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Chinook Energy Inc. Announces Its Audited Year-End Financial Results and 2016 Capital Program

Nachrichtenquelle: Marketwired
08.03.2016, 00:01  |  486   |   |   

CALGARY, ALBERTA--(Marketwired - March 7, 2016) - Chinook Energy Inc. ("our", "we", "us" or "Chinook") (TSX:CKE) is pleased to announce its audited year-end financial results and 2016 capital program. The audited financial results presented herein are consistent with the unaudited financial results announced in our news release issued on February 8, 2016.

We will file the audited consolidated financial statements for the years ended December 31, 2015 and 2014 and related management's discussion and analysis on the SEDAR website (www.sedar.com) and our website (www.chinookenergyinc.com). Operational and financial highlights for the three months and year ended December 31, 2015 are noted below and should be read in conjunction with our audited consolidated financial statements and related management's discussion and analysis.

2015 Financial and Operating Highlights

Three months ended
December 31
Year ended
December 31
2015 2014 2015 2014
CONTINUING CANADIAN OPERATIONS (2)
Production Volumes
Crude oil (bbl/d) 922 1,981 1,187 2,038
Natural gas liquids (boe/d) 364 778 510 779
Natural gas (mcf/d) 15,851 34,879 23,642 30,721
Average daily production (boe/d) 3,928 8,572 5,637 7,937
Sales Prices
Average oil price ($/bbl) $ 47.93 $ 70.84 $ 53.08 $ 90.68
Average natural gas liquids price ($/boe) $ 30.59 $ 48.05 $ 35.83 $ 65.02
Average natural gas price ($/mcf) $ 2.09 $ 3.57 $ 2.50 $ 4.59
Netback(1)
Average commodity pricing ($/boe) $ 22.51 $ 35.26 $ 24.89 $ 47.44
Royalties ($/boe) $ 2.39 $ (4.74 ) $ (0.73 ) $ (6.48 )
Net production expenses ($/boe) (1) $ (14.17 ) $ (18.89 ) $ (15.92 ) $ (17.61 )
G&A expense ($/boe) $ (8.31 ) $ (4.26 ) $ (4.76 ) $ (4.83 )
Netback ($/boe) (1) $ 2.42 $ 7.37 $ 3.48 $ 18.52
Wells Drilled (net)
Oil - 1.62 - 6.14
Gas - 0.83 2.75 2.70
Disposal/injection - - - 0.37
Total wells drilled (net) - 2.45 2.75 9.21
Three months ended
December 31
Year ended
December 31
2015 2014 2015 2014
FINANCIAL ($ thousands, except per share amounts)
Petroleum & natural gas revenues, net of royalties $ 9,000 $ 24,065 $ 49,701 $ 118,662
Funds from operations (1) $ 1,516 $ 6,069 $ 9,033 $ 48,158
Per share - basic and diluted ($/share) $ 0.01 $ 0.03 $ 0.04 $ 0.22
Net loss from continuing operations $ (5,303 ) $ (58,311 ) $ (83,606 ) $ (50,672 )
Per share - basic and diluted ($/share) $ (0.02 ) $ (0.27 ) $ (0.39 ) $ (0.24 )
Capital expenditures $ 9,998 $ 39,671 $ 44,325 $ 96,584
Net debt (surplus) (1) $ (29,614 ) $ (28,788 ) $ (29,614 ) $ (28,788 )
Total assets $ 321,564 $ 434,318 $ 321,564 $ 434,318
Common Shares (thousands)
Weighted average during period
- basic & diluted 215,337 215,081 215,197 214,601
Outstanding at period end 215,349 215,082 215,349 215,082
(1) Funds from operations, funds from operations per share, net debt (surplus), 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 "Funds from Operations", "Net Debt (Surplus)", "Netback" and "Net Production Expense" in the Reader Advisory below for further information on such terms.
(2) "Continuing Canadian Operations" refers to our remaining Canadian operations in western Canada after completing the sale of our Tunisian operations on August 19, 2014.

