Iron Bridge Resources Provides Operations Update and Reports Second Quarter 2018 Financial Results
CALGARY, Alberta, Aug. 14, 2018 (GLOBE NEWSWIRE) — Iron Bridge Resources Inc. (TSX:IBR) (“Iron Bridge”, “IBR” or the “Company”) today provides a Gold Creek operations update and reports its financial results for the second quarter ended June 30, 2018.
Gold Creek Montney Operations Update
At Gold Creek, Iron Bridge holds a large, strategically-positioned land base of 49,600 net acres (77.5 net sections) within the oil-rich window of the Gold Creek Montney formation, with substantial multi-year development opportunities holding significant resource potential. Asset development of the Montney formation in the Gold Creek area is focused on horizontal drilling with increased frac stages 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.
As previously-disclosed, at the end of April 2018 the Company brought on-production its two (2.0 net) new Gold Creek Montney horizontal wells (100/8-21 and 102/8-21). Production from these wells during the second quarter and the month of July was constrained by water injection limitations, which has been recently alleviated with the in-service of an additional third injection well. An existing Montney legacy well was converted to an injection well, which in addition to alleviating water management issues, will also provide pressure support to the producing reservoir. IBR now has capacity to handle Montney formation water production from all of its existing producers.
The water injection constraints also impacted production run times of IBR’s legacy horizontal wells during the second quarter. To avoid prohibitive costs associated with trucking and disposing of produced water to third-party facilities, the Company intentionally and prudently produced these wells on an intermittent basis within the water injection capacities of its 2-23 Facility. As a result of these variable shut-ins, three (3.0 net) Montney wells (the 3-22, 4-18 and 15-23) produced for only 45% (41 days), 47% (43 days) and 64% (58 days) of the time in the second quarter, respectively.
In the second quarter, pursuant to good engineering and production practice, the Company fitted its new Gold Creek 100/8-21 and 102/8-21 wells with downhole chokes to capture data on the impact of production pressure on gas-oil-ratios and water-cuts. Though this resulted in lower production volumes, as anticipated, it has provided important technical data with regard to maximizing hydrocarbon resource recovery.
Additionally, in order to assist with assessing the production contribution from individual fractured stages, the Company injected chemical tracers while completing the 100/8-21 and 102/8-21 lateral wellbores. In July, upon receipt of comprehensive tracer analysis, the results indicated that between 30-40% of the respective lateral sections are not yet contributing to wellbore output. As a result, the Company is currently conducting coil tubing clean-out operations on the 100/8-21 well and will conduct a similar well clean-out operation on the 102/8-21 well later this week. Results thus far on the 100/8-21 well have identified sand loading in the toe section of the lateral, including a possible sand bridge. Both wells are presently shut-in for these operations.
In the second quarter, the Company also completed the previously-described enhancement work to its wholly-owned Gold Creek 2-23 Facility. The battery was upgraded and re-configured in order to alleviate pressure restrictions, more efficiently handle high-volume wells and to support future development and growth of its Montney production base. As a result, the battery’s upgrade configuration is now optimized and is capable of processing 2,800 bbls/d of light oil and 22 MMcf/d of natural gas for an oil equivalent capacity of approximately 6,500 boe/d.
In preparation for the next phase of its Montney development, the Company recently permitted and licenced six new well locations (6.0 net), which are ‘drill ready’ from the Company’s Gold Creek 2-23 Facility surface lease pad. The Company has proposals from a number of potential strategic capital partners to provide funding capital for Iron Bridge’s next phase of development drilling. These financial parties are supportive of IBR’s current prioritized efforts to pursue alternative, “white-knight” superior proposals in response to the unsolicited take-over offer from Velvet Energy Ltd. (“Velvet”). Please refer to the Unsolicited Take-Over Offer section of this news release hereafter.
Second Quarter 2018 Results Commentary
Selected financial and operating information is summarized below and should be read in conjunction with IBR’s unaudited interim consolidated financial statements and related Management’s Discussion and Analysis, which are available at www.sedar.com and on the Company’s website at www.ironbridgeres.com.
