CALGARY, ALBERTA — (Marketwired) — 11/02/17 — Commenting on Company results, Steve Laut, President of Canadian Natural (TSX: CNQ)(NYSE: CNQ) stated, “Canadian Natural has reached a major milestone with the successful completion of the Phase 3 expansion at our world class Horizon Oil Sands Mining and Upgrading asset, a significant event. The completion of the Phase 3 expansion also marks the final step of our transition to a long life low decline asset base. High value upgraded products will represent approximately 45% of total corporate liquids production in the fourth quarter of 2017 and approximately 70% of our liquids production volumes are from long life low decline assets, and will increase going into 2018. Our long life low decline assets combined with our strong portfolio of conventional E&P assets will drive significant sustainable free cash flow providing flexibility for continued balanced capital allocation to our four pillars; economic resource development, returns to shareholders, opportunistic acquisitions and balance sheet strength, with continued focus on increasing return on equity and capital employed.”
Canadian Natural–s Chief Operating Officer, Tim McKay, added, “The Horizon Phase 3 expansion and the turnaround and tie-in activities are complete and were on budget, strong results for this large scale, world class project. Optimization and reliability work on the fractionation tower, the vacuum distillate unit and diluent recovery unit furnaces were also successfully completed during the turnaround on time and on budget. With completion of the Horizon turnaround, startup activities are underway and are going as expected, with production ramping up through November and December.
In the third quarter, operations across our balanced asset base were strong as quarterly production reached record levels for the second straight quarter at just under 1,040,000 BOE/d, up 14% from the second quarter of 2017. Production increases were achieved as a result of strong utilization and high reliability at the Athabasca Oil Sands Project for a full quarter and drilling programs that delivered as expected at Pelican Lake, primary heavy crude oil and light crude oil. Our continued focus on effectiveness and efficiencies delivered strong quarterly operating costs at AOSP of $24.60/bbl of synthetic crude oil.”
Canadian Natural–s Chief Financial Officer, Corey Bieber, continued, “The Company was able to achieve funds flow from operations of approximately $1.7 billion in the quarter, contributing to absolute debt reduction of $350 million when compared to second quarter 2017 debt levels, even as we funded the Pelican Lake acquisition in the quarter. Liquidity improved to $3.9 billion and debt metrics strengthened at the end of the quarter. Debt to EBITDA decreased to 3.0x at quarter end, while debt to book capital remains in the Company–s targeted range at 42%. With completion of the Horizon Phase 3 expansion, strong reliability at AOSP and continued focus on effective operations across our asset base, the Company will generate significant growing sustainable free cash flow, allowing for balanced capital allocation that includes a focus on continued strengthening of our balance sheet.”
(1) Adjusted net earnings (loss) from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation of this measure is discussed in the Management–s Discussion and Analysis (“MD&A”).
(2) Funds flow from operations (formally cash flow from operations) is a non-GAAP measure that the Company considers key as it demonstrates the Company–s ability to fund capital reinvestment and debt repayment. The derivation of this measure is discussed in the MD&A.
(3) For additional information and details, refer to the net capital expenditures table in the Company–s MD&A.
(4) A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
– The Company–s corporate production volumes averaged a record 1,036,499 BOE/d in Q3/17, representing 14% and 41% increases from Q2/17 and Q3/16 levels, respectively.
– Canadian Natural–s corporate crude oil and NGLs production volumes averaged a record 759,189 bbl/d representing 19% and 65% increases from Q2/17 and Q3/16 levels respectively. Crude oil and NGLs production volume increases were primarily due to high reliability and strong production from the Horizon Phase 2B expansion and a full quarter of production from the Athabasca Oil Sands Project (“AOSP”).
– Canadian Natural generated funds flow from operations of $1,675 million in Q3/17, comparable to Q2/17 and an increase of $654 million over Q3/16 levels.
– The Company has generated significant free cash flow year to date of approximately $1.2 billion after net capital expenditures, including the Company–s Pelican Lake acquisition expenditures, and excluding the AOSP acquisition expenditures.
