Canadian Natural Resources Limited Announces 2016 Third Quarter Results
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 11/03/16 -- Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on third quarter 2016 results, Steve Laut, President of Canadian Natural (TSX: CNQ) (NYSE: CNQ) stated, "Canadian Natural''s diverse and balanced asset portfolio delivered quarterly production volumes of 735,212 BOE/d that were within the Company''s Q3/16 guidance. We continued our focus on lowering our cost structures, which helped to achieve the Company''s cash flow from operations of $1.021 billion during the quarter.
The planned major turnaround at our Horizon Oil Sands Mining and Upgrading project was successfully completed in the third quarter of 2016 and tie-in of the 45,000 bbl/d of additional production from the Phase 2B expansion went as planned. Current production volumes at Horizon are approximately 175,000 bbl/d as we executed the Phase 2B expansion start-up in early October, slightly ahead of the targeted start-up date. We anticipate delivering targeted production rates in excess of 182,000 bbl/d of SCO being achieved imminently.
Also, the Company''s Board of Directors has authorized Management to re-initiate the development of the Kirby North thermal project with engineering and procurement commencing in 2017, with a focus on finding opportunities to continue to reduce construction costs to completion. The project will add 40,000 bbl/d of targeted production volumes to Canadian Natural''s thermal oil sands portfolio. Kirby North will be targeted to deliver first steam-in in 2019 with first oil targeted in 2020.
With the excellent progress of the Horizon expansion and the recommencement of Kirby North development, we are on track to deliver substantial and sustainable cash flow in the near-, mid- and long-term as we continue our transition to a longer-life, low decline asset base. As we go forward, Canadian Natural becomes a significantly more robust and sustainable company. Endorsing confidence in our ability to deliver the remaining elements of this transition, the Company''s Board of Directors increased the quarterly dividend on common shares by roughly 9% to 25 cents per quarter."
Canadian Natural''s Chief Financial Officer, Corey Bieber, continued, "During the quarter, our financial position remained resilient reflecting solid production and increased cash flow. Supplementing the Company''s liquidity, we successfully completed a $1.0 billion bond issuance in August.
Canadian Natural has reached a significant milestone with the recent additional production and incremental cash flows associated with the Company''s completion of Horizon Phase 2B, being a major addition to the Company''s balanced asset portfolio. Coupled with lower Horizon project capital, our free cash flow profile significantly changes, making us more sustainable through the commodity price cycle. The targeted completion of the Horizon expansion to 250,000 bbl/d of SCO in 2017 will further increase our long-life, low decline asset profile. In addition, we have made great strides throughout the entire company in lowering overall costs to reflect the new commodity price paradigms and we continue to target new savings and innovation to augment our sustainability."
QUARTERLY HIGHLIGHTS
(1) Adjusted net (loss) earnings 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) 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) 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 staged start-up of the Horizon Oil Sands ("Horizon") Phase 2B expansion is substantially complete with October Synthetic Crude Oil ("SCO") production volumes averaging approximately 161,000 bbl/d, a new monthly production record. Production rates are very strong with current production volumes of approximately 175,000 bbl/d of SCO and imminent ramp up to targeted production rates in excess of 182,000 bbl/d of SCO.
- For the first nine months of 2016, Horizon project capital costs totaled $1.405 billion, with total Horizon project capital now targeted to be approximately $1.920 billion in 2016 versus the Company''s original 2016 budget range of $1.890 billion to $1.990 billion. In 2017, Horizon project capital costs are targeted to be approximately $1 billion for Phase 3 completion, which is targeted to add incremental production volumes of 80,000 bbl/d of SCO in Q4/17. The addition of Phase 3 will mark the completion of the Horizon expansion with targeted design capacity in excess of 250,000 bbl/d of SCO, and targeted operating costs below C$25.00/bbl (US$20.00/bbl).
- At September 30, 2016, the Horizon Phase 3 expansion reached 87% physical completion. Within the scope of work for the combined hydrotreater, all modules have been installed and module interconnections are well advanced. Phase 3 includes the addition of an ore preparation plant, extraction trains, the combined hydrotreater and a sulphur recovery unit. Phase 3 remains on schedule for targeted start-up in Q4/17.
- Canadian Natural realized cash flow from operations in Q3/16 of $1,021 million, an increase from $938 million in Q2/16 primarily reflecting the impact of higher natural gas netbacks, higher North America Exploration and Production ("E&P") crude oil and NGL sales volumes and lower cash tax expense. The decrease from $1,533 million in Q3/15 primarily reflects lower North America crude oil and NGL sales volumes, largely due to the planned turnaround activities completed at Horizon and Primrose, and lower commodity prices resulting in lower North America netbacks.
- For Q3/16, the Company had a net loss of $326 million compared to a net loss of $111 million in Q3/15 and net loss of $339 million in Q2/16. Adjusted net loss from operations was $355 million in Q3/16 compared to adjusted net earnings of $113 million in Q3/15 and an adjusted net loss of $210 million in Q2/16. Changes in adjusted net earnings primarily reflect the changes in cash flow from operations.
