CALGARY, Alberta, May 09, 2019 (GLOBE NEWSWIRE) -- Chinook Energy Inc. ("our", "we", or "us") (TSX: CKE) is pleased to announce our operating and financial results for the three months ended March 31, 2019 (“Q119”). Our unaudited condensed consolidated financial statements and management’s discussion and analysis for the three months ended March 31, 2019 are available on our website (www.chinookenergyinc.com) and filed on SEDAR (www.sedar.com).
- Additional Q119 egress: We obtained additional egress during Q119 that limited our exposure to the BC Station 2 benchmark. This increased the ratio of our natural gas production sold at benchmarks other than Station 2 to 87% compared to 40% during the three months ended March 31, 2018 (“Q118”). These other benchmark prices included Chicago City Gate and Alliance Trading Pool, where we receive a premium to what we would have realized had we sold our natural gas production at spot Station 2 pricing.
- $2.0 million of annual cost savings: We signed a new Calgary office space lease commencing on June 2019.
- Additional $1.6 million of annual gathering revenues commencing in early 2020 : Construction continues by a third party who is on schedule to tie into our Aitken Creek Pipeline.
- Q119 production of 3,029 boe/d: Our corporate production increased by 9%, or 241 boe/d, compared to Q118 despite voluntary and significant third party production restrictions and no capital investment.
- New price risk contracts: We continue to layer in commodity price hedges and diversify our natural gas sales points with approximately 28% of forecast 2019 natural gas production currently hedged at Chicago or Station 2 pricing.
- Net production expense decrease of 24%: Net production expense decreased 24% to $11.28/boe despite significant production restrictions compared to Q118. Specifically, production expenses averaged approximately $9.00/boe in our Birley/Umbach area.
- G&A decrease of 31%:General and administrative expenses of $3.23/boe represent a decrease of 31%, compared to Q118 and mostly reflect the impact of last year’s reductions in staffing, employee benefits and information system costs.
- Capital preservation:We did not incur capital expenditures as we remain cautious on making further significant investments until such time as commodity prices improve to a more constructive level.
Q119 Operating and Financial Highlights
|Three months ended|
|Natural gas liquids (boe/d)||455||468|
|Natural gas (mcf/d)||15,389||13,806|
|Crude oil (bbl/d)||9||19|
|Average daily production (boe/d)(1)||3,029||2,788|
|Average natural gas liquids price ($/boe)||$||49.96||$||58.35|
|Average natural gas price ($/mcf)||$||2.10||$||2.64|
|Average oil price ($/bbl)||$||57.89||$||68.34|
|Operating Netback (2)|
|Average commodity pricing ($/boe)||$||18.34||$||23.35|
|Royalty expense ($/boe)||$||(0.04||)||$||(0.17||)|
|Realized loss on commodity price contract ($/boe)||$||(1.69||)||$||(1.18||)|
|Net production expense ($/boe) (2)||$||(11.28||)||$||(14.84||)|
|Operating Netback ($/boe) (1) (2)||$||5.33||$||7.16|
|Exploratory wells (net)||-||2.00|
|FINANCIAL ($ thousands, except per share amounts)|
|Petroleum & natural gas revenues, net of royalties||$||4,991||$||5,815|
|Cash outflow from operating activities||$||(157||)||$||(1,722||)|
|Adjusted funds flow (2)||$||194||$||471|
|Per share - basic and diluted ($/share)||$||-||$||-|
|Per share - basic and diluted ($/share)||$||(0.01||)||$||(0.01||)|
|Net debt (2)||$||3,120||$||3,961|
|Common Shares (thousands)|
|Weighted average during period|
|- basic & diluted||223,642||223,565|
|Outstanding at period end||223,655||223,565|
- Amounts may not be additive due to rounding.
- Adjusted funds flow, adjusted funds flow per share, net debt, operating netback and net production expense are non-GAAP measures. These terms do not have any standardized meanings as prescribed by IFRS and, therefore, may not be comparable with the calculations of similar measures presented by other companies. See headings entitled “Adjusted Funds Flow”, “Net Debt”, “Operational Netback” and “Net Production Expense” in the Reader Advisory below for further information on such terms.
We believe that our previous capital programs which saw us drill and complete 13 (11.23 net) wells on our Birley/Umbach property as well as construct our 50 mmcf/d Birley facility puts us in an excellent position to accelerate activity when commodity prices recover. The previous year’s delineation work has increased the extension confidence of the Montney resource on our Martin lands. Although we are encouraged with our results to date, we remain cautious on making further significant capital expenditures until such time as commodity prices improve to a more constructive level.
Since being repaired following a pipeline rupture near Prince George, BC, Enbridge has operated its Westcoast pipeline at reduced pressures which has negatively impacted the natural gas price at Station 2. This reduced service is likely to have a continued negative impact on Station 2 gas prices for the duration of the restriction, understood to be for the remainder of the natural gas year. Although we responded by acquiring additional egress allowing us to realize a premium over Station 2 spot pricing, most transport services are currently fully contracted or are not economically favourable. Should pricing return to pre-pipeline rupture levels, they would serve to strengthen our balance sheet and facilitate future drilling activity.