– The Company–s strong financial performance in the quarter resulted in Q3/17 ending debt being reduced by approximately $350 million from Q2/17 levels. Additionally, liquidity increased by approximately $300 million over the same period, after capital expenditures relating to the Pelican Lake acquisition. Debt to book capitalization decreased to 42% and debt to adjusted EBITDA strengthened to 3.0x.
– For Q3/17, the Company had net earnings of $684 million compared to net earnings of $1,072 million in Q2/17 and a net loss of $326 million in Q3/16. Adjusted net earnings from operations was $229 million in Q3/17, compared to adjusted net earnings of $332 million in Q2/17 and an increase of $584 million from the adjusted net loss of $355 million in Q3/16.
– At the AOSP, high reliability continued in Q3/17, the Company–s first full quarter of operations. Strong quarterly production of approximately 282,700 bbl/d (197,900 bbl/d net to Canadian Natural) of AOSP synthetic crude oil (“SCO”) was realized in Q3/17. A combination of strong production and modest integration gains resulted in operating costs of $24.60/bbl for upgraded products.
— Subsequent to quarter end, Canadian Natural successfully completed planned pit stops at both the Jackpine and Muskeg River mines. The production impacts from the planned pit stops were incorporated in the Company–s quarterly and annual guidance, which remain unchanged.
– At Horizon, Q3/17 production of 156,465 bbl/d of SCO was strong, with high reliability and utilization during the quarter. Q3/17 production decreased from Q2/17 levels by 18%, as Horizon began the planned turnaround activities and the Phase 3 expansion tie-in on September 11, 2017.
— Through safe, steady and reliable operations and a strong focus on continuous improvement, the Company realized average unadjusted operating costs of $25.68/bbl in Q3/17, a strong result given 19 days of planned downtime in the quarter related to the planned major turnaround and tie-in of the Phase 3 expansion. After normalizing for downtime in relation to the planned turnaround, quarterly operating costs reached a record low of $20.24/bbl of SCO in Q3/17.
— During the Company–s planned turnaround, optimization and reliability work on the fractionation tower, vacuum distillate unit (“VDU”) and diluent recovery unit (“DRU”) furnaces was completed on schedule and on budget. Ramp up of the units is currently underway, and progress is going as expected.
— The Horizon Phase 3 expansion was completed subsequent to quarter end, marking the completion of the Company–s transformational transition to a long life low decline asset base.
— Commissioning activities have begun with production ramping up through November and December 2017. Targeted production volumes in December 2017 are expected to be approximately 240,000 bbl/d of SCO. The construction of the Horizon Phase 3 expansion was ahead of schedule and within the cost estimate.
— The Company–s annual 2017 production guidance at Horizon remains unchanged at 170,000 – 184,000 bbl/d, due to the strong production results before the turnaround and targeted production volume ramp up through November and December 2017.
– Thermal in situ operations were strong in Q3/17, with production averaging 122,372 bbl/d, above the midpoint of quarterly guidance, representing 16% and 18% increases from Q2/17 and Q3/16 levels, respectively. Results were strong after the completion of planned turnaround activities in Q2/17 at Primrose and a full quarter of production from the previously announced acquired Peace River assets.
— Kirby South, the Company–s Steam Assisted Gravity Drainage (“SAGD”) project achieved production of 37,157 bbl/d in Q3/17.
— Including energy costs, strong operating costs of $8.94/bbl were achieved in the quarter, a 13% reduction from Q2/17 and in-line with Q3/16 levels. Kirby South–s Steam to Oil Ratio (“SOR”) was 2.7 in Q3/17.
— Primrose production was strong in Q3/17 averaging 80,668 bbl/d. Including energy costs, operating costs of $10.24/bbl were achieved in the quarter.