- Canadian Natural continues to realize excellent results from its commitment to effective and efficient operations, resulting in approximately $451 million of operating cost savings for the first nine months of 2016 over the same period in 2015.
- Canadian Natural''s corporate production volumes averaged 735,212 BOE/d, as expected, in Q3/16, representing a 13% and 6% decrease from Q3/15 and Q2/16 levels respectively. As expected, Q3/16 corporate production volumes were lower than Q3/15 and Q2/16 levels primarily due to the planned turnaround activities completed at Horizon and Primrose during Q3/16.
-- Q3/16 primary heavy crude oil production averaged 102,484 bbl/d, expected decreases of 18% and 1% from Q3/15 and Q2/16 levels respectively. During the quarter, Canadian Natural increased its primary heavy crude oil drilling activity to 85 net wells, partially offsetting natural production declines.
-- At Pelican Lake, Canadian Natural''s leading edge polymer flood, Q3/16 production volumes of 47,608 bbl/d were 6% lower than Q3/15 levels and relatively consistent with Q2/16 levels. Overall performance has been very good and notably, production volumes have been maintained despite the curtailment of drilling activity at Pelican Lake since Q4/14 due to capital allocation choices.
-- Thermal in situ quarterly production averaged 103,481 bbl/d in Q3/16, as expected, representing a decrease of 22% from Q3/15 and an increase of 11% from Q2/16. The increase in production volumes over Q2/16 levels is primarily due to strong steam flood performance at Primrose East and continued strong performance at Kirby South. The decrease in production volumes year-over-year reflects the normal impacts of Cyclical Steam Stimulation ("CSS") operations and the planned turnaround activities performed at Primrose during the third quarter of 2016. Notably, thermal production volumes have met expectations considering a significant reduction in drilling activity at Primrose due to capital allocation choices. Canadian Natural''s thermal Q4/16 production guidance is targeted to range from 127,000 bbl/d to 133,000 bbl/d.
-- Total natural gas quarterly production volumes averaged 1,645 MMcf/d, within the targeted production guidance range for the quarter. As was previously announced, the third party plant and gathering system restrictions continued into the third quarter resulting in the shut-in of approximately 139 MMcf/d of Q3/16 natural gas volumes. Currently, the Company has approximately 106 MMcf/d of this shut-in production targeted to be reinstated in December 2016.
-- During the third quarter, the Company successfully completed major turnaround activities at the Horizon plant and tied in the major components of the Horizon Phase 2B expansion. Upon start-up of the plant, additional maintenance activities were identified primarily within the Coker unit, resulting in delayed production ramp-up to plant capacity by 7 days. The additional work was undertaken to ensure safe and reliable operations and to ensure a smooth Phase 2B start-up. Subsequently, strong and then record production volumes were achieved with September rates averaging approximately 148,000 bbl/d of SCO.
- As previously announced, the Company expanded its North America E&P crude oil drilling program for the second half of 2016. During Q3/16, drilling activity included 85 net primary heavy crude oil wells, 1 net bitumen well and 3 net wells targeting light crude oil.
- Canadian Natural has determined to re-initiate the development of its second thermal in situ oil sands Steam Assisted Gravity Drainage ("SAGD") project, Kirby North, with engineering and procurement to commence in 2017. Kirby North project capital spending in 2017 is targeted to be $28 million as the Company optimizes its execution strategies in order to continue the reduction in project capital costs. Approximately $700 million of project capital has been invested to-date at Kirby North and the remaining project costs are targeted to be approximately $650 million, more than $100 million less than originally expected. Canadian Natural targets first steam-in for 2019 and first oil in 2020 for Kirby North. The project will add 40,000 bbl/d of targeted production volumes to Canadian Natural''s thermal oil sands portfolio.
- Continued cost savings achieved in the quarter on a per unit operating cost basis are detailed below.
(1) Horizon Q3/16 operating costs adjusted to reflect the impact of the Q3/16 planned maintenance turnaround.
(2) Total overall quarterly operating costs per BOE adjusted to reflect Horizon adjusted operating costs.
(3) Given the cyclical nature of Primrose operations, quarterly cost comparison year over year is not indicative of performance.
- Pelican Lake quarterly operating costs continue to be optimized to an industry leading level of $6.09/bbl in Q3/16, compared to $6.64/bbl in Q3/15 and $6.81/bbl in Q2/16.
- After normalizing for the planned turnaround in the quarter, Horizon quarterly adjusted operating costs averaged $27.05/bbl, comparable to Q3/15 costs of $27.04/bbl and to Q2/16 costs of $26.82/bbl. Horizon unadjusted operating costs averaged $50.57/bbl in Q3/16, as result of the completion of the planned major turnaround.
- Within the Company''s North America natural gas operations, gains in process optimization continued to be made during the quarter. Q3/16 operating costs were $1.04/Mcf, a 17% and 11% decrease from Q3/15 and Q2/16 levels respectively. Q3/16 operating costs in Canadian Natural''s key natural gas areas in the Deep Basin and Montney averaged $0.38/Mcfe and $0.25/Mcfe respectively.
