Canadian Natural Resources Limited Announces 2016 Second Quarter Results
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 08/04/16 -- Commenting on second quarter 2016 results, Steve Laut, President of Canadian Natural stated, "Canadian Natural delivered strong cash flow during the quarter while facing a number of challenges, ranging from low commodity prices to the proactive shut down of the Primrose East pipeline and operational issues at third party owned and operated natural gas facilities, which impacted quarterly production volumes. The major turnaround at Horizon is now largely complete with on spec production targeted for August 11, 2016. Start-up of the Horizon 2B expansion is targeted in October, with full production targeted in November, delivering additional sustainable production and cash flow. As a result, Canadian Natural is in an excellent position to become an even stronger and more robust company."
Canadian Natural''s Chief Financial Officer, Corey Bieber, continued, "In the first half of 2016, we continued to realize significant operating cost savings of approximately $430 million when compared with the previous year through our continued focus on top tier effectiveness and efficiency. Canadian Natural is nearing an inflection point, with the completion of Horizon Phase 2B. Upon completion, decreased project capital expenditures, coupled with greater cash flow generation potential, significantly enhances our ability to strengthen our balance sheet, maximize returns to shareholders, invest in economic resource development and execute on opportunistic acquisitions."
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.
- Canadian Natural realized cash flow from operations in Q2/16 of $938 million, an increase from $657 million in Q1/16. The decrease in Q2/16 from $1,503 million in Q2/15 primarily reflects lower crude oil and NGL and natural gas netbacks and lower sales volumes of North America crude oil and NGLs.
- For Q2/16, the Company had a net loss of $339 million compared to a net loss of $405 million in Q2/15 and net loss of $105 million in Q1/16. Adjusted net loss from operations was $210 million in Q2/16 compared to adjusted net earnings of $178 million in Q2/15 and adjusted net loss of $543 million in Q1/16. Changes in adjusted net earnings primarily reflect the changes in cash flow from operations.
- Canadian Natural''s corporate production volumes averaged 783,988 BOE/d in Q2/16, representing a 3% and 7% decrease from Q2/15 and Q1/16 levels respectively. Q2/16 production volumes were lower than Q2/15 and Q1/16 levels due to expected natural production declines, minimal conventional development capital expenditures, as well as unexpected weather and pipeline related events.
- Crude oil and NGL production volumes averaged 502,410 bbl/d in Q2/16.
-- During the quarter, Horizon Oil Sands ("Horizon") operations were not significantly affected by the wild fires in Fort McMurray. Q2/16 production averaged 119,511 bbl/d of synthetic crude oil ("SCO") as minor unplanned downtime was required during the quarter to optimize the diluent recovery unit ("DRU"). Horizon achieved strong operating costs of $26.82/bbl (US$20.81/bbl) in Q2/16, representing an 8% decrease over Q2/15 and comparable to Q1/16, as a result of a continued focus on effective and efficient operations.
-- Kirby South achieved record quarterly production volumes of 38,695 bbl/d as operations continue to be optimized. Operating costs of $8.56/bbl (US$6.64/bbl) represented a 37% and 18% reduction over Q2/15 and Q1/16 levels respectively. The steam to oil ratio ("SOR") was 2.55 in the quarter and is expected to be in the 2.50 - 2.60 range for the rest of the year.
-- At Pelican Lake, Canadian Natural''s industry leading polymer flood, quarterly production was 47,797 bbl/d, reflecting strong polymer flood performance offset by natural declines in base primary crude oil production. Q2/16 operating costs have decreased by 2% from Q2/15 to $6.81/bbl (US$5.29/bbl).
-- International Exploration & Production ("E&P") quarterly crude oil production volumes averaged 54,218 bbl/d, representing a 45% and 11% increase over Q2/15 and Q1/16 levels respectively.
--- Q2/16 represented the first full quarter of production at Espoir and Baobab in Offshore Africa after the completion of the Company''s successful infill drilling program. Crude oil production increased by 81% and 20% from Q2/15 and Q1/16 levels respectively, averaging 30,858 bbl/d. Crude oil operating costs increased in the quarter over Q1/16 to $20.13/bbl (US$15.62/bbl) due to timing of liftings from various fields, however year-over-year have significantly decreased by 54%.
