08:33:06 EDT Fri 29 Mar 2024
Enter Symbol
or Name
USA
CA



Ikkuma Resources Corp
Symbol IKM
Shares Issued 109,334,987
Close 2018-04-03 C$ 0.30
Market Cap C$ 32,800,496
Recent Sedar Documents

Ikkuma increases year-end NI 51-101 PDP reserves

2018-04-03 07:22 ET - News Release

Mr. Tim de Freitas reports

IKKUMA RESOURCES ANNOUNCES A 316 PERCENT INCREASE IN PROVED DEVELOPED PRODUCING RESERVES, 2017 OPERATING RESULTS AND OPERATIONS UPDATE

Ikkuma Resources Corp. has released its 2017 year-end reserves and other news.

2017 reserve highlights:

  • Increased proven developed producing (PDP) reserves by 316 per cent to 56.8 million barrels of oil equivalent (mmboe) at Dec. 31, 2017, from 13.6 mmboe at Dec. 31, 2016;
  • Increased PDP net present value to $301-million ($2.75 per share) at year-end 2017 at a 10-per-cent discount rate using a consensus price deck from four independent qualified reserves evaluators from $104-million ($1.10 per share) at year-end 2016;
  • Increased proven developed (PD) reserves by 366 per cent to 74.0 mmboe, proven (1P) reserves by 300 per cent to 79.6 mmboe and proven plus probable (2P) reserves by 287 per cent to 106.6 mmboe at Dec. 31, 2017;
  • Increased PD net present value to $361-million (2016 -- $118-million), 1P net present value to $376-million (2016 -- $132-million) and 2P net present value to $488-million (2016 -- $190-million);
  • Generated a finding, development and acquisition (FD&A) cost of $1.50/barrel of oil equivalent (boe) on 2P reserve additions and $1.99/boe on 1P reserve additions;
  • Achieved a recycle ratio of 3.4 times on a 2P basis and 2.5 times on a 1P basis, including changes in future development capital (FDC) and assumed decommissioning obligations on acquisitions;
  • Established conservative PDP reserve position that represents 53 per cent of 2P reserves with an FDC requirement of $67-million on a 1P basis and $75-million on a 2P basis;
  • Reduced annual production decline rates on PDP reserves from 16 per cent to 12 per cent.

2017 operating results and operations update:

  • Increased fourth quarter 2017 average daily production by 23 per cent to 7,324 barrels of oil equivalent per day compared with fourth quarter 2016 average daily production of 5,967 boe/d;
  • Current average daily production in excess of 19,000 boe/d based on field estimates, after closing the previously announced acquisition of assets located in the Alberta Foothills as well as in the British Columbia Deep basin on Dec. 21, 2017;
  • Field optimization initiatives with minimal capital spending since closing the Foothills acquisition have provided both production increases of more than 8 per cent and an operating cost decrease per boe of approximately 10 per cent;
  • The Foothills acquisition expanded the existing crude oil development drilling inventory to more than 200 low-risk drilling locations;
  • Infrastructure working interest replacement value estimated at $600-million that includes approximately 500 kilometres of gas transmission lines;
  • Undeveloped acreage represents 66 per cent of the corporation's 635,000 net acres of land;
  • Operating initiatives for the remainder of 2018 will focus on continuing production and operating cost optimization, pursuing a diversified marketing program in addition to the planned sale of non-core assets;
  • Average 2018 daily production is expected to be in the range of 17,500 boe/d to 18,500 boe/d.

2017 summary of reserves

The detailed reserves data set forth are based on an independent reserves assessment and evaluation prepared by Deloitte LLP with an effective date of Dec. 31, 2017, contained in a report dated April 2, 2018.

                                                                              2017 YE and
                                  2017 YE (1)         2016 YE (2)      2016 YE comparison
Reserves category                   NPV10%               NPV10%      Increase in reserves   
                             (Mboe)       ($M)    (Mboe)       ($M)                   (%)
Proven
Developed producing          56,809   $301,180    13,642   $103,551                  316%
Total developed              73,968   $360,568    15,881   $117,998                  366%
Total proven                 79,634   $375,517    19,931   $131,759                  300%
Total proven plus probable  106,637   $488,162    27,539   $190,031                  287%
                
Notes
(1) Deloitte report effective as of Dec. 31, 2017.
(2) Report prepared by Sproule Associates Ltd., dated March 15, 
2017, effective as of Dec. 31, 2016.
 

