CALGARY, Alberta, March 20, 2018 (GLOBE NEWSWIRE) — Iron Bridge Resources Inc. (“Iron Bridge”, “IBR” or the “Company”) (TSX:IBR) today is pleased to report its year-end 2017 oil and gas reserves and fourth quarter 2017 financial results and provide an operations update.
Year-End Reserves Information
The following provides information on IBR’s crude oil, natural gas and NGLs reserves as of December 31, 2017, as evaluated by the Company’s independent qualified reserves evaluators, McDaniel & Associates Consultants Ltd. (“McDaniel”). The evaluation of IBR’s reserves was prepared in accordance with the definitions, standards and procedures prescribed in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook. Unless stated otherwise, all reserves referred to in this news release are stated on a company gross basis (working interest before deduction of royalties and without including any royalty interests). Additional reserves information as required under NI 51-101 is included in the Company’s Annual Information Form with respect to the year ended December 31, 2017, which is being concurrently filed on SEDAR (as defined below).
The reported reserves at December 31, 2017 exclude reserves that were disposed of in connection with the strategic disposition of the Company’s Waskahigan, Grizzly, Kaybob, Gilby, Pine Creek fields, and other minor Alberta properties (the “Disposition Assets”), which closed on October 17, 2017. Iron Bridge’s year-end 2017 reserves highlights include the following:
- Total proved plus probable reserves at December 31, 2017 of 26.11 million boe. Elmworth/Gold Creek reserves additions of 21.76 million boe (proved plus probable) essentially replaced the disposed proved plus probable reserves associated with the aforementioned Disposition Assets (22.15 million boe).
- Total proved reserves at December 31, 2017 of 11.47 million boe. Significant proved reserve additions at Elmworth/Gold Creek (10.31 million boe), less the divested proved reserves attributable to the Disposition Assets (14.00 million boe) and fiscal 2017 production (1.20 million boe), resulted in lower proved reserves reported at year-end 2017 as compared to 16.36 million boe of proved reserves at December 31, 2016.
- Assigned and booked reserves on only 10% (8.5 net sections) of IBR’s year-end 2017 acreage of 53,440 net acres (83.5 net sections) of Montney rights at Elmworth/Gold Creek and Pipestone. At year-end 2017, conservatively a total of only 16 future Montney proved undeveloped horizontal locations and 12 future Montney probable undeveloped horizontal locations were booked. These future development opportunities were booked offsetting or in close proximity to the Company’s previously-drilled wells on the surface lease pad at 2-23-68-3W6. Iron Bridge estimates, based on geological mapping and technical data, that it has in excess of 500 potential drilling locations in the Montney formation across its acreage position.
- Drilling locations booked within the Elmworth/Gold Creek Mid-Montney oil window averaged approximately 870 Mboe per well location (33% light oil and NGLs) proved plus probable, which is a 34% increase over the year-end 2016 average location booking of 650 Mboe (proved plus probable), resulting in positive reserve revisions at year-end 2017 at Elmworth/Gold Creek. Refer to the Reserves Reconciliation heading hereafter
- Delivered low cost Elmworth/Gold Creek Montney reserves additions in 2017, with finding and development (“F&D”) costs of $9.47 per proved plus probable boe, and $12.79 per proved boe, including changes in future development capital (“FDC”). Refer to the detailed calculation under the Capital Expenditures Efficiency heading hereafter
- Established a net asset value at December 31, 2017 of $1.25 per share (proved plus probable discounted at 10%). Refer to the detailed calculation under the Net Asset Value heading hereafter.
Please refer to below for definitions and advisories.