In the second quarter, average daily production was 2,314 boe/d (weighted 30% light crude oil and NGLs), representing an 84% sequential increase over the prior quarter output of 1,256 boe/d. Please refer to the foregoing Gold Creek Montney Operations Update section of this news release for further production discussion.
Adjusted Funds Flow and Field Operating Netback
Second quarter adjusted funds flow was $1.22 million ($0.01 per share basic), impacted by corporate costs related to IBR’s defense against the ongoing hostile take-over offer. Please refer to G&A Expense section hereafter. The Company’s Gold Creek field operating netback during the second quarter was $11.58/boe, lower than the operating netback of $16.69/boe in the preceding first quarter of 2018, due primarily to lower realized gas prices in the second quarter.
Petroleum and natural gas (“P&NG”) revenue in the second quarter was $5.54 million, an increase of 63% from the preceding first quarter 2018 revenue amount of $3.39 million. There was no realized commodity hedging activity in either quarter. IBR’s average selling price for its Gold Creek light oil (43 degree API) was $81.27/bbl in the second quarter, reflecting a $6.32/bbl oil differential to the Canadian-dollar equivalent WTI price of C$87.59/bbl. IBR’s natural gas sales price of $1.33/Mcf in the quarter was at a premium to the AECO benchmark price, as its Gold Creek Montney gas benefits from a relatively-higher heat content as compared to the standard heat conversion used in the AECO benchmark pricing. IBR’s average selling price for its Gold Creek NGLs was $54.86/bbl in the second quarter, approximately 68% of its realized oil sales price.
For the second quarter, royalties were approximately $150 thousand (2.7% royalty rate). P&NG royalty expense was positively impacted by a Crown GCA net recovery related to a prior period in the amount of $208 thousand. At Gold Creek, a significant portion of the Company’s current Montney production and future new well production, benefits from the Alberta Government’s Modernized Royalty Framework, which provides for a pre-payout drilling and completion cost allowance based on a revenue minus cost royalty structure across all hydrocarbons, a post-payout royalty rate based on commodity prices, and the reduction of royalty rates for mature wells. IBR’s significant Gold Creek Montney leasehold position of 49,920 gross acres (49,600 net acres) is substantially all Crown-lease based.
Net Operating Expense
For the second quarter, total net operating expenses were $1.85 million ($8.78/boe). IBR’s 2018 operating cost profile has benefited from the Company’s strategic transition to a geographically-concentrated, Montney-focused play at Gold Creek with a lower operating cost structure. Moreover, future production additions are expected to provide further operational efficiencies with fixed costs being distributed over a higher, future production base.
Net Transportation Expense
For the second quarter, total net transportation expenses were $1.11 million ($5.25/boe). Transportation expense represents the cost of pipeline transporting IBR’s crude oil and natural gas and trucking its NGLs to their respective title transfer points. IBR is party to ‘take-or-pay’ firm transportation service agreements for both its natural gas (Alliance Pipeline system) and crude oil (Pembina Peace system) sales production, which ensures uninterrupted delivery of the Company’s light oil and gas production.
Iron Bridge’s second quarter head office general and administrative expenses (“G&A”) amounted to $1.31 million ($6.22/boe). Reported G&A for the quarter includes approximately $0.3 million of costs incurred in connection with defending the hostile, unsolicited take-over bid and the related strategic alternatives, “white-knight” process presently ongoing. This extraordinary item impacted IBR’s second quarter per unit G&A expense by $1.42/boe. Excluding these costs, the Company’s per-unit G&A expense for the second quarter would have been $4.80/boe, a significant decrease of 50% from the preceding first quarter 2018 per-unit G&A cost of $9.54/boe.
Second quarter exploration and development capital expenditures amounted to $4.63 million. In the quarter, the Company completed necessary enhancement work to its wholly-owned Gold Creek 2-23 Facility. The battery was upgraded and re-configured in order to alleviate pressure restrictions, more efficiently handle high-volume wells and to support future development and growth of its Montney production base. In April 2018 the Company finalized tie-in connection and equipping of its new Gold Creek Montney horizontal wells (100/8-21 and 102/8-21), in addition to its second water injection well. Reported second quarter 2018 capital expenditures also includes residual costs for the completion and testing operations for both the 100/8-21 and 102/8-21 wells, in addition to residual drilling costs with equipment de-mobilization and lease restoration associated with IBR’s second Montney delineation, land-holding horizontal well.