— The development of the Company–s low pressure steamflood at Primrose East continues as planned. The average production volumes under steamflood were strong in Q3/17 at approximately 43,600 bbl/d, representing an increase of 36% from Q2/17 levels.
– Pelican Lake heavy crude oil production of 47,604 bbl/d in Q3/17 was in-line with Q2/17 and Q3/16 levels, reflecting the low decline nature of this asset. Operations continued to be optimized in the quarter, resulting in record low operating costs of $6.00/bbl in Q3/17, a decrease of 6% from Q2/17 and in-line with Q3/16 levels.
— On September 29, 2017, the Company successfully closed the previously announced Pelican Lake acquisition, adding approximately 19,100 bbl/d of heavy crude oil production. The integration of the assets is proceeding as planned.
– Primary heavy crude oil production averaged 98,564 bbl/d in Q3/17, representing a 10% increase from Q2/17 as a result of the Company–s successful heavy crude oil drilling program and a full quarter of production from the previously announced acquired Cliffdale asset.
– North America light crude oil and NGLs quarterly production averaged 92,676 bbl/d, representing 2% and 3% increases from Q2/17 and Q3/16 levels respectively, as a result of a successful drilling program.
– The Company–s North America natural gas production in Q3/17 averaged 1,593 MMcf/d, in-line with Q2/17 and Q3/16 levels. Operating costs of $1.15/Mcf were achieved in the quarter, a decrease of 2% from Q2/17 levels.
– International quarterly crude oil production volumes were within the Company–s production guidance and averaged 43,608 bbl/d in Q3/17.
– Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. At September 30, 2017 the Company had $3.9 billion of available liquidity, including cash and cash equivalents, an increase of $300 million from Q2/17.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.275 per share payable on January 1, 2018.
– Canadian Natural–s 2018 budget is targeted to be released on November 7, 2017, followed by a webcast with more details on the Company–s current and future plans. Details will be available on our website .
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK sector of the North Sea and Offshore Africa. Canadian Natural–s production is well balanced between light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein collectively referred to as “crude oil”), natural gas and NGLs. This balance provides optionality for capital investments, facilitating improved value for the Company–s shareholders.
Underpinning this asset base is long life low decline production from Horizon mining and upgrading and the AOSP mining and upgrading, thermal in situ oil sands and Pelican Lake heavy crude oil assets. The combination of low decline, low reserve replacement costs, and effective and efficient operations means these assets provide substantial and sustainable cash flow throughout the commodity price cycle.
Augmenting this, Canadian Natural maintains a substantial inventory of low capital exposure projects within its conventional asset base. These projects can be executed quickly and with the right economic conditions, can provide excellent returns and maximize value for shareholders. Supporting these projects is the Company–s undeveloped land base which enables large, repeatable drilling programs; programs that can be optimized over time. Additionally, by owning and operating most of the related infrastructure, Canadian Natural is able to control a major component of its operating cost and minimize production commitments. Low capital exposure projects can typically be easily stopped or started depending upon success, market conditions, or corporate needs.
Canadian Natural–s balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.
– The Company–s total crude oil and natural gas drilling program of 393 net wells for the nine months ended September 30, 2017, excluding strat/service wells, was a significant increase of 291 net wells from the same period in 2016. The change in drilling reflects the flexibility of Canadian Natural–s resource development program and the Company–s disciplined capital allocation process.
North America Exploration and Production
– Quarterly production volumes of North America crude oil and NGLs averaged 238,844 bbl/d in Q3/17, representing a 5% increase from Q2/17 and in-line with Q3/16 levels.
– Pelican Lake heavy crude oil production of 47,604 bbl/d in Q3/17 was in-line with Q2/17 and Q3/16 levels, reflecting the low decline nature of this asset, given little to no drilling in 2015 and 2016. Operations continued to be optimized in the quarter, resulting in record low operating costs of $6.00/bbl in Q3/17, a decrease of 6% and 1% from Q2/17 and Q3/16 levels, respectively.