Corporate Reserves Information
|December 31, 2017 Reserves Summary (1) (company gross reserves)|
|Shale Gas||Tight Oil||NGLs||Oil Equivalent|
|(Columns may not add due to rounding)||(Bcf)||(Mbbls)||(Mbbls)||(Mboe) (6:1)|
|Proved developed producing||4.827||173.5||116.9||1,094.8|
|Proved developed non-producing||–||–||–||–|
|Total Proved plus Probable||105.132||6,066.6||2,524.4||26,113.0|
|(1) Estimated using McDaniel’s forecast prices and costs as of January 1, 2018.|
|December 31, 2017 Net Present Value Summary (1) (company gross reserves)|
|(Columns may not add due to rounding) (amounts in $000s)|
|Proved developed producing||$||7,830||$||7,315||$||6,832||$||6,401||$||6,024|
|Total Proved plus Probable||$||277,150||$||179,532||$||121,494||$||85,165||$||61,353|
|(1) Net present values reported are before taxes based on McDaniel’s forecast prices and costs as of January 1, 2018. The calculated net present values include a deduction for estimated future well abandonment and reclamation but do not include a provision for bank debt interest and general and administrative expenses. It should not be assumed that the net present value estimates represent the fair market value of the reserves.|
A summary of McDaniel’s escalated price forecast assumptions as of January 1, 2018 are as follows:
|YEAR||WTI||Light||Spot||Propane||Butane||Condensate||Exchange Rate||Inflation Rate|
Net Asset Value
The Company’s net asset value details, as of December 31, 2017, are as follows:
|(columns may not add due to rounding)||NPV 10%||NPV 15%|
|(per share figures based on basic outstanding shares)||($000s)||$/share||($000s)||$/share|
|Proved plus probable reserves NPV (1,2)||$||121,494||$||0.78||$||85,165||$||0.55|
|Undeveloped acreage (3)||41,309||0.27||41,309||0.27|
|Net Asset Value||$||193,494||$||1.25||$||157,164||$||1.01|
|(1) Evaluated by McDaniel as at December 31, 2017. Net present values do not represent fair market value of the reserves.|
|(2) Net present values (“NPV”) reported are before taxes based on McDaniel’s forecast prices and costs as of January 1, 2018. The calculated net present values include a deduction for estimated future well abandonment and reclamation but do not include a provision for bank debt interest and general and administrative expenses. It should not be assumed that the net present value estimates represent the fair market value of the reserves.|
|(3) Independently-evaluated undeveloped acreage with no reserves assigned. Reflects an independent third-party estimate of the fair market value of IBR’s undeveloped acreage based on past Crown land sale activity, adjusted for tenure and other considerations.|
|(4) Liquidity reflects working capital surplus plus available-for-sale investment asset at December 31, 2017 (unaudited).|
|(5) Common shares outstanding at December 31, 2017 of 155.36 million.|
Capital Expenditures Efficiency
The following provides an overview of IBR’s F&D costs. Generally the calculation of both F&D costs and FD&A costs includes incorporating changes in future development capital (“FDC”) required to bring the proved undeveloped and probable undeveloped reserves on-production. Changes in forecasted FDC occur annually due to capital development activities, acquisition and/or disposition activities, undeveloped reserve revisions and capital cost estimates that reflect the independent reserves evaluators best estimate of what it will cost to bring the proved undeveloped and probable undeveloped reserves on-production.
For fiscal 2017, the Company cannot calculate its corporate FD&A costs, including changes in FDC, as the impact of the divested Disposition Assets and the change in FDC more than offsets IBR’s 2017 exploration and development expenditures. Similarly, disclosure calculation of prior year comparative fiscal 2016 FD&A costs including changes in FDC cannot be calculated as the impact of the Ante Creek property disposition that closed in November 2016 along with the change in FDC more than offsets the Company’s 2016 exploration and development capital expenditures.