Proven developed producing reserves

During 2017, Ikkuma increased proven developed producing reserves by 316 per cent to 56.8 mmboe which represents 53 per cent of proven and probable reserves. At a 10-per-cent discount rate, using a consensus price deck from four independent qualified reserves evaluators, the net present value (NPV 10) of proven developed producing reserves increased by 191 per cent to $301-million, or $2.75 per share, at year-end 2017 from $104-million, or $1.10 per share at year-end 2016. Deloitte has estimated the annual production decline on proven developed producing reserves to be 12 per cent as at Dec. 31, 2017, compared with a previous annual production decline rate estimate of 16 per cent as at Dec. 31, 2016.

Proven developed reserves

During 2017, Ikkuma increased proven developed reserves by 366 per cent to 74.0 mmboe which represents 93 per cent of proven reserves. The NPV10 (net present value at a 10-per-cent discount) of proven developed reserves more than tripled to $361-million, or $3.30 per share, at year-end 2017 compared with $118-million at year-end 2016.

Proven reserves

During 2017, Ikkuma increased proven reserves by 300 per cent to 79.6 mmboe (74.0 mmboe of proven developed reserves and 5.6 mmboe of proven undeveloped reserves) and the NPV10 of proven reserves increased by 185 per cent to $376-million, or $3.43 per share. Proven reserve additions and revisions replaced 2017 average daily production by more than 26 times.

Proven and probable reserves

During 2017, Ikkuma increased proven and probable reserves by 287 per cent to 106.6 mmboe and the NPV10 of proven and probable reserves increased by 157 per cent to $488-million, or $4.46 per share.

Finding, development and acquisition costs, and recycle ratios

In 2017, Ikkuma generated an FD&A cost of $1.50/boe on proven and probable reserve additions and $1.99/boe on proven reserve additions. The FD&A calculations are based on exploration and development capital expenditures, acquisition costs, proceeds from dispositions within a reserve category, including changes in future development capital and decommissioning obligations assumed on the Foothills acquisition divided by reserve additions by reserve category.

The future development capital requirement as at Dec. 31, 2017, was $75-million on a proven and probable reserve basis and $67-million on a proven reserve basis as at Dec. 31, 2016. The decommissioning obligations assumed on the Foothills acquisition was estimated at $52-million as at Dec. 31, 2017.

In 2017, Ikkuma achieved a recycle ratio of 3.4 times on a proven and probable basis and 2.5 times on a proven basis on an estimated operating netback of $5.07/boe (unaudited).

Corporate reserves

The detailed reserves data set forth are based on the Deloitte report. The presentation summarizes the corporation's crude oil, natural gas liquids and natural gas reserves and the net present values before income tax of future net revenue for the corporation's reserves using forecast prices and costs as set out in the Deloitte report. The Deloitte report has 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. The reserves evaluation was based on the consensus forecast escalated pricing and foreign exchange rates at Dec. 31, 2017, as outlined in the table entitled price forecast. This consensus price forecast is the average of the escalated price forecasts of four independent reserve evaluators, namely Deloitte, GLJ Petroleum Consultants Ltd., McDaniel & Associates Consultants Ltd. and Sproule.

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 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 recovery and reserve estimates of Ikkuma's crude oil, natural gas liquids and natural gas reserves provided 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. In addition to the detailed information disclosed in this press release, more detailed information will be included in the corporation's annual information form (AIF) which will be filed on the corporation's profile at SEDAR on or before April 30, 2018.

The preparation and audit of Ikkuma's 2017 annual financial statements are not yet complete, and accordingly, all financial amounts referred to in this press release are unaudited and represent management's estimates. Readers are advised that these financial estimates may be subject to change. Year-end financial statements for 2017 are anticipated to be released on or about April 25, 2018.

                                           CORPORATE RESERVES
  
Reserves category (1)       Light and medium  Natural gas          Non-associated      Barrels of
                                   crude oil      liquids  Sulphur        gas (2)  equivalent (3)
                                      (mbbl)       (mbbl)    (mlt)         (mmcf)          (mbbl)
Proven
Proven developed
producing (PDP)                          606        1,051    1,333        330,908          56,809
Proven developed
Non-producing (PDNP)                      86           31       78        102,258          17,160
Proven developed (PD)                    692        1,082    1,411        433,166          73,968
Proven undeveloped
(PUD)                                    326           22       37         31,902           5,666
Total proven (1P)                      1,018        1,104    1,448        465,069          79,634
Probable                                 654          392      408        155,745          27,003
Total proven plus
probable (2P)                          1,672        1,496    1,856        620,814         106,637
                   
Notes
(1) Reserves have been presented on a gross basis which is defined as Ikkuma's working 
interest (operating and non-operating) share before deduction of royalties and without including 
any royalty interest of the corporation.
(2) Includes solution gas.
(3) Oil equivalent amounts have been calculated using a conversion rate of 6,000 cubic
feet of natural gas to one barrel of oil.
(4) Columns may not add due to rounding.