— On September 29, 2017, the Company successfully closed the previously announced Pelican Lake acquisition, adding approximately 19,100 bbl/d of heavy crude oil production. The integration of the assets is proceeding as planned.
— Drilling activities at Pelican Lake saw 6 net wells drilled in Q3/17. In the first nine months of 2017, drilling activity increased to 17 net wells. Results from the Company–s drilling program have been as expected, with current total production of approximately 1,700 bbl/d from the new drills.
– Primary heavy crude oil production averaged 98,564 bbl/d in Q3/17, representing a 10% increase from Q2/17 as a result of the Company–s successful heavy crude oil drilling program and a full quarter of production from the previously announced acquired Cliffdale asset.
— Drilling continued in primary heavy crude oil in Q3/17 with 136 net wells drilled, an increase of 97 wells from Q2/17. Early results of the Q3/17 heavy crude oil drilling program have been as expected, with the wells ramping up to the targeted 50 bbl/d per well.
– North America light crude oil and NGLs quarterly production averaged 92,676 bbl/d, representing 2% and 3% increases from Q2/17 and Q3/16 levels respectively, as a result of a successful drilling program. Operating costs in the quarter averaged $14.45/bbl.
– The Company–s 2017 North America E&P crude oil and NGLs annual production guidance remains unchanged and is targeted to range from 236,000 bbl/d – 246,000 bbl/d.
– Thermal in situ operations were strong in Q3/17, with production averaging 122,372 bbl/d, above the midpoint of quarterly guidance, representing 16% and 18% increases from Q2/17 and Q3/16 levels, respectively. Results were strong after the completion of planned turnaround activities in Q2/17 at Primrose and a full quarter of production from the previously announced acquired Peace River assets.
— Kirby South, the Company–s SAGD project achieved production of 37,157 bbl/d in Q3/17.
— Including energy costs, strong operating costs of $8.94/bbl were achieved in the quarter, a 13% reduction from Q2/17 and in-line with Q3/16 levels. Kirby South–s SOR was 2.7 in Q3/17.
— Steam circulation is targeted to begin in Q4/17 for the 8 producer and 3 injection wells that were drilled in Q3/17, with production targeted in Q1/18.
— Primrose production was strong in Q3/17 averaging 80,668 bbl/d. Including energy costs, operating costs of $10.24/bbl were achieved in the quarter.
— The development of the Company–s low pressure steamflood at Primrose East continues as planned. The average production volumes under steamflood were strong in Q3/17 at approximately 43,600 bbl/d, representing an increase of 36% from Q2/17 levels.
— At Kirby North, the project is trending ahead of schedule and cost performance is trending below budget. Civil works at the plant site are nearing completion and the major mechanical work is ramping up with module and equipment setting underway. Project construction manpower is currently at 220 and will be increasing to over 300 in early 2018.
– The Company–s 2017 thermal in situ annual production guidance remains unchanged and is targeted to range between 112,000 bbl/d – 122,000 bbl/d.
– The Company–s North America natural gas production in Q3/17 averaged 1,593 MMcf/d, in-line with Q2/17 and Q3/16 levels. Operating costs of $1.15/Mcf were achieved in the quarter, a decrease of 2% from Q2/17 levels.
— The decrease in natural gas production during the first nine months of 2017 from the previous comparable period was primarily due to shut-in production volumes of approximately 27 MMcf/d related to low natural gas prices and 41 MMcf/d related to the impact of reliability issues at a third party facility. Natural gas production at the third party facility restarted at the end of July, with plant operations reinstated to near full capacity in the latter half of August 2017. In the month of September 2017 the plant operated reliably at 130 MMcf/d.
– The Company–s 2017 total natural gas annual production guidance remains unchanged and is targeted to range from 1,655 MMcf/d – 1,705 MMcf/d.
– International quarterly crude oil production volumes were within the Company–s production guidance and averaged 43,608 bbl/d in Q3/17.