The Company, however, has calculated its fiscal 2017 Elmworth/Gold Creek area F&D costs for the reserves added as a result of its exploration and development capital expenditures at Elmworth/Gold Creek, exclusive of its disposition activities in 2017.
|Elmworth/Gold Creek Field F&D Costs||Fiscal 2017|
|(amounts in $000s except reserve units and unit costs)||Proved||Proved + Probable|
|Drilling and completions||20,867||20,867|
|Facilities and well equipment||16,842||16,842|
|Total capital expenditures (1)||$||38,563||$||38,563|
|Change in FDC: (1)|
|FDC – December 31, 2017||$||114,987||$||207,678|
|FDC – December 31, 2016||(21,700)||(40,034)|
|Change in FDC||$||93,287||$||167,644|
|Aggregate F&D, including change in FDC (1)||$||131,850||$||206,207|
|Reserve additions (Mboe)||10,311.4||21,764.9|
|Elmworth/Gold Creek F&D Costs ($/boe) (1,2)||$||12.79||$||9.47|
|(1) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total F&D costs related to reserves additions for that year.|
|(2) Calculation includes changes in FDC.|
Future Development Capital
At year-end 2017, a total of only 16 future Montney proved undeveloped horizontal locations and 12 future undrilled Montney probable undeveloped horizontal locations were booked at Elmworth. The following table outlines the FDC required to bring proved undeveloped and probable undeveloped reserves associated with these locations on-production. The FDC has been deducted in the estimation of future net revenue attributable to total proved reserves and total proved plus probable reserves (using forecast prices and costs).
|Future Development Capital (1)|
|(amounts in $000s)||Total Proved||Total Proved + Probable|
|2022 and subsequent||21,477||112,365|
|Total undiscounted FDC||$||114,987||$||207,678|
|Total discounted FDC at 10% per year||$||92,399||$||139,957|
|(1) FDC as per McDaniel’s independent reserves evaluation as of December 31, 2017 and based on McDaniel’s forecast pricing as at January 1, 2018.|
The following summary table provides a reconciliation of the Company’s working interest gross reserves as at December 31, 2017 to the reserves as at December 31, 2016:
|Reserves Reconciliation (company gross reserves)||Total
|December 31, 2016||16,361.9||11,339.5||27,701.4|
|Extensions and Improved Recovery||9,796.0||10,417.8||20,213.8|
|December 31, 2017||11,473.0||14,640.0||26,113.0|
|(columns may not add due to rounding)|
Elmworth/Gold Creek Operations Update
For the fourth quarter of 2017, the Company produced 1,946 boe/d on average from its Elmworth/Gold Creek Montney asset (28% light oil and NGL’s), reflecting a 38% increase over the 1,410 boe/d produced in the third quarter of 2017.
The Company recently concluded its winter drilling program, which was comprised of four, 100% working interest horizontal Montney wells and a water disposal well. Details of the four (4.0 net) horizontal Montney wells are as follows:
|Horizontal Well Location:||00/8-21-68-3W6||02/8-21-68-3W6||8-22-69-4W6||3-17-69-3W6|
|Drilling Rig Release:||12/22/2017||1/14/2018||2/14/2018||3/18/2018|
|Frac Packer Stages:||72||80||78||86|
|Frac Packer Spacing (m):||35||32||32||32|
|Proppant tonnes/m pumped:||1.68||1.85||TBD||TBD|
|Proppant lbs/foot pumped:||1129||1243||TBD||TBD|
|Hz length (m):||2577||2602||2528||2765|
|Total Measured Depth (m):||5000||5073||4924||5543|
|Completion type:||sliding sleeve||sliding sleeve||sliding sleeve||sliding sleeve|
|Well Status:||Awaiting Tie-in||Awaiting Tie-in||Awaiting Completion||Awaiting Completion|
Additionally, Iron Bridge recently wrapped up completion operations on two (2.0 net) Montney development horizontal wells (“8-21” and the “02/8-21”) at Elmworth/Gold Creek. These wells were drilled off of the Company’s 2-23 Facility pad and applied tighter stage spacing, longer lateral length and increased proppant intensity relative to other wells previously completed by the Company. The two wells averaged approximately 2,600 metres (~ 8,500 feet) in lateral length, 76 frac stages and 4,560 tonnes of sand proppant per well. The Company is pleased to report that 99.9% of the planned frac load was placed in the 152 stages. These wells represent a significant increase in frac intensity and are consistent with recent industry activity in the Gold Creek area.