--- Q2/16 North Sea crude oil production averaged 23,360 bbl/d. Production enhancements, increased reliability and waterflood optimization resulted in an increase of production by approximately 3,000 bbl/d, or 15%, in Q2/16 over Q2/15 and comparable to Q1/16. Quarterly crude oil operating costs averaged $40.74/bbl (US$31.62/bbl), reductions of 33% and 15% from Q2/15 and Q1/16 levels respectively, as a result of the Company''s continued focus on effective and efficient operations.
- Quarterly natural gas volumes averaged 1,689 MMcf/d, representing a 5% decrease from both Q2/15 and Q1/16 levels mainly due to third party pipeline and facility outages. North America natural gas operating costs in Q2/16 averaged $1.17/Mcf, 9% and 1% lower as compared to Q2/15 and Q1/16 levels respectively, reflecting a continued focus on process optimization.
- During the forest fires in the Fort McMurray region, Horizon''s teams effectively and efficiently worked together to mobilize resources and organize logistics in support of over 2,700 evacuees all while ensuring the safety and well-being of everyone on site and keeping operations stable. Horizon personnel focused on supporting its employees, their families, Fort McMurray and neighboring community residents with accommodations, meals, medical treatment, and flights from the Horizon site to Edmonton or Calgary. In support of firefighting efforts, a portion of Horizon''s firefighters worked alongside crews from the city and contributed firefighting equipment to help protect critical infrastructure and homes while government officials were offered access to Horizon''s aerodrome services. The Company would like to recognize and thank its teams for their strong commitment and hard work through this challenging time.
- Subsequent to June 30, 2016, the Company began a scheduled major turnaround at Horizon to complete maintenance activities within the plant facilities and tie-in of major components of the Horizon Phase 2B expansion. The turnaround is now largely complete with SCO production targeted to resume on August 11, 2016.
- 2016 is a milestone year for Canadian Natural as the Company advances the completion of the Horizon expansion with the addition of 45,000 bbl/d of SCO from Phase 2B, targeted to start up in October 2016 with full production targeted in November 2016. With the completion of Phase 2B, Canadian Natural expects Horizon''s 2016 exit nameplate capacity to be rated at 182,000 bbl/d of SCO, resulting in a step change in the sustainability of the production and cash flow profiles for the Company.
- Concurrent with the completion of maintenance activities, tie-in of major components of the Horizon Phase 2B expansion has been completed as planned. Staged completion of plant system commissioning activities commenced in March 2016 and remains on schedule.
- Horizon project capital in 2016 is targeted to range from $1.89 billion to $1.99 billion, the majority of which will be spent over the first nine months of 2016. Horizon project costs in Q2/16 totaled $583 million and are $1,005 million year-to-date. In 2017, Horizon project capital costs are targeted to decline to approximately $1 billion for Phase 3 completion, which is targeted to add incremental production volumes of 80,000 bbl/d in Q4/17. The addition of Phase 3 marks the completion of the current Horizon expansion and volumes are targeted to average 250,000 bbl/d of SCO with operating costs trending below C$25.00/bbl (US$19.40/bbl).
- The Company continues to proactively manage the cost structures within its crude oil and natural gas drilling programs. As a result of realizing 20% to 25% of drilling and completions cost reductions year-over-year and increasing commodity prices, the Company has reallocated $50 million of development capital across the basin while remaining within annual corporate capital guidance. In the second half of 2016, Canadian Natural targets to increase its drilling activity by approximately 130 net North America E&P crude oil wells and 4 net producing thermal in situ wells.
- Canadian Natural continues to realize excellent results from its commitment to effective and efficient operations resulting in approximately $430 million of operating cost savings in the first half of 2016 over the same period in 2015.
- Significant cost savings achieved in the quarter on a per unit operating cost basis are detailed below.
- Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. As at June 30, 2016, the Company had in place bank credit facilities of approximately $7.4 billion, of which approximately $1.7 billion was undrawn and available. Balance sheet strength was maintained with debt to book capitalization of 40% at June 30, 2016.
- On June 6, 2016, the Company distributed approximately 21.8 million PrairieSky common shares to the shareholders of record of the Company at a volume weighted price of $24.89, completing the previously announced Plan of Arrangement. Subsequent to the distribution, the Company''s ownership interest in PrairieSky decreased to approximately 22.6 million shares with a market value of approximately $575 million as at July 31, 2016. Current ownership is less than 10% of the issued and outstanding common shares of PrairieSky, satisfying the requirements of the purchase and sale agreement with PrairieSky.