- Offshore Africa crude oil operating costs significantly improved to $16.32/bbl in Q3/16 from $40.53/bbl in Q3/15 and from $20.13/bbl in Q2/16. The decrease in operating costs from Q3/15 reflects an increase in production volumes from wells added through the infill drilling program completed in Q1/16, timing of liftings from various fields and a focus on effective and efficient operations.
- As a result of capital allocation choices, there has been no drilling activity of production wells in the North Sea since Q4/14. However, due to the Company''s continued focus on production enhancements, increased reliability and water flood optimization in the North Sea, production volumes averaged 23,450 bbl/d in Q3/16, increasing by 5% from Q3/15 levels and comparable to Q2/16 levels. North Sea quarterly crude oil operating costs averaged $39.41/bbl, representing excellent reductions of 46% and 3% from Q3/15 and Q2/16 levels respectively. In addition, effective January 1, 2016, the reduction of the Petroleum Revenue Tax rate from 35% to 0%, and more recently a decrease in the supplementary charge on oil and gas profits from 20% to 10%, represent favorable changes to the tax regime for assets in the North Sea. Due to these factors, the viability of reinvestment in the Company''s North Sea asset base has improved.
- Canadian Natural maintains significant financial liquidity represented in part by committed bank credit facilities. As at September 30, 2016, the Company had in place bank credit facilities of approximately $7.4 billion, of which approximately $2.35 billion was undrawn and available. Balance sheet strength continues to be a focus of the Company with debt to book capitalization of 40% at September 30, 2016, within Canadian Natural''s targeted operating range.
- On August 9, 2016, the Company successfully issued medium-term notes at 3.31% with a principal amount of $1.0 billion. The net proceeds were used to repay credit facilities, thereby generating additional liquidity for the Company.
- During the third quarter of 2016, the Company repaid US$250 million of 6.00% notes.
- Canadian Natural declared a quarterly cash dividend on common shares of C$0.25 per share payable on January 1, 2017, increasing approximately 9% over the previous quarterly dividend. This is the sixteenth consecutive year of dividend increases since the Company first paid a dividend in 2001.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse portfolio of assets. 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 Oil Sands 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 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.
Drilling Activity
North America Exploration and Production
Crude oil and NGLs - excluding Thermal In Situ Oil Sands
- In Q3/16, North America E&P crude oil and NGL production volumes averaged 240,298 bbl/d, as expected, within the Company''s Q3/16 production guidance, decreasing by 9% from Q3/15 levels and increasing by 2% over Q2/16 levels.
- North America light crude oil and NGL quarterly production averaged 90,207 bbl/d in Q3/16, representing a 2% and 8% increase from Q3/15 and Q2/16 levels respectively. The increase in production volumes is primarily a result of a focus on production optimization and minor acquisitions completed in Q2/16.
- Quarterly production volumes from Pelican Lake operations averaged 47,608 bbl/d, representing a 6% decrease from Q3/15 and comparable to Q2/16 levels. Overall performance has been very good and notably, production volumes have been maintained despite the curtailment of drilling activity at Pelican Lake since Q4/14 due to capital allocation choices.
- Q3/16 primary heavy crude oil production averaged 102,484 bbl/d, expected decreases of 18% and 1% from Q3/15 and Q2/16 levels respectively. During the quarter, Canadian Natural increased its primary heavy crude oil drilling activity to 85 net wells, partially offsetting natural production declines within the asset base.
- Canadian Natural continued to reduce quarterly operating costs of its North America E&P crude oil and NGL products on a per unit basis in Q3/16 from Q3/15 levels.
-- North America light crude oil and NGL quarterly operating costs were reduced by 8%.
-- At Pelican Lake, industry leading operating costs of $6.09/bbl were achieved, representing an 8% decrease.
-- Continued operating cost reductions of 5% were realized within the primary heavy crude oil operations despite expected production declines.
- The Company''s North America E&P crude oil and NGL annual production guidance remains unchanged and is targeted to range from 235,000 bbl/d - 245,000 bbl/d in 2016.
- Thermal in situ quarterly production averaged 103,481 bbl/d in Q3/16, as expected, representing a decrease of 22% from Q3/15 and an increase of 11% from Q2/16. The increase in production volumes over Q2/16 levels is primarily due to strong steam flood performance at Primrose East and continued strong performance at Kirby South. The decrease in production volumes year-over-year reflects the normal impacts of CSS operations and the planned turnaround activities performed at Primrose during the third quarter of 2016. Notably, thermal production volumes have met expectations considering a significant reduction in drilling activity at Primrose due to capital allocation choices. Canadian Natural''s thermal Q4/16 production guidance is targeted to range from 127,000 bbl/d to 133,000 bbl/d.
- Kirby South achieved quarterly volumes of 38,150 bbl/d, while operations continue to be optimized. Including energy costs, Q3/16 operating costs of $8.86/bbl represent a 18% reduction from Q3/15 and a 4% increase over Q2/16. The increase in quarterly operating costs over Q2/16 reflects an increase in fuel costs. Kirby South''s Steam to Oil Ratio ("SOR") was 2.6 in the quarter.