Normal Course Issuer Bid
In the second quarter, there were no common shares purchased for cancellation in connection with the Company’s normal course issuer bid, share buy-back program (the “NCIB”). In the first quarter, a total of 545,172 shares were purchased for cancellation for $366 thousand. Since commencement of its NCIB in November 2017, the Company has purchased a total of 1.77 million shares for cancellation for a total of $1.17 million.
Liquidity and Capital Resources
In connection with the annual borrowing base re-determination of its revolving credit facility, the Company’s borrowing base limit was recently increased to $10.0 million by its lender, enhancing IBR’s liquidity capabilities. Additionally, the Company holds a $9.0 million share investment in Tangle Creek Energy Ltd. (the “TCE Investment”). As at June 30, 2018, Iron Bridge’s net debt was $5.74 million. Net debt is defined as outstanding bank debt plus the working capital deficiency and excludes the TCE Investment asset.
Unsolicited Take-Over Offer
On May 29, 2018, Velvet commenced an unsolicited, hostile offer to acquire all of the outstanding shares of Iron Bridge” at a price of $0.75 in cash per common share (the “Offer”). IBR’s Board of Directors (the “Board”), based upon the recommendation of its independent Special Committee, have unanimously recommended that IBR shareholders reject the Offer from Velvet.
The Company is currently engaged in discussions with multiple potential “white-knight” parties that may result in a superior proposal to the Offer by Velvet and also has access to its own financing alternatives. The overwhelming majority of shareholders that IBR’s Management and the Board have spoken to have expressed their preference for either of these alternatives over a $0.75 per share cash bid, which in addition to significantly undervaluing the Company’s resource value potential, would deny them exposure to IBR’s tremendous growth upside and the price improvement in the energy sector.
As described in the Letter to Shareholders and Directors’ Circular mailed in June 2018 to each of Iron Bridge’s shareholders and filed with Canadian securities regulatory authorities, the Board carefully reviewed and considered the terms and conditions of the Offer, with the assistance of its legal and financial advisors. On the basis of multiple factors, including an inadequacy opinion received from Cormark Securities Inc., its independent financial advisor, the Board unanimously concluded that the Offer is not in the best interests of Iron Bridge shareholders.
The Board’s recommendation to IBR shareholders is that they reject the Offer and do not tender their Common Shares. If shareholders have tendered their Common Shares in error and wish to withdraw, they simply need to ask their broker or contact our information agent (Evolution Proxy, Inc.) at 1-844-226-3222 (North American toll-free) for assistance with this process. A more detailed discussion of the reasons for rejecting the unsolicited Offer and the inadequacy opinion provided by Cormark Securities Inc. is contained in the Directors’ Circular. The Directors’ Circular is also available on SEDAR (www.sedar.com) and on the Company’s website (www.ironbridgeres.com).
The Company’s interim condensed consolidated financial statements and associated Management’s Discussion and Analysis for the three and six month periods ended June 30, 2018 will be available 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.
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|
|Calgary, Alberta, Canada|
|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.
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.
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: capacity to handle Montney formation water production from all existing producing wells; the completion of strategic funding or “white-knight” superior proposals; and, the development opportunities in respect 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 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.
Net debt represents outstanding bank debt plus working capital deficiency (or minus working capital surplus) excluding any unrealized amounts pertaining to risk management contracts.
Adjusted Funds Flow
Adjusted funds flow represents cash provided from (used in) operating activities before: decommissioning obligation cash expenditures, and changes in non-cash working capital from operating activities. As an indicator of the Company’s performance, the term adjusted funds flow contained within should not be considered as an alternative to, or more meaningful than, cash provided from (used in) operating, financing or investing activities, as determined in accordance with IFRS. Adjusted funds flow is widely accepted as a financial indicator of an exploration and production company’s ability to generate cash which is used to internally fund exploration and development capital activities and to service debt. This measure is widely used by shareholders and investors in the valuation, comparison and investment recommendations of companies within the upstream oil and gas exploration and production industry.
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.