- Canadian Natural declared a quarterly cash dividend on its common shares of C$0.23 per share payable on October 1, 2016.
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 acted on quickly, and, in the right economic conditions, can provide excellent payouts and returns. 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 maximizes value.
Drilling Activity
North America Exploration and Production
- Q2/16 production volumes of North America crude oil and NGLs averaged 235,468 bbl/d, representing an expected decrease of 13% and 7% from Q2/15 and Q1/16 levels. The year-over-year production decline was modest considering an 84% reduction in drilling activity from 44 net wells in the first half of 2015 to 7 net wells in the first half of 2016.
- North America light crude oil and NGL quarterly production averaged 83,821 bbl/d in Q2/16, representing a 6% and 7% decrease from Q2/15 and Q1/16 levels respectively.
- Quarterly production volumes from Pelican Lake operations averaged 47,797 bbl/d, representing a 8% decrease from Q2/15 and comparable to Q1/16 levels.
- Q2/16 primary heavy crude oil production averaged 103,850 bbl/d, a decrease of 19% and 9% from Q2/15 and Q1/16 levels respectively. This production decline reflects the Company''s proactive decision to reduce its primary heavy crude oil drilling program since 2014.
- In the second half of 2016, Canadian Natural targets to increase its drilling activity by approximately 130 net North America E&P crude oil wells.
- 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 Q2/16 from Q2/15 levels.
-- North America light crude oil and NGL quarterly operating costs were reduced by 10%.
-- At Pelican Lake, industry leading operating costs of $6.81/bbl were achieved, representing a 2% decrease.
-- Strong operating cost reductions of 8% were realized within the primary heavy crude oil operations.
- The Company''s North America E&P crude oil and NGL annual production guidance remains unchanged and is targeted to range from 514,000 bbl/d - 563,000 bbl/d in 2016.
- Thermal in situ quarterly production averaged 93,213 bbl/d in Q2/16, representing a decrease of 11% and 21% from Q2/15 and Q1/16 levels respectively. The decrease in production volumes reflect reduced drilling programs at Primrose since 2014, the normal impacts of cyclical steam stimulation ("CSS") operations for this asset, and the 13,000 bbl/d quarterly impact of the previously announced proactive shut down of the Primrose East pipeline. The Primrose East pipeline returned to service on May 17, 2016.
- Kirby South achieved record quarterly volumes of 38,695 bbl/d, while operations continue to be optimized. Operating costs of $8.56/bbl represented a 37% and 18% reduction over Q2/15 and Q1/16 levels respectively. The SOR was 2.55 in the quarter and is expected to be in the 2.50 - 2.60 range for the rest of 2016.
- The Company is targeting to drill 3 wells at Primrose/Wolf Lake and one SAGD well pair at the Senlac thermal in situ property in the second half of 2016.
- 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 1,620 MMcf/d in Q2/16, a decrease of 6% from both Q2/15 and Q1/16 levels respectively. In Q2/16, approximately 55 MMcf/d was negatively impacted due to an unplanned restriction to the third party Pine River Gas Plant.
-- As mentioned above, the third party operated Pine River Gas Plant experienced unforeseen operational issues in the quarter. In addition, in mid-June the main line to the plant was compromised due to flooding and was subsequently shut in. As a result, the Company has approximately 176 MMcf/d of natural gas production shut in due to the outage. Subsequent to quarter end, the third party is targeting to reinstate natural gas processing volumes of approximately 50 MMcf/d on August 8, 2016, an additional 40 MMcf/d by late-September 2016 and the remaining 86 MMcf/d by December 2016.
- Operations at Septimus, Canadian Natural''s liquids-rich Montney natural gas play in British Columbia, continue to perform above expectations, with industry leading operating costs of $0.23/Mcfe in Q2/16.
- North America natural gas quarterly operating costs were $1.17/Mcf in Q2/16, a 9% decrease from Q2/15 levels and were in line with Q1/16 reflecting a continued focus on process optimization.
- The Company''s natural gas annual production guidance has been reduced to reflect third party outages and is now 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 averaged 54,218 bbl/d, representing a 45% and 11% increase over Q2/15 and Q1/16 levels respectively.
