Basic and diluted (000) |
97,959 |
87,407 |
95,496 |
87,407 |
(1) |
Funds flow from operations and operating netback are non-IFRS measures. See “Non- IFRS Measures”. |
(2) |
Funds flow from operations include transaction costs related to the Foothills Acquisition and non-recurring G&A expenses for personnel changes. |
(3) |
Debt is defined as the outstanding principal amounts of Ikkuma’s term loan and its bank loan, plus outstanding letters of credit, less unrestricted cash. |
OPERATIONS UPDATE
Two horizontal wells were completed in Q3 2017. Each well intersected high-quality light oil pools, with one exploration well expanding the fairway farther west than previously delineated. The wells were also used to collect reservoir data from the “Badheart formation”, a sandstone reservoir that has proven to be oil bearing. Initial Cardium reservoir pressure in one of the wells appears to have lessened following fracture stimulation, suggesting that stimulated reservoir rock is now in pressure communication with a low pressure conduit, thought to be a fault, impeding efforts to recover frac fluid. In the Corporation’s experience, this is an unusual complexity for foothills reservoirs, but fairly common in the deep basin. The Corporation is currently collecting pressure information to aid in the future production of these wells and is working on an alternative completion design for these wells, found in only 15% of the Corporation’s land base. In contrast, the first well drilled (8-31-63-11W6) into the mildly structured part of the Narraway Pool, and known as the “deep basin” play type, has been on production for more than a year. Production decline of this well has been significantly lower than expected (about 40%), typical of unstimulated wells with significant matrix contribution. The intersection of the deep basin play type, in mildly structured parts of Narraway subsurface, is generally known to occur in over 70% of the Corporation’s land base. Over these lands, the Corporation expects that oil production can be improved significantly with a stimulation redesign, similar to many deep basin plays. The last play type, “folded Cardium”, is expected to be tested in 2018.
ABOUT IKKUMA
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.