- Canadian Natural has determined to re-initiate the development of its second thermal in situ oil sands SAGD project, Kirby North, with engineering and procurement to commence in 2017. Kirby North project capital spending in 2017 is targeted to be $28 million as the Company optimizes its execution strategies in order to continue the reduction in project capital costs. Approximately $700 million of project capital has been invested to-date at Kirby North and the remaining project costs are targeted to be approximately $650 million, more than $100 million less than originally expected. Canadian Natural targets first steam-in for 2019 and first oil in 2020 for Kirby North. The project will add 40,000 bbl/d of targeted production volumes to Canadian Natural''s thermal oil sands portfolio.
- The Company''s thermal in situ oil sands annual production guidance remains unchanged and is targeted to range from 110,000 bbl/d - 130,000 bbl/d in 2016.
- North America natural gas quarterly production volumes averaged 1,567 MMcf/d in Q3/16, a decrease of 2% and 3% from both Q3/15 and Q2/16 levels respectively. As was previously announced, the third party plant and gathering system restrictions continued into the third quarter resulting in the shut-in of approximately 139 MMcf/d of Q3/16 natural gas volumes. Currently, the Company has approximately 106 MMcf/d of this shut-in production targeted to be reinstated in December 2016.
- Within the Company''s North America natural gas operations, gains in process optimization continued to be made during the quarter. Q3/16 operating costs were $1.04/Mcf, a 17% and 11% decrease from Q3/15 and Q2/16 levels respectively. Q3/16 operating costs in Canadian Natural''s key natural gas areas in the Deep Basin and Montney averaged $0.38/Mcfe and $0.25/Mcfe respectively.
- Operations at Septimus, Canadian Natural''s liquids-rich Montney natural gas play in British Columbia, continue to perform above expectations. Q3/16 Septimus sales volumes averaged 140 MMcf/d and associated liquids, with industry leading operating costs of $0.25/Mcfe.
- The Company''s total natural gas annual production guidance remains unchanged and is targeted to range from 1,705 MMcf/d to 1,735 MMcf/d in 2016.
International Exploration and Production
- International E&P quarterly crude oil production volumes were within the Company''s production guidance and averaged 49,621 bbl/d, representing a 14% increase over Q3/15 and an 8% decrease from Q2/16 levels. The year-over-year increase in production reflects the impact of the infill drilling program completed at Espoir and Baobab during 2015 and 2016, and substantial gains in production optimization attained in the North Sea, offsetting natural production declines. The decrease in production from Q2/16 to Q3/16 primarily reflects natural production declines and unplanned downtime at Espoir.
- As a result of capital allocation choices, there has been no drilling activity of production wells in the North Sea since Q4/14. However, due to the Company''s continued focus on production enhancements, increased reliability and water flood optimization in the North Sea, production volumes averaged 23,450 bbl/d in Q3/16, increasing by 5% from Q3/15 levels and comparable to Q2/16 levels. North Sea quarterly crude oil operating costs averaged $39.41/bbl, representing excellent reductions of 46% and 3% from Q3/15 and Q2/16 levels respectively. In addition, effective January 1, 2016, the reduction of the Petroleum Revenue Tax rate from 35% to 0%, and more recently a decrease in the supplementary charge on oil and gas profits from 20% to 10%, represent favorable changes to the tax regime for assets in the North Sea. Due to these factors, the viability of reinvestment in the Company''s North Sea asset base has improved.
- The Company''s International E&P annual production guidance remains unchanged and is targeted to range from 49,000 bbl/d to 56,000 bbl/d in 2016.
North America Oil Sands Mining and Upgrading - Horizon
(1) The Company produces diesel for internal use at Horizon. Third quarter 2016 SCO production before royalties excludes 1,464 bbl/d of SCO consumed internally as diesel (second quarter 2016 - 2,227 bbl/d; third quarter 2015 - 2,058 bbl/d; nine months ended September 30, 2016 - 2,083 bbl/d; nine months ended September 30, 2015 - 2,049 bbl/d).
- During the third quarter, the Company successfully completed major turnaround activities at the Horizon plant and tied in the major components of the Horizon Phase 2B expansion. Upon start-up of the plant, additional maintenance activities were identified primarily within the Coker unit, resulting in delayed production ramp-up to plant capacity by 7 days. The additional work was undertaken to ensure safe and reliable operations and to ensure a smooth Phase 2B start-up. Subsequently, strong and then record production volumes were achieved with September and October rates averaging approximately 148,000 bbl/d and 161,000 bbl/d respectively.
- The staged start-up of the Horizon Phase 2B expansion is substantially complete. Production rates are very strong with current production volumes of approximately 175,000 bbl/d of SCO and imminent ramp up to targeted production rates in excess of 182,000 bbl/d of SCO.
- After normalizing for the planned turnaround in the quarter, Horizon quarterly adjusted operating costs averaged $27.05/bbl, comparable to Q3/15 costs of $27.04/bbl and to Q2/16 costs of $26.82/bbl. Horizon unadjusted operating costs averaged $50.57/bbl in Q3/16, as result of the completion of the planned major turnaround.
