Questions? +1 (202) 335-3939 Login
Trusted News Since 1995
A service for energy industry professionals · Tuesday, November 20, 2018 · 468,804,165 Articles · 3+ Million Readers

Chinook Energy Inc. Announces Third Quarter 2018 Results

CALGARY, Alberta, Nov. 08, 2018 (GLOBE NEWSWIRE) -- Chinook Energy Inc. ("our", "we", or "us") (TSX: CKE) is pleased to announce its third quarter of 2018 financial and operating results.

Our operational and financial highlights for the three and nine months ended September 30, 2018 are noted below and should be read in conjunction with our unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2018 and 2017 and our related management’s discussion and analysis which have been posted on the SEDAR website (www.sedar.com) and our website (www.chinookenergyinc.com).

/EIN News/ -- Third Quarter of 2018 Financial and Operating Highlights

           
    Three months ended
  Nine months ended
 
      September 30
  September 30
 
OPERATIONS     2018     2017     2018     2017  
Production Volumes          
Natural gas liquids (boe/d)       707       405       620       442  
Natural gas (mcf/d)       24,454       14,109       20,210       17,051  
Crude oil (bbl/d)       24       19       22       22  
Average daily production (boe/d) (1)       4,807       2,776       4,010       3,306  
Sales Prices          
Average natural gas liquids price ($/boe)   $    63.73   $   42.07   $    63.46   $   46.22  
Average natural gas price ($/mcf)   $    1.54   $   1.20   $    1.74   $   2.31  
Average oil price ($/bbl)   $    71.35   $   51.49   $    71.82   $   57.52  
Netback (2)          
Average commodity pricing ($/boe)   $    17.59   $   12.61   $    18.97   $   18.49  
Royalty recovery (expense) ($/boe)   $    -    $   0.52   $    (0.07 ) $   0.09  
Realized (loss) gain on commodity price contracts ($/boe)   $    (0.17 ) $   6.54   $    (0.28 ) $   2.70  
Net production expense ($/boe) (2)   $    (9.74 ) $   (12.32 ) $    (11.06 ) $   (11.77 )
Operating Netback ($/boe) (1) (2)   $    7.68   $   7.35   $    7.56   $   9.51  
Wells Drilled          
Exploratory wells (net)       -        -        2.00       -   
Natural gas wells (net)       -        -        -        3.63  
           
           
    Three months ended
  Nine months ended
 
    September 30
  September 30
 
      2018     2017     2018     2017  
FINANCIAL ($ thousands, except per share amounts)          
Petroleum & natural gas revenues, net of royalties   $    7,778   $   3,351   $    20,691   $   16,772  
Adjusted funds flow (2)   $    2,285   $   647   $    4,592   $   3,878  
  Per share - basic and diluted ($/share)   $    0.01   $   -    $    0.02   $   0.02  
Cash inflow (outflow) from operating activities   $    1,132   $   (1,352 ) $    633   $   3,483  
Net (loss) income    $    (1,944 ) $   (3,923 ) $    (6,513 ) $   4,246  
  Per share - basic and diluted ($/share)   $    (0.01 ) $   (0.02 ) $    (0.03 ) $   0.02  
Capital expenditures    $    -    $   14,733   $    2,677   $   31,791  
Net (debt) surplus (2)    $    (713 ) $   3,616   $    (713 ) $   3,616  
Total assets    $    120,572   $   155,799   $    120,572   $   155,799  
Common Shares (thousands)          
Weighted average during period          
  - basic        223,605       217,115       223,591       216,721  
  - diluted       223,605       217,115       223,591       217,144  
Outstanding at period end       223,605       217,115       223,605       217,115  
           
  1. Amounts may not be additive due to rounding.
  2. Adjusted funds flow, adjusted funds flow per share, net (debt) surplus, 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) Surplus”, “Operational Netback” and “Net Production Expense” in the Reader Advisory below for further information on such terms.