— In the North Sea, the Company–s continued focus on production enhancements, increased reliability and water flood optimization resulted in average production volumes of 24,832 bbl/d in Q3/17 as expected, a decrease of 6% from Q2/17 levels and a 6% increase from Q3/16 levels.
— North Sea quarterly crude oil operating costs were $35.72/bbl, representing a reduction of 9% from Q3/16 levels.
— Offshore Africa production volumes averaged 18,776 bbl/d in Q3/17 as expected, an 8% decrease from Q2/17 levels, primarily due to normal well declines, as well as down time relating to the successfully completed planned turnaround in Q3/17 at Baobab.
— Production expense related to the Baobab and Espoir fields in Cote d–Ivoire, decreased to $12.51/bbl in Q3/17, a reduction of 28% from Q2/17. After incorporating production from the Olowi field in Gabon, production expense was $29.24/bbl.
– The Company–s 2017 International annual production guidance remains unchanged and is targeted to range from 43,000 bbl/d – 49,000 bbl/d.
(1) During the Q3/17, no SCO production was consumed internally as diesel (Q2/17 – 438 bbl/d; Q3/16 – 1,464 bbl/d; nine months ended September 30, 2017 – 287 bbl/d; nine months ended September 30, 2016 – 2,083 bbl/d).
– At Horizon, Q3/17 production of 156,465 bbl/d of SCO was strong, with high reliability and utilization during the quarter. Q3/17 production decreased from Q2/17 levels by 18%, as Horizon began the planned turnaround activities and the Phase 3 expansion tie-in on September 11, 2017.
— Through safe, steady and reliable operations and a strong focus on continuous improvement, the Company realized average unadjusted operating costs of $25.68/bbl in Q3/17, a strong result given 19 days of planned downtime in the quarter related to the planned major turnaround and tie-in of the Phase 3 expansion. After normalizing for downtime in relation to the planned turnaround, quarterly operating costs reached a record low of $20.24/bbl of SCO in Q3/17.
— During the Company–s planned turnaround, optimization and reliability work on the fractionation tower, VDU and DRU furnaces was completed on schedule and on budget. Ramp up of the units is currently underway, and progress is going as expected.
— On September 11, 2017, during ramp down at Horizon for the planned turnaround, a fire occurred at an electrical control building on the plant site. Repairs have now been successfully completed, however an extra 7 days of incremental time was needed in addition to the planned 45 day turnaround.
— Overall the turnaround and additional work related to the electrical control building was completed very effectively and efficiently, with overall costs for both the turnaround and work allocated to the electrical building being within the 45 day turnaround budget.
— The Horizon Phase 3 expansion was completed subsequent to quarter end, marking the completion of the Company–s transition to a long life low decline asset base.
— Commissioning activities have begun with production ramping up through November and December 2017. Targeted production volumes in December 2017 are expected to be approximately 240,000 bbl/d of SCO. The construction of the Horizon Phase 3 expansion was ahead of schedule and within the cost estimate.
– Directive 85 (formerly Directive 74) implementation at the Horizon project remains on track and was 72% physically complete as at September 30, 2017. This project includes research into tailings management and investments in technological advancements to advance the cessation of the use of traditional tailings ponds.
– The Company–s annual 2017 production guidance at Horizon remains unchanged at 170,000 – 184,000 bbl/d, due to the strong production results before the turnaround, and strong targeted production volume ramp up in Q4/17.
(1) Consists of heavy and light synthetic crude oil products.
– At the AOSP, high reliability continued in Q3/17, the Company–s first full quarter of operations. Strong quarterly production of approximately 282,700 bbl/d (197,900 bbl/d net to Canadian Natural) of AOSP SCO was realized in Q3/17. A combination of strong production and modest integration gains resulted in operating costs of $24.60/bbl of upgraded products.
— In early Q4/17, Canadian Natural successfully completed planned pit stops at both the Jackpine and Muskeg River mines. The production impacts from the planned pit stops were incorporated in the Company–s quarterly and annual guidance.