- For the first nine months of 2016, Horizon project capital costs totaled $1.405 billion, with total Horizon project capital now targeted to be approximately $1.920 billion in 2016 versus the Company''s original 2016 budget range of $1.890 billion to $1.990 billion. In 2017, Horizon project capital costs are targeted to be approximately $1 billion for Phase 3 completion, which is targeted to add incremental production volumes of 80,000 bbl/d of SCO in Q4/17. The addition of Phase 3 will mark the completion of the Horizon expansion with targeted design capacity in excess of 250,000 bbl/d of SCO, and targeted operating costs below C$25.00/bbl (US$20.00/bbl).
- At September 30, 2016, the Horizon Phase 3 expansion reached 87% physical completion. Within the scope of work for the combined hydrotreater, all modules have been installed and module interconnections are well advanced. Phase 3 includes the addition of an ore preparation plant, extraction trains, the combined hydrotreater and a sulphur recovery unit. Phase 3 remains on schedule for targeted start-up in Q4/17. Phase 3 is targeted to increase production capacity by 80,000 bbl/d in Q4/17 and will target significant operating cost savings for Horizon operations.
- Directive 85 (formerly Directive 74) of the Horizon expansion remains on track and was 65% physically complete as at September 30, 2016. This project includes research into tailings management and technological investment.
- Canadian Natural''s Horizon annual production guidance remains unchanged and is targeted to range from 120,000 bbl/d to 132,000 bbl/d in 2016.
MARKETING
(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$44.94/bbl for Q3/16, a decrease of 3% from US$46.44/bbl from Q3/15 and comparable to US$45.60/bbl for Q2/16. WTI pricing for the nine months ended September 30, 2016 continued to reflect volatility in supply and demand factors and geopolitical events.
- In Q3/16, the WCS Heavy Differential averaged US$13.49/bbl (30%) compared with US$13.21/bbl (28%) and US$13.31/bbl (29%) in Q3/15 and Q2/16 respectively. Fluctuations in the WCS Heavy Differential reflect seasonal demand, changes in transportation logistics, and refinery utilization and shutdowns. As of October 17, 2016, the WCS Heavy Differential for the fourth quarter of 2016 is approximately US$14.16/bbl (28%).
- Canadian Natural contributed approximately 191,000 bbl/d of its heavy crude oil stream to the WCS blend in Q3/16. The Company remains the largest contributor to the WCS blend, accounting for 47% of the total blend.
- The SCO price averaged US$45.63/bbl for Q3/16, comparable to US$45.78/bbl for the Q3/15, and a decrease of 4% from US$47.39/bbl for Q2/16. The fluctuations in SCO pricing for Q3/16 from the comparable periods were primarily due to changes in WTI benchmark pricing.
- AECO natural gas prices averaged $2.08/GJ for Q3/16, a decrease of 22% from $2.65/GJ for Q3/15, and an increase of 76% from $1.18/GJ for Q2/16. The decrease in natural gas prices in Q3/16 compared with Q3/15 was primarily due to US natural gas inventories being at near record high levels at the end of the winter season. The increase from Q2/16 to Q3/16 was primarily due to reduced natural gas production growth, warm weather in the third quarter of 2016 and strong substitution of natural gas for coal in U.S. electricity generation.
- 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 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 cash 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 production of 735,212 BOE/d in Q3/16, with approximately 96% of total production located in G7 countries.
- Canadian Natural maintains significant financial liquidity represented in part by committed bank credit facilities. As at September 30, 2016, the Company had in place bank credit facilities of approximately $7.4 billion, of which approximately $2.35 billion was undrawn and available. Balance sheet strength continues to be a focus of the Company with debt to book capitalization of 40% at September 30, 2016, within Canadian Natural''s targeted operating range.
- On August 9, 2016, the Company successfully issued medium-term notes at 3.31% with a principal amount of $1.0 billion. The net proceeds were used to repay credit facilities, thereby generating additional liquidity for the Company.
- During the third quarter of 2016, the Company repaid US$250 million of 6.00% notes.
- In addition to its strong cash flow and access to debt capital markets, Canadian Natural has additional financial levers at its disposal to effectively manage its liquidity. As at October 31, 2016, these financial levers include the Company''s investment in PrairieSky with an approximate value of $660 million and cross currency swaps maturing after 2020 with an approximate value of $370 million. Additionally, the Company could monetize its third party royalty volumes of approximately 1,000 BOE/d.
- Canadian Natural declared a quarterly cash dividend on common shares of C$0.25 per share payable on January 1, 2017, increasing approximately 9% over the previous quarterly dividend. This is the sixteenth consecutive year of dividend increases since the Company first paid a dividend in 2001.