Despite voluntary and significant third party production restrictions, our average daily production for Q119 was 3,029 boe/d, a 9% increase compared to Q118. Starting on January 2, 2019, there was a 20 day unplanned outage at the Enbridge McMahon Gas Plant (“McMahon Plant”). The associated production restriction partially prevented us from realizing peak winter pricing. This was further exacerbated as we had previously entered into incremental egress contracts, with their associated tariffs, to deliver natural gas production at various benchmarks and fixed prices with the objective to limit exposure to the Station 2 benchmark. These firm volume pipeline tariffs during the unscheduled outage at the McMahon Plant, net of our mitigation efforts, caused an increase in our net take-or-pay cost.
Adjusted funds flow of $0.2 million during Q119 decreased from Q118 because of lower realized pricing caused by lower benchmark pricing, other pricing changes, production restrictions, and a higher loss from a commodity price risk contract. These other pricing changes include being partially unable to realize peak winter pricing caused by the unplanned outage at the McMahon Plant in addition to entering into fixed price natural gas contracts and incurring higher pipeline tariffs to obtain additional egress despite realizing a premium to spot Station 2 pricing.
Net debt at March 31, 2019, increased to $3.1 million from $2.0 million at December 31, 2018. This increase was due to minimal adjusted funds flow, as just discussed, a new accounting standard that requires we separately report lease payments for our current Calgary office lease that expires this June and abandonment expenditures that included two (2.0) net vertical exploratory wells in the Birley/Umbach area that essentially completes our flow-through share obligation.
During the first quarter of 2019, we entered into the following commodity price contracts:
|Contractual Term||Notional Volumes||Index and Company's Received Price|
|Natural gas swap|
|October 1, 2019 to December 31, 2019||3,000 GJ/d||Westcoast Station 2 CAD$1.645/GJ|
|Natural gas collar|
|October 1, 2019 to December 31, 2019||3,000 mmbtu/d||NYMEX US$2.25/mmbtu to US$3.68/mmbtu|
|Natural gas differential swap|
|October 1, 2019 to December 31, 2019||3,000 mmbtu/d||Price at Chicago = NYMEX less US$0.125/mmbtu|
The combination of the NYMEX natural gas collars and differential swaps provide us a minimum and maximum price on notional volumes sold at Chicago City Gate pricing during the fourth quarter of 2019.
As BC natural gas price weakness continues related to export capacity constraints, we remain cautious in deploying further capital. Consequently, our capital program in 2019 will be minimal until such time as commodity prices improve to constructive levels. Our management and Board of Directors will make adjustments to the capital program in response to changing market conditions. We also expect the following to occur during 2019 or early 2020:
- $1.6 million of annualized gathering revenues: We continue to lever our existing assets and recently completed a transportation agreement for the partial use of our 12” Aitken Creek pipeline. The agreement will commence on the initial delivery of gas, anticipated to be early 2020, and will continue for a minimum period of two years. Minimum gathering charges will total approximately $1.6 million annually.
- New processing contract: Our current processing arrangement to have our natural gas processed at the McMahon Plant expires June 1, 2019. We are actively negotiating a new processing toll with Enbridge and other producers who have excess processing capacity at this plant.
- Renewal of our credit facility: Our credit facility’s next scheduled semi-annual review is May 2019. We expect our lender to reduce the $10 million availability of our credit facility given recent decreases in forward natural gas benchmark pricing. While there is no certainty in the amount of the borrowing base redetermination, we expect that our debt borrowings in May 2019 will be less than the anticipated reassessed credit facility’s availability. At March 31, 2019, we had debt borrowings of $3.0 million.
About Chinook Energy Inc.
Chinook is a Calgary-based public oil and natural gas exploration and development company which is focused on realizing per share growth from its large contiguous Montney liquids-rich natural gas position at Birley/Umbach, British Columbia.
For further information please contact:
|Walter Vrataric||Jason Dranchuk|
|President and Chief Executive Officer||Vice President, Finance and Chief Financial Officer|
|Chinook Energy Inc.||Chinook Energy Inc.|
|Website: www.chinookenergyinc.com||Telephone: (403) 261-6883|
|Oil and Natural Gas Liquids||Natural Gas|
barrels per day
|thousand cubic feet|
million cubic feet
|NGLs||Natural gas liquids||mcf/d|
|thousand cubic feet per day|
million cubic feet per day
million British Thermal Units
million British Thermal Units per day
|GJ/d||gigajoules per day|
|boe||barrel of oil equivalent on the basis of 6 mcf/1 boe for natural gas and 1 bbl/1 boe for crude oil and natural gas liquids (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)|
Chicago City Gate
|barrel of oil equivalent per day|
Market point for BC natural gas
Market point for eastern US natural gas
In the interest of providing our shareholders and readers with information regarding our company, including management's assessment of our future plans and operations, certain statements contained in this news release constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "potential", "target" and similar words suggesting future events or future performance. In particular, this news release contains, without limitation, forward-looking statements pertaining to: that our new office space lease commencing in June 2019 will result in estimated annual cost savings of $2.0 million, that our previous capital programs have put us in an excellent position to accelerate activity when commodity prices recover, our belief that a significant extension to the productive Montney fairway exists on our Martin lands, our belief that Station 2 gas prices will be negatively impacted for the remainder of the natural gas year due to reduced pressures on the Enbridge Westcoast pipeline, that our capital plan for 2019 will be minimal, the anticipated initial delivery date of gas for the purposes of the transportation agreement for the partial use of our 12” Aitken Creek pipeline, that we expect our lender to reduce the $10 million availability of our credit facility given recent decreases in forward natural gas benchmark pricing, however, we expect our debt borrowing will be less than the anticipated reassessed credit facility availability, and how we intend to manage our company.