Reserve values

The estimated before tax net present value (NPV) of future net revenue associated with Ikkuma's reserves effective Dec. 31, 2017, and based on the Deloitte report and the consensus price forecast are summarized in the associated table.

                                         RESERVE VALUES

Reserves category                    0%          5%         10%         15%         20%
                                   (M$)        (M$)        (M$)        (M$)        (M$)
Proven
Developed producing            $564,278    $396,518    $301,180    $241,391    $200,990
Developed non-producing         135,627      86,876      59,389      42,557      31,574
Undeveloped                      38,195      24,264      14,949       8,585       4,125
Total proven                    738,100     507,658     375,517     292,533     236,689
Probable                        379,605     188,565     112,645      75,673      54,929
Total proven plus probable    1,117,704     696,223     488,162     368,206     291,619

Notes
(1) Based on Deloitte's Dec. 31, 2017, consensus price 
forecast.
(2) The estimated future net revenues are stated prior to 
provision for interest, debt service charges, or general and 
administrative expenses and after deduction of royalties, 
operating costs, estimated well abandonment and reclamation 
costs, and estimated future capital expenditures.
(3) See the corporation's AIF, once filed, for the 
after-tax present values of future net revenue attributed 
to Ikkuma's reserves.
(4) Columns may not add due to rounding.
 

                                                    PRICE FORECAST
            Canadian
               light          Western
               sweet           Canada
           crude (2)           Select        Alberta       Edmonton        Edmonton        Edmonton
Year   40-degree API  20.5-degree API         AECO-C        propane          butane   pentanes plus        $US/$C
            ($C/bbl)         ($C/bbl)   ($C/mcf) (4) ($C/bbl) (3,5)  ($C/bbl) (3,5)  ($C/bbl) (3,5) exchange rate

2018          $67.80           $49.56          $2.39         $37.39          $55.63          $65.87         0.788
2019          $71.08           $55.17          $2.71         $37.96          $57.13          $67.86         0.800
2020          $73.52           $59.41          $3.14         $37.62          $58.99          $69.50         0.816
2021          $77.98           $63.47          $3.42         $39.43          $62.51          $72.99         0.834
2022          $81.64           $66.92          $3.62         $40.57          $65.80          $75.46         0.835
2023          $83.56           $68.65          $3.75         $41.13          $67.30          $77.25         0.845
2024          $85.74           $70.61          $3.90         $42.24          $69.02          $79.31         0.845
2025          $87.95           $72.58          $4.03         $43.36          $70.74          $81.37         0.845
2026          $89.99           $74.39          $4.14         $44.42          $72.34          $83.29         0.845
2027          $91.82           $75.94          $4.24         $45.35          $73.83          $84.98         0.845
2028          $93.65           $77.46          $4.33         $46.31          $75.29          $86.70         0.845
2029 plus                                                              prices escalate at 2.0 per cent thereafter

Notes
(1) This consensus price forecast is an average of four independent reserve evaluators' 
forecasts at Dec. 31, 2017, including Deloitte, GLJ, McDaniel and Sproule.       
(2) Edmonton city gate prices based on historical light oil par prices posted by the 
government of Alberta and net energy differential futures (40-degree API less than 0.5 per cent sulphur).
(3) Natural gas liquid prices are forecasted at Edmonton therefore an additional 
transportation cost must be included to plant gate sales point.                            
(4) One thousand cubic feet are equivalent to one million British thermal units.
(5) Natural gas liquids prices have been switched from a mix reference to a spec reference. 
 