Highlights for the three months ended September 30, 2018

  • During the third quarter of 2018 (“third quarter”) corporate production increased by 73%, or 2,031 boe/d, compared to the same quarter of 2017 and increased 9% relative to the 4,413 boe/d reported in the 2018 second quarter.
  • Adjusted funds flow for the third quarter of $2.3 million resulted from both higher production volumes and average commodity pricing.
  • Net production expenses decreased by 21%, or $2.58/boe (to $9.74/boe), in the third quarter compared to same quarter of 2017. Specifically, our third quarter production expenses averaged $7.68/boe in our Birley/Umbach area.
  • General and administrative expenses of $2.12/boe for the third quarter represented a decrease of $0.24 million, or 20%, compared to the same quarter of 2017 and reflected the impact of ongoing reductions in staffing, employee benefits and information system costs.
  • Net debt at September 30, 2018 was reduced to $0.7 million, from $2.7 million at June 30, 2018.

President’s Message

We believe that our capital program during the past few years which saw us drill and complete 13 (11.23 net) wells on our Birley/Umbach property as well as complete our Birley facility expansion to 50 mmcf/d puts us in an excellent position to accelerate activity when commodity prices recover. With over 550 locations on our Birley/Umbach property and only 13 drilled to date, we have confirmed the resources are there and our objective is to extract them efficiently and profitably. Our additional delineation work in the first quarter has expanded the boundaries of the Montney resource in the area. 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.

Unfortunately, Enbridge’s recent (October 9, 2018) pipeline rupture near Prince George, BC has negatively impacted the natural gas price at Station 2 (which traded at negative $1.245/gj on November 7, 2018). Enbridge subsequently issued a notice that this Westcoast pipeline has been repaired and returned to service in early November, albeit at a reduced operating pressure of 80%. 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 entire winter gas season. Although we continue to explore additional egress options, most transport services are currently fully contracted or are not economically viable. As such, we have currently voluntarily restricted our natural gas production to match firm gas sales markets (Chicago City Gate via Alliance) allowing us to produce approximately 1,900 boe/day. We will continue to monitor this situation and the related remediation by Enbridge. Prior to the pipeline rupture, commodity prices in 2018 have been higher than our internal forecasts, and should this pricing return to pre-pipeline rupture levels, they would serve to strengthen our balance sheet and facilitate future drilling activity.

We continue to prudently manage our production volumes and will continue to monitor commodity prices throughout the year and shut-in production where warranted. As a result of recent voluntary shut-ins our 2018 October production volumes were approximately 2,200 boe/day, down from 5,112 boe/day in September.

2018 Guidance Update

In our August 9, 2018 news release we provided guidance for the second half and full year 2018. The production and net debt guidance numbers provided in this news release will not be met as they are negatively impacted by the recent Enbridge pipeline outage. Given the uncertainty of the impact on winter BC Station 2 pricing, we are unable to provide updated guidance at this time.

Please see our related management’s discussion and analysis for the three and nine months ended September 30, 2018 and 2017 for details of our operational and financial results.

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.
Telephone: (403) 261-6883 Telephone: (403) 261-6883
Website: www.chinookenergyinc.com  

Reader Advisory

Abbreviations

Oil and Natural Gas Liquids   Natural Gas  
           
bbl
bbl/d
barrels
barrels per day
  mcf
mmcf
thousand cubic feet
million cubic feet
 
NGLs Natural gas liquids   mcf/d
mmcf/d
mmbtu
mmbtu/d
thousand cubic feet per day
million cubic feet per day
million British Thermal Units
million British Thermal Units per day
 
      GJ gigajoules  
      GJ/d gigajoules per day  
           
Other    
     
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)
boe/d
Station 2
Chicago City Gate
barrel of oil equivalent per day
Market point for BC natural gas
Market point for eastern US natural gas

Forward-Looking Statements

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 previous capital program during the past few years has put us in an excellent position to accelerate activity when commodity prices recover, that our capital plan for the remainder of 2018 will be minimal, and 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 2018, 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, 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.

Drilling Locations

This news release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Company’s most recent independent reserves evaluation as prepared by McDaniel & Associates Consultants Ltd. 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 Chinook'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. Of the up to 550 gross (460 net) drilling locations identified herein, 19 gross (16 net) are proved locations, 14 gross (11 net) are probable locations and 517 gross (433 net) are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Chinook will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend 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 the majority of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, certain 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.

Operating Netback

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.

Net (Debt) Surplus

The reader is cautioned that this news release contains the term net (debt) surplus, 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 and provisions. We use net (debt) surplus to assist us in understanding our liquidity at specific points in time. We exclude the current portion of provisions 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.

Chinook Energy.jpg

Powered by EIN News