The two wells were tested for a short period of time on a restricted basis in order to ensure minimal sand production and are currently shut-in awaiting tie-in. Following positive, encouraging initial flow test indications, the downhole tubulars will be upsized to match the expected inflow performance. These two wells are expected to be tied-in and producing in mid-April 2018 through IBR’s 2-23 Facility. The Company will report on production rates once it feels the wells have established a stabilized rate.
The drilling of the other two Montney horizontal wells were successfully concluded in the first quarter. These two step-out delineation, ‘land-holding’ horizontal wells (“8-22” and the “3-17”) will continue 41 sections of prospective acreage past its primary expiry date through to the year 2020. Completion operations on these well bores is expected to be undertaken in the second half of 2018.
At Elmworth/Gold Creek, the Company holds a large land base consisting of 84 (83.5 net) sections (53,440 net acres) of operated acreage. Management estimates these lands have in excess of 500 drilling locations. Asset development of the Montney formation will be focused on extended-reach horizontals with increased frac and proppant intensity. These technical enhancements, coupled with operational efficiencies in spud-to-on-stream cycle times, emulsion management and infrastructure optimization, will provide the key to unlocking the vast potential of the Company’s Gold Creek Montney asset.
Iron Chain Technologies Operations Update
The Company continues to progress its cryptocurrency mining pilot at its 2-23 battery site. Cryptocurrency mining equipment and a fit-for-purpose containerized facility is expected to be powered-up and operational after spring break-up. A limited amount of mining is ongoing currently in the Company’s existing facilities. Meanwhile, discussions are ongoing with a number of parties with regard to hosting third-party mining equipment. These opportunities would allow Iron Bridge to sell power without exposure to mining equipment capital costs thereby increasing natural gas netbacks. The Company will provide progress updates as they become available.
Fourth Quarter 2017 Results Commentary
In the fourth quarter of 2017, the Company closed the strategic asset divestiture (the “Disposition Transaction”) of the Disposition Assets. It is noteworthy that under International Financial Reporting Standards (“IFRS”), the Company recognizes the results of operations from the Disposition Assets up to the date of closing, when control transferred. As such, IBR’s fourth quarter 2017 results include operational and financial contribution from the Disposition Assets up to the date of closing of October 17, 2017.
The Company has transitioned to a geologically-focused Montney producer, with highly-concentrated operations at Elmworth/Gold Creek in West Central Alberta. The following commentary summarizes the Company’s fourth quarter 2017 results, which are not entirely indicative of the Company’s current and go-forward operational and financial performance, given its fourth quarter results include contribution from the Disposition Assets.
- Fourth quarter 2017 average daily production was 2,416 boe/d (weighted 28% crude oil and NGLs), which included 1,946 boe/d from the Company’s Elmworth/Gold Creek Montney property. Production contribution from the Disposition Assets up to the closing date of the Disposition Transaction was approximately 470 boe/d, on average for the fourth quarter. At Elmworth/Gold Creek, in early-October 2017, additional compression was installed and commissioned at the 2-23 Facility in order to alleviate gas compression capacity restrictions and facilitate concurrent production of crude oil, emulsion and natural gas from the initial three (3.0 net) Montney horizontal wells.
- The Company’s realized petroleum and natural gas (“P&NG”) revenue in the fourth quarter, including realized commodity hedging, was $5.6 million (66% was derived from crude oil and NGL sales), with $4.6 million generated from its Elmworth/Gold Creek operations. The realized sales price in the fourth quarter for its Elmworth/Gold Creek light oil sales (43 degree API), was $70.12/bbl, approximating the Canadian-dollar converted WTI benchmark price of $70.27/bbl. The realized gas price at Elmworth/Gold Creek benefits from the high heat content of its Montney gas, which yields approximately 15% more value than the standard heat conversion used in the AECO benchmark pricing. The Company’s realized sales price in the fourth quarter for its Elmworth/Gold Creek NGLs was approximately $45/bbl.