                                RESERVES RECONCILIATION 

                                 Light and Natural gas     Associated and          Oil
                          medium crude oil     liquids non-associated gas   equivalent
Total proven                        (mbbl)      (mbbl)             (mmcf)       (mboe)

Dec. 31, 2016                          265         459            115,240       19,931
Product type transfer                    -           -                  -            -
Extensions and
improved recovery                      154           6              6,489        1,241
Infill drilling                          -           -                  -            -
Technical revisions (decrease)         (59)        233             19,418        3,410
Acquisitions                           684         481            344,394       58,564
Dispositions                             -           -                  -            -
Economic factors (decrease)             (5)        (29)            (6,924)      (1,189)
Production (decrease)                  (20)        (46)           (13,549)      (2,324)
Dec. 31, 2017                        1,018       1,104            465,069       79,634


                                    Light and   Natural gas      Associated and         Oil
                             medium crude oil       liquids  non-associated gas  equivalent
Total proven plus probable             (mbbl)        (mbbl)              (mmcf)      (mboe)

Dec. 31, 2016                             799           567             157,037      27,539
Product type transfer                       -             -                   -           -
Extensions and
Improved recovery                         268            11              10,462       2,023
Infill drilling                             -             -                   -           -
Technical revisions (decrease)           (250)          227               8,306       1,362
Acquisitions                              876           759             462,293      78,684
Dispositions                                -             -                   -           -
Economic factors (decrease)                (2)          (22)             (3,734)       (646)
Production (decrease)                     (20)          (46)            (13,549)     (2,324)
Dec. 31, 2017                           1,672         1,496             620,814     106,637
           
Note 
(1) Columns may not add due to rounding.

2017 operating results and operations update

Production

Ikkuma's 2017 annual average increased to 6,366 boe/d, comparable with 6,310 boe/d of 2016 annual average production volumes. Fourth quarter 2017 average daily production increased by 23 per cent to 7,324 boe/d compared with fourth quarter 2016 average daily production of 5,967 boe/d.

Current average daily production, based on field estimates, is in excess of 19,000 boe/d after closing the Foothills acquisition on Dec. 21, 2017.

Optimization

Successful field optimization initiatives with minimal capital spending have been completed since closing the Foothills acquisition. During the last three months, field and office staff have contributed to optimization efforts on the newly acquired properties for production increases of more than 8 per cent and an operating cost decrease per boe of not less than 10 per cent. Continuing production and operating cost optimization will continue as Ikkuma further integrates the acquired assets into its now substantially larger production base.

Crude oil development drilling opportunities

The Foothills acquisition expanded the existing crude oil development drilling inventory to more than 200 low-risk locations throughout the Alberta foothills areas.

Market diversification

With the significant production growth, in addition to a continuing hedging risk management program, Ikkuma is also pursuing a diversified natural gas marketing program to reduce price risk beyond AECO pricing. The corporation has begun to build a portfolio of energy derivatives and has forward sold 33 per cent of its expected sulphur production for 2018 in the form of costless collars at $60 (U.S.) to $100 (U.S.)/tonne. In addition, 17 per cent of its expected average daily natural gas production for 2018 has been hedged at an average price of $2.55/gigajoule.

Non-core divestitures

To maintain its prudent financial strategy and to access the significant inventory of drilling opportunities, particularly focused on an expanded crude oil development drilling inventory, Ikkuma is actively planning to sell non-core assets in 2018.

Liquidity

As a result of the significant increase in all reserve categories, particularly proven developed producing reserves, as at Dec. 31, 2017, Ikkuma anticipates an extension of its current syndicated credit facility. A review of the facility is anticipated to be completed by April 25, 2018.

The syndicated credit facility along with anticipated proceeds from non-core asset dispositions is expected to provide the necessary liquidity to fulfill Ikkuma's capital expenditure requirements for 2018.

Given the current low natural gas price environment, financial covenants with both the corporation's bank syndicate and its term debtholder were amended prior to Dec. 31, 2017, and Ikkuma is fully compliant with all covenants associated with its current debt financing facilities (unaudited).

Production

Guidance for 2018 average daily production is expected to be in the range of 17,500 boe/d to 18,500 boe/d considering the impact of production declines throughout the year. Production guidance excludes potential non-core divestitures.

Capital expenditures

The corporation's capital expenditure program for 2018 will focus on fulfilling a $12.5-million obligation associated with the flow-through financing completed in 2017. The remainder of the capital expenditure program is expected to be on necessary maintenance, equipping, tie-in and low-cost high-return optimization initiatives.

About Ikkuma Resources Corp.

Ikkuma Resources is a diversified junior public oil and gas company listed on the TSX Venture Exchange 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. 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.

We seek Safe Harbor.

© 2024 Canjex Publishing Ltd. All rights reserved.