With respect to the forward-looking statements contained in this news release, we have made assumptions regarding, among other things: that we will continue to conduct our operations in a manner consistent with that expressed herein, that we will not make significant future capital expenditures in 2019, future oil and natural gas prices, anticipated oil and natural gas production levels, future currency, exchange and interest rates, our ability to obtain equipment in a timely manner to carry out exploration and development activities, the ability of the operator of the projects in which we have an interest in to operate in the field in a safe, efficient and effective manner, the impact of increasing competition, field production rates and decline rates, our ability to replace and expand production and reserves through exploration and development activities, certain cost assumptions and the continued availability of adequate debt and cash flow to fund our planned expenditures. Although we believe that the expectations reflected in the forward-looking statements contained in this news release, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this news release, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that predictions, forecasts, projections and other forward-looking statements will not occur, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, without limitation, that the budgeted capital program for 2019, which is subject to the discretion of our Board of Directors, will not be amended in the future, there is no certainty in the amount of our borrowing base redetermination, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices and currency fluctuations, environmental risks, competition from other producers, inability to retain drilling rigs and other services, unanticipated increases in or unforeseen capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, delays in projects and/or operations resulting from surface conditions, wells not performing as expected, delays resulting from or inability to obtain the required regulatory approvals and inability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Readers are cautioned that the forgoing list of factors is not exhaustive. Additional information on these and other factors that could affect our operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) and at our website (www.chinookenergyinc.com). Furthermore, the forward-looking statements contained in this news release are made as at the date of this news release and we do not undertake any obligation to update publicly or to revise any of the forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
The reader is cautioned that this news release contains the term operating netback, which is not a recognized measure under IFRS and is calculated as a period’s sales of petroleum and natural gas, net of realized gains or losses on commodity price contracts, royalties and net production expenses, divided by the period’s sales volumes. We use this non-GAAP measure to assist us in understanding our production profitability relative to current and fixed commodity prices and it provides an analytical tool to benchmark changes in field operational performance against prior periods. Readers are cautioned, however, that this measure should not be construed as an alternative to other terms such as net income determined in accordance with IFRS as a measure of performance. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies.
Net Production Expense
The reader is cautioned that this news release contains the term net production expense, which is not a recognized measure under IFRS and is calculated as production and operating expense less processing and gathering income. We use net production expense to determine the current periods' cash cost of operating expenses and net production and operating expense per boe is used to measure operating efficiency on a comparative basis. This measure approximates our operating costs relative to only our volumes by excluding the approximated operating costs resulting from third party processing and gathering services. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies.
Adjusted Funds Flow
The reader is cautioned that this news release contains the term adjusted funds flow, which is not a recognized measure under IFRS and is calculated from cash flow from operations adjusted for changes in non-cash working capital related to operations, exploration and evaluation expenses related to operations, provision expenditures related to operations and severance/transaction costs. We believe that adjusted funds flow is a key measure to assess our ability to finance capital expenditures and when debt is drawn, debt repayments. Adjusted funds flow is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS and should not be construed as an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS as an indicator of our financial performance. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies. Adjustments to cash flow from operations are for changes in non-cash operating working capital which are expected to reverse and for those costs that are not directly caused by lifting production volumes.
The reader is cautioned that this news release contains the term net debt, which is not a recognized measure under IFRS and is calculated as bank debt adjusted for current assets less current liabilities as they appear on the balance sheets, both of which exclude mark-to-market derivative contracts and assets and liabilities held for sale and current liabilities excludes any current portion of debt, deferred customer obligations, lease liabilities and provisions. We use net debt to assist us in understanding our liquidity at specific points in time. We exclude the current portion of provisions, lease liabilities and the deferred customer obligation as they are not financial instruments. Mark-to-market derivative contracts and assets and liabilities held for sale are excluded as they are unrealized.
Barrels of Oil Equivalent
Barrels of oil equivalent (boe) is calculated using the conversion factor of 6 mcf (thousand cubic feet) of natural gas being equivalent to one barrel of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl (barrel) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.