– The Company–s 2017 AOSP annual production guidance remains unchanged and is targeted to range from 102,000 bbl/d – 116,000 bbl/d of AOSP SCO.
(1) West Texas Intermediate (“WTI”).
(2) Western Canadian Select (“WCS”).
(3) Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.
– WTI averaged US$48.19/bbl in Q3/17, an increase of 7% from US$44.94/bbl in Q3/16, and in-line with Q2/17.
– Crude oil sales contracts for the Company–s North Sea and Offshore Africa segments are typically based on Brent pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$51.76/bbl in Q3/17, an increase of 13% from US$45.76/bbl in Q3/16, and an increase of 3% from $50.24/bbl in Q2/17.
– WTI and Brent pricing continued to reflect volatility in supply and demand factors and geopolitical events.
– The WCS Heavy Differential averaged US$9.94/bbl in Q3/17, a decrease of 26% from US$13.49/bbl in Q3/16, and a decrease of 11% from $11.11/bbl in Q2/17. The WCS Heavy Differential largely reflects US Gulf Coast pricing, adjusted for transportation costs. The narrowing of the differential in Q3/17 compared with Q2/17 primarily reflects seasonality.
– Canadian Natural contributed approximately 196,000 bbl/d of its heavy crude oil stream to the WCS blend in Q3/17. The Company remains the largest contributor to the WCS blend, accounting for 47% of the total blend.
– The SCO price averaged US$48.83/bbl in Q3/17, an increase of 7% from $45.63/bbl in Q3/16, and in-line with Q2/17. The fluctuations in SCO pricing from the comparable periods were primarily due to changes in WTI benchmark pricing.
– AECO natural gas prices averaged $1.94/GJ in Q3/17, a decrease of 7% from $2.08/GJ in Q3/16, and a decrease of 26% from $2.63/GJ in Q2/17. The fluctuations in natural gas prices in Q3/17 compared with the Q3/16 and Q2/17 reflected third party pipeline maintenance, reducing flow capability of natural gas to discretionary storage and export markets.
– The North West Redwater refinery, upon completion, will strengthen the Company–s position by providing a competitive return on investment and by adding 50,000 bbl/d of bitumen conversion capacity in Alberta and create demand for 79,000 bbl/d of dilbit that will not require export pipelines, which will help reduce pricing volatility in all Western Canadian heavy crude oil. The Company has a 50% interest in the North West Redwater Partnership. For project updates, please refer to: .
FINANCIAL REVIEW
The Company continues to implement proven strategies and its disciplined approach to capital allocation. As a result, the financial position of Canadian Natural remains strong. Canadian Natural–s funds flow generation, credit facilities, US commercial paper program, diverse asset base and related flexible capital expenditure programs all support a flexible financial position and provide the appropriate financial resources for the near-, mid- and long-term.
– The Company–s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved record production levels of 1,036,499 BOE/d in Q3/17, with approximately 98% of total production located in G7 countries.
– The Company has generated significant free cash flow year to date of approximately $1.2 billion after net capital expenditures including the Company–s Pelican Lake acquisition expenditures, and excluding AOSP acquisition expenditures.
– Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. At September 30, 2017 the Company had $3.9 billion of available liquidity, including cash and cash equivalents, an increase of $300 million from Q2/17.
– Balance sheet strength continues to be a focus of the Company with strong financial performance in the quarter resulting in a Q3/17 ending debt reduction of approximately $350 million, while liquidity increased by approximately $300 million.
— Important metrics improved with debt to book capitalization within the Company–s targeted operating range at 42% and debt to adjusted EBITDA strengthening to 3.0x, as at September 30, 2017.
– In addition to its strong funds flow, capital flexibility and access to debt capital markets, Canadian Natural has additional financial levers at its disposal to effectively manage its liquidity. As at September 30, 2017, these financial levers include the Company–s third party equity investments of approximately $888 million.