OUTLOOK
The Company forecasts annual 2016 production levels to average between 514,000 and 563,000 bbl/d of crude oil and NGLs and between 1,705 and 1,735 MMcf/d of natural gas, before royalties. Q4/16 production guidance before royalties is forecast to average between 575,000 and 599,000 bbl/d of crude oil and NGLs and between 1,690 and 1,720 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 2016 capital expenditures are targeted to be approximately $4.4 billion. This reflects increased operating capital at Horizon partly due to additional proactive maintenance completed during the Q3/16 turnaround to ensure safe and reliable operations and a smooth Phase 2B start-up. Additionally the Company targets increased capital activity in the Company''s North America E&P business in the second half of 2016 and also targets an increase in the Company''s net acquisition and dispositions in 2016. This additional capital has minimal impact on Q3/16 and Q4/16 production volumes, but will be reflected in 2017 production volumes.
MANAGEMENT''S DISCUSSION AND ANALYSIS
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, 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; 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.
Management''s Discussion and Analysis
This MD&A of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2016 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2015.
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, 2016 and this MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. This MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings (loss) from operations, 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), 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 cash flow from operations are reconciled to net earnings (loss), as determined in accordance with IFRS, in the "Financial Highlights" section of this MD&A. 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 this MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the "Liquidity and Capital Resources" section of this 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 this 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 MD&A 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.
The following discussion and analysis refers primarily to the Company''s financial results for the three and nine months ended September 30, 2016 in relation to the comparable periods in 2015 and the second quarter of 2016. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2015, is available on SEDAR at , and on EDGAR at . This MD&A is dated November 2, 2016.
FINANCIAL HIGHLIGHTS
(1) Adjusted net earnings (loss) from operations is a non-GAAP measure that represents net earnings (loss) adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings (loss) from operations. The reconciliation "Adjusted Net Earnings (Loss) from Operations" presents the after-tax effects of certain items of a non-operational nature that are included in the Company''s financial results. Adjusted net earnings (loss) from operations may not be comparable to similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net earnings (loss) adjusted for non-cash items before working capital adjustments. The Company evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company''s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation "Cash Flow from Operations" presents certain non-cash items that are included in the Company''s financial results. Cash flow from operations may not be comparable to similar measures presented by other companies.
(1) The Company''s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company''s balance sheets and periodic changes in the fair value are recognized in net earnings (loss) or are capitalized to Oil Sands Mining and Upgrading construction costs.
(2) Derivative financial instruments are recorded at fair value on the Company''s balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings (loss). The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil, natural gas and foreign exchange.
(3) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings (loss).
(4) The Company''s investment in the 50% owned North West Redwater Partnership is accounted for using the equity method of accounting. Included in the non-cash (gain) loss from investments is the Company''s pro rata share of the North West Redwater Partnership''s accounting (gain) loss for the period.
(5) The Company''s investment in PrairieSky Royalty Ltd. ("PrairieSky") has been accounted for at fair value through profit and loss and is remeasured each period with changes in fair value recognized in net earnings (loss).
(6) During the first quarter of 2016, the Company recorded a pre-tax gain of $32 million ($23 million after-tax) on the disposition of certain exploration and evaluation assets.
(7) In connection with the Company''s notice of withdrawal from Block CI-12 in Cote d''Ivoire, Offshore Africa in the second quarter of 2016, the Company derecognized $18 million ($13 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense.
(8) In the third quarter of 2016, the UK government enacted legislation to reduce the supplementary charge on oil and gas profits from 20% to 10% effective January 1, 2016, resulting in a decrease in the Company''s deferred corporate income tax liability of $107 million. During the first quarter of 2016, the UK government enacted tax rate reductions relating to Petroleum Revenue Tax ("PRT"), resulting in a decrease in the Company''s net deferred income tax liability of $114 million. During the second quarter of 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. As a result of this income tax rate increase, the Company''s deferred corporate income tax liability was increased by $579 million. During the first quarter of 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and PRT, and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company''s net deferred income tax liability of $228 million.
SUMMARY OF CONSOLIDATED NET EARNINGS (LOSS) AND CASH FLOW FROM OPERATIONS
The net loss for the nine months ended September 30, 2016 was $770 million compared with a net loss of $768 million for the nine months ended September 30, 2015. The net loss for the nine months ended September 30, 2016 included net after-tax income of $338 million compared with expenses of $1,080 million for the nine months ended September 30, 2015 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, (gain) loss from investments, gain on disposition of properties, derecognition of exploration and evaluation assets and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, the adjusted net loss from operations for the nine months ended September 30, 2016 was $1,108 million compared with adjusted net earnings of $312 million for the nine months ended September 30, 2015.
The net loss for the third quarter of 2016 was $326 million compared with a net loss of $111 million for the third quarter of 2015 and a net loss of $339 million for the second quarter of 2016. The net loss for the third quarter of 2016 included net after-tax income of $29 million compared with net after-tax expenses of $224 million for the third quarter of 2015 and net after-tax expenses of $129 million for the second quarter of 2016 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, (gain) loss from investments, gain on disposition of properties, derecognition of exploration and evaluation assets and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, the adjusted net loss from operations for the third quarter of 2016 was $355 million compared with adjusted net earnings of $113 million for the third quarter of 2015 and an adjusted net loss of $210 million for the second quarter of 2016.