- P&NG royalties in the fourth quarter amounted to $346 thousand (6% of P&NG revenue excluding realized amounts on risk management contracts), as compared to royalties of $799 thousand (10% of P&NG revenue) in the preceding third quarter of 2017. At Elmworth/Gold Creek, the Company’s field royalty rate was approximately 3% in the fourth quarter. The Alberta Government’s Modernized Royalty Framework is expected to have a significant, positive impact on the well economics of the Company’s Elmworth Montney drilling inventory.
- On an oil-equivalent per unit basis, fourth quarter 2017 field production net operating costs of $10.43/boe were 21% lower when compared with the preceding third quarter 2017 per-unit expense of $13.25/boe. Contribution from higher-cost production from the Disposition Assets during the fourth quarter, relative to its lower cost Elmworth/Gold Creek production, inflated the Company’s overall reported operating costs. In the fourth quarter, the Disposition Assets net operating costs were approximately $14.40/boe, as compared to $9.48/boe at Elmworth/Gold Creek. Compressor maintenance start-up costs along with a workover operation conducted on a legacy Gold Creek well in the fourth quarter resulted in a higher than normal cost profile at Elmworth/Gold Creek. However, for the month of December 2017, net operating costs for the Elmworth/Gold Creek field were approximately $8.30/boe. The Company’s transition to a geographically concentrated, Montney-focused play with a lower operating cost structure is expected to result in lower reported net operating expenses prospectively.
- Per-unit net transportation costs were $6.65/boe in the fourth quarter of 2017, as compared to the preceding third quarter 2017 per-unit expense of $6.03/boe. On July 1, 2017, upon the completion and in-service of the Pembina Peace Pipeline Phase III expansion, the Company’s contracted firm service oil transportation volumes increased. The associated ‘take-or-pay’ charges resulted in higher per-unit net transportation costs in the third quarter. However, in conjunction with the aforementioned Disposition Transaction, a significant portion of these commitments were permanently assigned to the purchaser, thus mitigating the go-forward obligations for the Company. Per-unit transportation costs at Elmworth/Gold Creek for 2018 is expected to approximate $5.00/boe, which primarily relates to pipeline tolls on the Pembina Peace Pipeline and Alliance Pipeline Systems in addition to transportation charges of its NGLs.
- Fourth quarter 2017 general and administrative expenses (“G&A”) amounted to $1.7 million, a 47% decrease from the $3.3 million in the third quarter of 2017 and a 23% decrease from the $2.2 million expensed in the fourth quarter of 2016. Gross G&A decreased by $1.6 million over the preceding third quarter primarily as a result of executive management restructuring undertaken in the third quarter. Fourth quarter 2017 gross G&A included annual year-end costs associated with the IBR’s independent engineering reserves report and the fiscal 2017 financial statement audit. The quarter also included employee termination severance costs of $386 thousand, disbursed in connection with the Company’s head office staff count reductions. At year end 2017, IBR employed 15 head office personnel, as compared to the 20 employees prior to staff reductions. Adjusting for the employee termination costs in the fourth quarter, “normalized” G&A expense for the quarter would have been $1.3 million or $6.02 per boe. For 2018 the Company is estimating G&A expenses to average approximately $1.0 million per quarter, representing a 20% to 25% decrease from historical levels, reflecting cost optimization initiatives already undertaken in 2018.
- In the fourth quarter of 2017, the Company’s exploration and development capital program was approximately $7.5 million. Drilling and completion costs for the quarter were approximately $6.1 million and include the horizontal drilling cost of a 100% working interest development infill Elmworth/Gold Creek Montney well, initial drilling costs for a second infill horizontal Montney well and drilling and completion costs for a water disposal well. Fourth quarter 2017 facilities and well equipment costs were $1.3 million, which primarily relates to costs incurred in respect to the 2-23 Facility for gas compression installation, additional power generation and water disposal well pump gear.