– At September 30, 2017, 50,000 GJ/d of natural gas volumes were hedged using AECO swaps through to October 31, 2017. Additionally, 67,500 bbl/d of crude oil volumes were hedged through to December 31, 2017 using WTI costless collars with a floor of US$50.00 and ceiling of US$60.10. For full hedging disclosure please see the Company–s website.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.275 per share payable on January 1, 2018.
OUTLOOK
The Company forecasts annual 2017 production levels to average between 663,000 and 717,000 bbl/d of crude oil and NGLs and between 1,655 and 1,705 MMcf/d of natural gas, before royalties. Q4/17 production guidance before royalties is forecast to average between 736,000 and 772,000 bbl/d of crude oil and NGLs and between 1,700 and 1,750 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company–s website at .
Canadian Natural–s annual 2017 capital expenditures are targeted to be approximately $4.9 billion.
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule”, “proposed” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, operating costs, capital expenditures, income tax expenses and other guidance provided throughout this Management–s Discussion and Analysis (“MD&A”), constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansions, the Athabasca Oil Sands Project (“AOSP”), Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the construction and future operations of the North West Redwater bitumen upgrader and refinery, and construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or synthetic crude oil (“SCO”) that the Company may be reliant upon to transport its products to market also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.
In addition, statements relating to “reserves” are deemed to be 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. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and natural gas liquids (“NGLs”) reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company–s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company–s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company–s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs;
the Company–s and its subsidiaries– ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of the Company–s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company–s bitumen products; availability and cost of financing; the Company–s and its subsidiaries– success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies and assets, including the interests in the AOSP as well as additional working interests in certain other producing and non-producing oil and gas properties (the “other assets”), acquired by the Company on May 31, 2017; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company–s provision for taxes; and other circumstances affecting revenues and expenses.
The Company–s operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company–s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company–s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management–s estimates or opinions change.
Special Note Regarding Currency, Production and Non-GAPP Financial Measures
This release should be read in conjunction with the Company–s Management–s Discussion and Analysis (“MD&A”) and the unaudited interim Consolidated Financial Statements for the three months and nine months ended September 30, 2017 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2016.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company–s unaudited interim consolidated financial statements for the period ended September 30, 2017 and MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. This release includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings (loss) from operations, funds flow from operations (previously referred to as cash flow from operations), and adjusted cash production costs. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings (loss) and cash flows from operating activities, as determined in accordance with IFRS, as an indication of the Company–s performance. The non-GAAP measures adjusted net earnings (loss) from operations and funds flow from operations are reconciled to net earnings (loss), as determined in accordance with IFRS, in the “Financial Highlights” section of the Company–s MD&A. The non-GAAP measure funds flow from operations is also reconciled to cash flows from operating activities. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization are included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of the Company–s MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of the Company–s MD&A.
A Barrel of Oil Equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of the Company–s MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO.
Production volumes and per unit statistics are presented throughout this release on a “before royalty” or “gross” basis, and realized prices are net of blending costs and exclude the effect of risk management activities. Production on an “after royalty” or “net” basis is also presented for information purposes only in the Company–s MD&A.
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time on Thursday, November 2, 2017.
The North American conference call number is 1-866-521-4909 and the outside North American conference call number is 001-647-427-2311. Please call in 10 minutes prior to the call starting time.
An archive of the broadcast will be available until 6:00 p.m. Mountain Time, Thursday, November 16, 2017. To access the rebroadcast in North America, dial 1-800-585-8367. Those outside of North America, dial 001-416-621-4642. The conference archive ID number is 87609953.
The conference call will also be Webcast live on the internet and may be accessed on the home page our website at .
Contacts:
Canadian Natural Resources Limited
2100, 855 – 2nd Street S.W.
Calgary, Alberta, T2P 4J8 Canada
Phone: (403) 514-7777
Email:
Steve W. Laut
President
Corey B. Bieber
Chief Financial Officer and Senior Vice-President, Finance
Mark A. Stainthorpe
Director, Treasury and Investor Relations