Highlights for the three months and year ended December 31, 2015

  • We ended the 2015 year with a strong balance sheet including a working capital surplus of $29.6 million (including cash of $37.9 million) and remained undrawn on our $50.0 million reserve-based revolving credit facility. We expect to remain undrawn on this credit facility through 2016.
  • We implemented cost saving initiatives and deferred certain discretionary capital spending as a result of the decrease in commodity prices. We decreased our overall G&A expenditures by 29% year over year despite incurring $0.8 million in severance costs from staff reductions in the current year. Net production expenses were $15.92 per boe in 2015, a decrease of almost ten percent from 2014.
  • At Birley/Umbach, we drilled three (2.75 net) and completed four (3.50 net) Montney horizontal wells and have delineated a large portion of our 70 gross (59 net) sections of Montney lands. Average costs of between $4.4 million to $4.7 million to drill, complete, equip and tie-in the three wells drilled in 2015, represented a reduction of approximately 40% compared to $7.6 million in 2014.
  • Infrastructure investment at Birley/Umbach included $16.1 million for the completion of the majority of the 25 mmcf/d first phase expansion of our compression facility. The facility came on-stream in February 2016 enabling us to produce from five of the six wells we have drilled at Birley/Umbach. We added 7.6 mmboe of proved plus probable Montney reserves at Birley/Umbach and achieved a company record low all-in Finding, Development and Acquisition Costs (including Future Development Capital) of $5.75 per boe.
  • We completed the disposition of several non-core properties during 2015 for net proceeds of $42.8 million. These proceeds, in addition to our funds from operations of $9.0 million for the year, allowed us to fully fund our capital program for 2015, while increasing our net surplus by 3% over the prior year.
  • We exited 2015 with approximately 4,472 boe/d of production. However, with the start-up of our Birely/Umbach facility in mid-February our production increased to approximately 7,300 boe/d. We recently shut in approximately 1,250 boe/d of non-Montney production in northeastern British Columbia as a result of recent decreases in natural gas prices in northeastern British Columbia, specifically at Station 2. Additionally, production recently decreased by 250 boe/d due to a third-party facility turnaround anticipated to be completed prior to April 2016.

2015 Financial Results

Throughout 2015, the overall driver of our financial results was the impact of falling commodity prices. These lower prices drove decreases in our production volumes through the voluntary shut-in of wells and impacted our decreased revenues for 2015.

Production in the fourth quarter of 2015 averaged 3,928 boe/d, down 54% from the same period in 2014. The decrease is attributed to property dispositions, third party plant restrictions and turnarounds and ongoing pipeline service restrictions. However, an increase in our access to pipeline capacity combined with modestly improved natural gas pricing in British Columbia and the completion of our Birley compressor expansion, resulted in increased production to approximately 7,300 boe/d in mid-February. Subsequently, this production has decreased in early March by approximately 1,250 boe/d as a result of additional voluntary shut-ins related to lower pricing and 250 boe/d due to a third-party facility turnaround, resulting in current production of 5,800 boe/d.

Our year-over-year and fourth quarter petroleum and natural gas revenues were down approximately 71% and 63%, respectively, from the same periods of 2014 as a result of a lower realized weighted average commodity prices and lower volumes. Crude oil prices began to decrease significantly late in 2014 as a result of an oversupply in the crude oil market. An increase in natural gas supply and ongoing pipeline service restrictions and reduced system capacity in northeastern British Columbia contributed to volatile natural gas price fluctuations.

Our full year net production expense (operating costs) decreased by almost 36% to $32.8 million from $51.0 million in 2014. In addition to our on-going review of our cost structure, production costs have decreased as a result of our 2014 and 2015 property dispositions, the voluntary shut-in of relatively higher operating costs/lower netback wells, the impact of the temporary and voluntary shut-in of natural gas production due to lower commodity prices in British Columbia (including our recently developed properties at Birley/Umbach), and a one-time equalization from an operating partner.

Our year-over-year netback decreased by 81% in 2015 as compared to 2014 and decreased 67% in the fourth quarter of 2015 compared to the fourth quarter 2014 as result of a decrease in realized commodity prices and the effect of a decrease in production volumes relative to fixed costs.

Funds from operations for the fourth quarter and year ended 2015 decreased by 75% and 81% to $1.5 million and $9.0 million, respectively, compared to the same periods in 2014 as a result of lower commodity prices. These decreases were offset by lower financing charges as a result of having no outstanding debt throughout the entire year and, for the year ended, having higher realized gains on our derivative contracts as a result of falling commodity prices.

