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.