- In the fourth quarter, on November 20, 2017, the Company commenced a normal course issuer bid, share buy-back program (the “NCIB”). In 2017, the Company purchased 1,224,702 shares for cancellation for $0.8 million. The cancelled shares have been removed from share capital. Year-to-date fiscal 2018, the Company has purchased an additional 545,172 shares for cancellation for $0.4 million.
- The fourth quarter 2017 field operating netback was $6.60/boe, tempered by higher-cost production from the Disposition Assets. IBR’s Elmworth/Gold Creek operating netback during the fourth quarter was $10.67/boe, as compared to a negative operating netback from the Disposition Assets of ($3.49/boe).
- As a result of the Disposition Transaction, at year-end 2017 the Company had no bank debt outstanding and a liquidity position of approximately $31 million, comprised of a working capital surplus of $21.7 million and the $9.0 million available-for-sale asset (equity investment in shares of the purchaser of the Disposition Assets). Additionally, IBR has access to a $5.0 million bank credit facility.
Please refer to the Company’s audited consolidated financial statements and the Management’s Discussion and Analysis for the year ended December 31, 2017 for detailed financial and operational results. These documents will be filed later today on IBR’s website at www.ironbridgeres.com within “Investors” under “Financials”. Additionally, these documents will be filed later today on the System for Electronic Document Analysis and Retrieval (“SEDAR”). After such filing, these documents can be retrieved electronically from the SEDAR system by accessing IBR’s public filings under “Search for Public Company Documents” within the “Search Database” module at www.sedar.com.
Notice of Change of Transfer Agent and Registrar
Effective March 15, 2018, Odyssey Trust Company replaced Computershare Investor Services Inc. as Transfer Agent and Registrar for Iron Bridge. No action is required by shareholders as a result of this transition.
For more information, please contact:
IRON BRIDGE RESOURCES INC.
|Rob Colcleugh||Dean Bernhard|
|Chief Executive Officer||Vice President, Finance and Chief Financial Officer|
|(403) 930-6333||(403) 930-6304|
Suite 1200, 500 – 4th Avenue SW
|bbl or bbls||barrel or barrels||Mcf/d||thousand cubic feet per day|
|Mbbl||thousand barrels||MMcf/d||million cubic feet per day|
|bbls/d||barrels per day||MMcf||Million cubic feet|
|boe||barrels of oil equivalent||Bcf||billion cubic feet|
|Mboe||thousand barrels of oil equivalent||psi||pounds per square inch|
|boe/d||barrels of oil equivalent per day||kPa||kilopascals|
|NGLs||natural gas liquids||GJ||Gigajoule|
|WTI||West Texas Intermediate||GJ/d||Gigajoules per day|
|AECO||Alberta Energy Company|
Oil and Gas Matters
In this news release IBR has adopted a standard for converting thousands of cubic feet (“mcf“) of natural gas to barrels of oil equivalent (“boe”) of 6 mcf:1 boe. Use of boes may be misleading, particularly if used in isolation. The boe rate is based on an energy equivalent 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 than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
This news release may disclose drilling locations in three categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; and (iii) unbooked locations. Proved undeveloped locations and probable undeveloped locations are booked and derived from the Company’s most recent independent reserves evaluation as prepared by McDaniel as of December 31, 2017 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by management as an estimation of the Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells is ultimately dependent upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
This news release contains a number of oil and gas metrics, including F&D, operating netback, net asset value and reserve additions, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. F&D costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total finding and development costs related to reserves additions for that year. F&D costs both including and excluding acquisitions and dispositions have been presented in this news release because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of IBRs cost structure. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total F&D costs related to reserves additions for that year. Operating netback is calculated using realized wellhead revenues less royalties, net operating expenses and net transportation costs calculated on a per boe equivalent basis. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare IBR’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.
Any references in this news release to production test rates, flow-back results, flow test results and production flow test rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter. These test results are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Furthermore, neither a pressure transient analysis or a well-test interpretation has been carried out yet, and as such, test results should be considered to be preliminary until such analysis or interpretation has been completed.