Our reported net loss from continuing operations for the year ended 2015 included a $75 million impairment charge booked during the third quarter of 2015 compared to a $63.5 million impairment charge booked during the fourth quarter of 2014. This impairment was attributable to lower forward commodity pricing. For the year ended 2015, an increase in gains on property dispositions partially offset the net loss from continuing operations.

2015 Operational Results

As commodity prices continued to weaken throughout 2015, we remained focused on cost savings and implementing a strategic capital program which allowed us to take advantage of lower service and supplier pricing. Even with a contracted capital program in 2015 we continued to prudently delineate our large Montney position at Birley/Umbach and delivered strong results with improved capital efficiencies along with receiving positive technical revisions as a result of wells performing above type curve estimates. We drilled a total of three horizontal operated wells (2.75 net) targeting the Montney on our Birley/Umbach property. All three of these wells, plus another Birley/Umbach well (0.75 net) drilled in 2014 were completed in 2015. As previously announced, initial production and test rates from the wells have performed well and the average drill, complete, equip and tie-in costs of between $4.4 million and $4.7 million per well represented a significant decrease over the average costs in 2014 of $7.6 million per well. We substantially completed the first phase 25 mmcf/d expansion of our Birley/Umbach compressor during 2015, which came on-stream in mid-February 2016. This expansion eliminated the need to continue using a rental compressor at this facility and resulted in a net increase to our throughput capacity to 29 mmcf/d, with production currently from five of the six wells we have drilled to date. Birley/Umbach natural gas volumes averaged approximately 18 mmcf/d of gross raw throughput through the new 25 mmcf/d compression facility during the last 12 days of February 2016. Current throughput is estimated at 16.1 mmcf/d gross raw gas. One well, A-60-K (0.75 net), remains shut-in due to field gathering system constraints and has productive capacity of approximately 3.0 mmcf/d gross raw gas.

Results from our producing Birley/Umbach wells, for the week of February 22-28, 2016 are as follows:

Well Working Interest
(%)
Average Gross
Production Rate
(boe/d)
Birley B-071-F/094-H-03 74.55 576
Birley A-73-L/094-H-03 74.55 432
Birley B-04-K/094-H-03 100.00 693
Birley C-73-K/94-H-03 100.00 894
Birley B-72-F/94-H-03 74.55 754

Our future growth potential at Birley/Umbach is significant with up to 280 gross (236 net) potential upper Montney locations (undrilled - 274 gross (231 net)) with additional future middle and lower Montney potential over a 240 metre thick Montney interval.

Outlook

Our capital program for the first half of 2016 includes the final commissioning of the recently expanded Birley compressor which occurred in mid-February. However, as a result of unfavourable commodity pricing, we have elected to defer the previously announced, capital program originally slated for the first half of 2016, including $8 million to drill, complete, equip and tie-in four (3.5 net) Dunvegan oil wells at Albright in the Grande Prairie area. This drilling was to commence in the first quarter, with anticipated production to occur in April or May 2016.

Natural gas pricing in British Columbia will be a key determinant in the amount of capital, if any, dedicated to our Birley/Umbach development in the second half of 2016. We realized material cost savings at Birley/Umbach in 2015 by conducting completion operations after spring break-up. Subject to commodity pricing, in an effort to again capture these seasonal cost savings in 2016, and to accommodate the short term facility constraints associated with the high initial production rates from wells brought into our new facility in February, our Birley/Umbach drilling program is anticipated to commence in the second half of 2016 (3 gross wells, 2.67 net) for a cost of approximately $13.8 million. The total 2016 capital program is anticipated at $22.0 million - $23.0 million, dependent on economic factors.

In 2015, we confirmed the scale of the Montney resource across our Birley/Umbach lands and are committed to developing this core asset prudently and efficiently during this period of depressed natural gas prices. We have set a capital program that addresses the need for flexibility in a challenging business environment. We continue to maintain one of the strongest balance sheets among our peers, which will allow us the optionality to quickly adjust our capital spending in response to market factors while still adding value for our shareholders by expanding the size of our resources with a selective drilling and completion program. We will continue to focus on capital discipline and cost control while maintaining our commitment to safety.