The decrease in adjusted net earnings (loss) for the three and nine months ended September 30, 2016 from the comparable periods in 2015 was primarily due to:
- lower SCO sales volumes in the Oil Sands Mining and Upgrading segment as a result of the major turnaround in the third quarter of 2016;
- lower crude oil and NGLs sales volumes in the North America segment;
- lower natural gas netbacks in the Exploration and Production segments;
- lower crude oil and NGLs netbacks in the North America segment;
- higher depletion, depreciation and amortization in the Oil Sands Mining and Upgrading segment as a result of minor asset de-recognitions resulting from the major turnaround; and
- lower realized risk management gains.
partially offset by:
- higher crude oil and NGLs sales volumes in the Offshore Africa segment; and
- higher crude oil and NGLs netbacks in the International segments.
The increase in adjusted net loss for the third quarter of 2016 from the second quarter of 2016 was primarily due to:
- lower SCO sales volumes in the Oil Sands Mining and Upgrading segment;
- lower natural gas sales volumes in the North America segment; and
- higher depletion, depreciation and amortization in the Oil Sands Mining and Upgrading segment as a result of minor asset de-recognitions resulting from the major turnaround.
partially offset by:
- higher natural gas and crude oil and NGLs netbacks in the Exploration and Production segments;
- higher crude oil and NGLs sales volumes in North America and the North Sea segments; and
- higher realized risk management gains.
The impacts of share-based compensation, risk management activities and fluctuations in foreign exchange rates are expected to continue to contribute to significant volatility in consolidated net earnings (loss) and are discussed in detail in the relevant sections of this MD&A.
Cash flow from operations for the nine months ended September 30, 2016 was $2,616 million compared with $4,406 million for the nine months ended September 30, 2015. Cash flow from operations for the third quarter of 2016 was $1,021 million compared with $1,533 million for the third quarter of 2015 and $938 million for the second quarter of 2016. The fluctuations in cash flow from operations from the comparable periods were primarily due to the factors noted above relating to the fluctuations in adjusted net earnings (loss), as well as due to the impact of cash taxes.
Total production before royalties for the third quarter of 2016 decreased 13% to 735,212 BOE/d from 848,701 BOE/d for the third quarter of 2015 and decreased 6% from 783,988 BOE/d for the second quarter of 2016.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company''s quarterly results for the eight most recently completed quarters:
Volatility in the quarterly net earnings (loss) over the eight most recently completed quarters was primarily due to:
- Crude oil pricing - The impact of shale oil production in North America, fluctuating global supply/demand including the Organization of the Petroleum Exporting Countries'' ("OPEC") decision not to curtail crude oil production to offset the excess world supply, the impact of geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential from the West Texas Intermediate reference location at Cushing, Oklahoma ("WTI") in North America and the impact of the differential between WTI and Brent benchmark pricing in the North Sea and Offshore Africa.
- Natural gas pricing - The impact of fluctuations in both the demand for natural gas and inventory storage levels, and the impact of shale gas production in the US.
- Crude oil and NGLs sales volumes - Fluctuations in production due to the cyclic nature of the Company''s Primrose thermal projects, production from Kirby South, the results from the Pelican Lake water and polymer flood projects, the reduction in the Company''s drilling program in North America, the impact and timing of acquisitions, the impact of turnarounds at Horizon, and the impact of the drilling program in Cote d''Ivoire in Offshore Africa. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the International segments.
- Natural gas sales volumes - Fluctuations in production due to the Company''s allocation of capital to higher return crude oil projects, natural decline rates, shut-in production due to third party pipeline restrictions and related pricing impacts and an outage at a third party processing facility, shut-in production due to low commodity prices, and the impact and timing of acquisitions.
- Production expense - Fluctuations primarily due to the impact of the demand and cost for services, fluctuations in product mix and production, the impact of seasonal costs that are dependent on weather, cost optimizations across all segments, the impact and timing of acquisitions, turnarounds at Horizon and maintenance activities in the International segments.
- Depletion, depreciation and amortization - Fluctuations due to changes in sales volumes including the impact and timing of acquisitions and dispositions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company''s proved undeveloped reserves, fluctuations in international sales volumes subject to higher depletion rates, and the impact of turnarounds at Horizon.
- Share-based compensation - Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model of the Company''s share-based compensation liability.
- Risk management - Fluctuations due to the recognition of gains and losses from the mark - to - market and subsequent settlement of the Company''s risk management activities.
- Foreign exchange rates - Fluctuations in the Canadian dollar relative to the US dollar, which impacted the realized price the Company received for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Fluctuations in realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt, partially offset by the impact of cross currency swap hedges.
- Income tax expense - Fluctuations in income tax expense include statutory tax rate and other legislative changes substantively enacted in the various periods.
- Gains on disposition of properties and investments - Fluctuations due to the recognition of gains on disposition of properties in the various periods and fair value changes in the investment in PrairieSky shares.