In this news release, references to the Company’s 2017 reserves are based on a report prepared by McDaniel with an effective date of December 31, 2017 prepared in accordance with definitions, standards and procedures prescribed in NI 51-101 and the Canadian Oil and Gas Evaluation Handbook and based on McDaniel forecast pricing effective January 1, 2018.
In this news release, the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and net revenue for all properties due to the effects of aggregation. Estimates of reserves have been made assuming that development of each property, in respect of which estimates have been made, will occur without regard to the availability of funding required for that development. It should not be assumed that the estimates of future net revenues presented herein represent the fair market value of the reserves.
The information in this news release contains certain forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “budget”, “plan”, “continue”, “estimate”, “approximate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”, “would” and similar expressions. More particularly and without limitation, this news release contains forward-looking information relating to: anticipated number of drilling locations; FDC required to bring proved undeveloped and probably undeveloped reserves associated with certain locations of IBR; expected timing on tie-in and production of wells 8-21 and 02-8-21; expected timing for completion of drilling operations on wells 8-22 and 3-17; the potential of the Company’s Gold Creek Montney asset; expected timing of mining operations and commercial arrangements with respect to IBR’s cryptocurrency mining operations; expected results and cost structure with the Company’s transition to a geographically concentrated Montney-focused play; the financial obligations of the Company following the Disposition Transaction; estimated G&A expenses in 2018; and liquidity levels of the Company. In addition, statements relating to reserves are forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
With respect to forward-looking statements contained in this news release, IBR has made assumptions regarding, but not limited to: conditions in general economic and financial markets; effects of regulation by governmental agencies; current and future commodity prices and royalty regimes; future exchange rates; royalty rates; future operating costs; availability of skilled labor; availability of drilling and related equipment; timing and amount of capital expenditures; the impact of increasing competition; the price of crude oil and natural gas; that the Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Company’s conduct and results of operations will be consistent with its expectations; available pipeline capacity; that the Company will have the ability to develop the Company’s properties in the manner currently contemplated; that the Company will be able to drill, complete and tie-in wells in the manner and on the timing described herein; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and the estimates of the Company’s production and reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects.
These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond the Company’s control, including: the impact of general economic conditions; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; obtaining required approvals of regulatory authorities; unexpected drilling results; the Company is unable to achieve its objectives; that the anticipated resource potential in the Elmworth/Gold Creek area is not achieved; changes in capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties, including hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; delays in anticipated timing of drilling and completion of wells; lack of available capacity on pipelines; the lack of availability of qualified personnel; uncertainties associated with estimating oil and natural gas reserves; and ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties and additional risk factors are described in the Company’s Annual Information Form for the year ended December 31, 2017, which is available at www.sedar.com.
The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that the Company will derive from them. The Company’s forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statements.
Within this news release, the Company may use non-GAAP measures as an indicator of the Company’s performance. These non-GAAP measures are not prescribed by International Financial Reporting Standards (“IFRS“) and do not have standardized meanings or methods of calculation and therefore, such measures may not be comparable to similar measures presented by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon.
Field Operating Netback or Operating Netback
The term field operating netback or operating netback refers to realized wellhead revenue (including realized gains or losses on commodity risk management contracts) less royalties, net operating expenses and net transportation costs per barrel of oil equivalent. The Company believes that this financial netback measure is useful supplemental information to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities. Investors should be cautioned that this measure should not be construed as an alternative to other measures of financial performance as determined in accordance with IFRS.
Net Operating Expenses
Net operating expenses are calculated as operating expenses less the component of other income pertaining to gathering, compression, road use and other income. This metric is expressed on a total and per boe basis. Management uses this metric to determine the net cash cost related to operating expenses and to provide supplemental information to analyze operating performance.
Net Transportation Costs
Net transportation expenses are calculated as transportation expenses less the component of other income pertaining to transportation income. This metric is expressed on a total and per boe basis. Management uses this metric to determine the net cash cost related to transportation costs and to provide supplemental information to analyze operating performance.