Our 2016 guidance is based on a three well Birley/Umbach capital program (dependent on economic factors) as follows:

($ millions, except boe/d) 2016 Guidance
Average production (boe/d) 5,700 - 5,800
Exit production (boe/d) 7,300 - 7,500
Capital expenditures $22 - $23

About Chinook Energy Inc.

Chinook is a Calgary-based public oil and natural gas exploration and development company with multi-zone conventional production and resource plays in western Canada.

Reader Advisory

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: our expectation of our future growth potential at Birley/Umbach, the anticipated timing of the completion of a third-party facility turnaround, the productive capacity of our shut-in well at Birley/Umbach, our expectation that our cost saving and optimization initiatives will be effective in 2016, our budgeted capital program in fiscal 2016, future exploration and development activities and how we intend to manage our company during 2016 as well as our expectations regarding production and capital expenditures set out in the table under the heading "Outlook".

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 past operations, future capital expenditure levels, future oil and natural gas prices, future 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, anticipated production volumes, our ability to replace and expand production and reserves through exploration and development activities, certain cost assumptions, the results of negotiations and the plans of our partners in certain of our areas; that the budgeted 2016 capital amount set forth herein, which is subject to the discretion of our Board of Directors, will not be amended in the future, 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, our Board of Directors may amend the 2016 capital program based on its discretion; 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.

Netback

The reader is cautioned that this news release contains the term netback, which is not a recognized measure under IFRS and is calculated as a period's sales of petroleum and natural gas, net of royalties less net production and operating expenses and G&A expense as divided by the period's sales volumes. Management uses this measure to assist them in understanding our profitability relative to current commodity prices and it provides an analysis tool to benchmark changes in operational performance against prior periods and to peers on a comparable basis. 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. Management uses net production expense to determine the current periods' cash cost of operating expenses. Our method of calculating this measure may differ from other companies, and accordingly, it may not be comparable to measures used by other companies.

Funds from Operations

The reader is cautioned that this news release contains the term funds from operations, which is not a recognized measure under IFRS and is calculated as cash flow from continuing operations adjusted for changes in non-cash working capital related to continuing operations, exploration and evaluation expenses and decommissioning obligation expenditures related to continuing operations. Management believes that funds from operations is a key measure to assess our ability to finance capital expenditures and debt repayments. Readers are cautioned, however, that this measure should not be construed as an alternative to other terms such as cash flow from operating activities, net income or other measures of financial performance calculated in accordance with IFRS. 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 Debt (Surplus)

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 working capital excluding mark-to-market derivative contracts, current portion of decommissioning obligation and assets and liabilities held for sale. Working capital excluding mark-to-market derivative contracts, current portion of decommissioning obligation and assets and liabilities held for sale is calculated as current assets less current liabilities both of which exclude derivative contracts and assets and liabilities held for sale and current liabilities excludes any current portion of debt and decommissioning obligation. Management uses net debt (surplus) to assist them in understanding our liquidity at specific points in time. Mark-to-market derivative contracts are excluded from working capital, in addition to net debt (surplus), as management intends to hold each contract through to maturity of the contract's term as opposed to liquidating each contract's fair value or less.

Future Oriented Financial Information

This news release, in particular the information in respect of anticipated capital expenditures set out in the table under the heading "Outlook", may contain Future Oriented Financial Information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by our management to provide an outlook of our activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions including the assumptions discussed under the heading "Forward-Looking Statements" and assumptions with respect to production rates and commodity prices. The actual results of our operations and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. Our management believes that the FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments.

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, 2015 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 274 gross (231 net) additional drilling locations identified herein, 9 gross (7.7 net) are proved locations, 6 gross (5.1 net) are probable locations and 259 gross (218.2 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 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.

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 Inc.
Walter Vrataric
President and Chief Executive Officer
(403) 261-6883

Chinook Energy Inc.
Jason Dranchuk
Vice President, Finance and Chief Financial Officer
(403) 261-6883
www.chinookenergyinc.com

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Chinook Energy Inc. Announces Its Audited Year-End Financial Results and 2016 Capital Program

CALGARY, ALBERTA--(Marketwired - March 7, 2016) - Chinook Energy Inc. ("our", "we", "us" or "Chinook") (TSX:CKE) is pleased to announce its audited year-end financial results and 2016 capital program. The audited financial results presented herein …

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