BUSINESS ENVIRONMENT
Substantially all of the Company''s production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Dated Brent ("Brent") indices. Canadian natural gas pricing is primarily based on Alberta AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The Company''s realized prices are highly sensitive to fluctuations in foreign exchange rates. For the third quarter of 2016, realized prices continued to be supported by the weaker Canadian dollar, as the Canadian dollar sales price the Company received for its crude oil and natural gas sales is based on US dollar denominated benchmarks.
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$41.37 per bbl for the nine months ended September 30, 2016, a decrease of 19% from US$50.98 per bbl for the nine months ended September 30, 2015. WTI averaged US$44.94 per bbl for the third quarter of 2016, a decrease of 3% from US$46.44 per bbl for the third quarter of 2015, and comparable with the second quarter of 2016.
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$41.84 per bbl for the nine months ended September 30, 2016, a decrease of 24% from US$55.37 per bbl for the nine months ended September 30, 2015. Brent averaged US$45.76 per bbl for the third quarter of 2016, a decrease of 9% from US$50.39 per bbl for the third quarter of 2015, and comparable with the second quarter of 2016.
WTI and Brent pricing for the nine months ended September 30, 2016 continued to reflect volatility in supply and demand factors and geopolitical events.
The WCS Heavy Differential averaged 33% for the nine months ended September 30, 2016, compared with 26% for the nine months ended September 30, 2015. The WCS Heavy Differential averaged 30% for the third quarter of 2016 compared with 28% for the third quarter of 2015 and 29% for the second quarter of 2016. Fluctuations in the WCS Heavy Differential reflected seasonal demand, changes in transportation logistics, and refinery utilization and shutdowns.
The SCO price averaged US$42.27 per bbl for the nine months ended September 30, 2016, a decrease of 16% from US$50.55 per bbl for the nine months ended September 30, 2015. The SCO price averaged US$45.63 per bbl for the third quarter of 2016, comparable with the third quarter of 2015, and a decrease of 4% from US$47.39 per bbl for the second quarter of 2016. The fluctuations in SCO pricing for the three and nine months ended September 30, 2016 from the comparable periods were primarily due to changes in WTI benchmark pricing.
NYMEX natural gas prices averaged US$2.27 per MMBtu for the nine months ended September 30, 2016, a decrease of 19% from US$2.80 per MMBtu for the nine months ended September 30, 2015. NYMEX natural gas prices averaged US$2.81 per MMBtu for the third quarter of 2016, comparable with the third quarter of 2015, and an increase of 44% from US$1.95 per MMBtu for the second quarter of 2016.
AECO natural gas prices averaged $1.75 per GJ for the nine months ended September 30, 2016, a decrease of 34% from $2.66 per GJ for the nine months ended September 30, 2015. AECO natural gas prices averaged $2.08 per GJ for the third quarter of 2016, a decrease of 22% from $2.65 per GJ for the third quarter of 2015, and an increase of 76% from $1.18 per GJ for the second quarter of 2016.
The decrease in natural gas prices for the nine months ended September 30, 2016 compared with the comparable period in 2015 was primarily due to warmer than normal winter temperatures in 2016. US natural gas inventories were at near record high levels at the end of the 2015/2016 winter season.
The increase in natural gas prices in the third quarter of 2016 compared with the second quarter of 2016 was primarily due to reduced natural gas production growth, warm weather in the third quarter of 2016 and strong substitution of gas for coal in U.S. electricity generation. While natural gas prices are anticipated to remain volatile in the near term, ongoing normalization of storage inventories is expected to continue to reduce pressure on natural gas pricing entering the 2016/2017 winter season.
DAILY PRODUCTION, before royalties
(1) Third quarter 2016 SCO production before royalties excludes 1,464 bbl/d of SCO consumed internally as diesel (second quarter 2016 - 2,227 bbl/d; third quarter 2015 - 2,058 bbl/d; nine months ended September 30, 2016 - 2,083 bbl/d; nine months ended September 30, 2015 - 2,049 bbl/d).
(2) Net of blending costs and excluding risk management activities.
DAILY PRODUCTION, net of royalties
The Company''s business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO and natural gas.
Crude oil and NGLs production for the nine months ended September 30, 2016 decreased 10% to 503,286 bbl/d from 561,554 bbl/d for the nine months ended September 30, 2015. Crude oil and NGL production for the third quarter of 2016 of 460,986 bbl/d decreased by 20% from 573,135 bbl/d for the third quarter of 2015, and decreased 8% from 502,410 bbl/d for the second quarter of 2016. The decrease in crude oil and NGL production for the three and nine months ended September 30, 2016 from the comparable periods in 2015 was primarily due to lower drilling activity and natural field declines in North America and the completion of the major turnaround at Horizon in the third quarter of 2016. The decrease in crude oil and NGLs production for the third quarter of 2016 from the second quarter of 2016 primarily reflected lower production at Horizon due to the major turnaround in the third quarter of 2016, partially offset by higher thermal oil production.
Crude oil and NGLs production for the third quarter of 2016 was within the Company''s previously issued guidance o
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Datum: 03.11.2016 - 04:00 Uhr
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