- Q2/16 represented the first full quarter of production at Espoir and Baobab in Offshore Africa after the completion of the Company''s successful infill drilling programs. Crude oil production increased by 81% and 20% from Q2/15 and Q1/16 levels respectively, averaging 30,858 bbl/d. Crude oil operating costs increased in the quarter over Q1/16 to $20.13/bbl (US$15.62/bbl) due to timing of liftings, however year-over-year have decreased significantly by 54%.
- Q2/16 North Sea crude oil production averaged 23,360 bbl/d. Production enhancements, increased reliability and waterflood optimization resulted in an increase of production by approximately 3,000 bbl/d, or 15%, in Q2/16 over Q2/15 and comparable to Q1/16. Quarterly crude oil operating costs averaged $40.74/bbl (US$31.62/bbl), reductions of 33% and 15% from Q2/15 and Q1/16 levels respectively, as a result of the Company''s continued focus on effective and efficient operations.
North America Oil Sands Mining and Upgrading - Horizon
(1) The Company produces diesel for internal use at Horizon. Second quarter 2016 SCO production before royalties excludes 2,227 bbl/d of SCO consumed internally as diesel (first quarter 2016 - 2,562 bbl/d; second quarter 2015 - 2,410 bbl/d; six months ended June 30, 2016 - 2,394 bbl/d; six months ended June 30, 2015 - 2,045 bbl/d).
- Q2/16 production averaged 119,511 bbl/d of SCO, representing a 24% increase from Q2/15 and a decrease of 7% from Q1/16. The increase in production from Q2/15 reflects high utilization rates and reliability following the turnaround completed in the prior year. The decrease from Q1/16 reflects minor unplanned downtime in the quarter to optimize performance of the DRU.
- The Company achieved strong quarterly operating costs at Horizon of $26.82/bbl, a 8% reduction from Q2/15 levels and comparable to Q1/16 levels, as a result of safe, steady and reliable operations and a focus on continuous improvement during the quarter.
- Subsequent to June 30, 2016, the Company began a scheduled major turnaround at Horizon to complete maintenance activities within the plant facilities and tie-in of major components of the Horizon Phase 2B expansion. The turnaround is now largely complete with SCO production targeted to resume on August 11, 2016.
- Concurrent with the completion of maintenance activities, tie-in of major components of the Horizon Phase 2B expansion has been completed as planned. Staged completion of plant system commissioning activities commenced in March 2016 and remains on schedule. Phase 2B is targeted to start up in October 2016 with full production targeted in November 2016.
- The Phase 3 expansion is currently on budget and on schedule. This Phase is 83% physically complete, and includes the addition of extraction trains and combined hydrotreater. Phase 3 is targeted to increase production capacity by 80,000 bbl/d in Q4/17 and will result in additional reliability, redundancy and significant operating cost savings for the Horizon project.
- Directive 85 (formerly Directive 74) of the Horizon expansion includes research into tailings management and technological investment. This project remains on track and is 61% physically complete as at June 30, 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$45.60/bbl for Q2/16, a decrease of 21% from US$57.96/bbl from Q2/15 and an increase of 36% from US$33.51/bbl for Q1/16. WTI pricing for the six months ended June 30, 2016 continued to reflect volatility in supply and demand factors and geopolitical events.
- In Q2/16, the WCS Heavy Differential averaged US$13.31/bbl (29%) compared with US$11.60/bbl (20%) and US$14.24/bbl (42%) in Q2/15 and Q1/16 respectively. Fluctuations in the WCS Heavy Differential reflect seasonal demand, changes in transportation logistics, and refinery utilization and shutdowns. Pricing as at July 15, 2016, Q3/16 WCS Heavy Differential is approximately US$13.50/bbl (29%).
- Canadian Natural contributed approximately 197,000 bbl/d of its heavy crude oil stream to the WCS blend in Q2/16. The Company remains the largest contributor to the WCS blend, accounting for 51% of the total blend.
- The SCO price averaged US$47.39/bbl for Q2/16, a decrease of 22% from US$60.61/bbl for the Q2/15, and an increase of 40% from US$33.77/bbl for Q1/16. The fluctuations in SCO pricing for Q2/16 from the comparable periods were primarily due to changes in WTI benchmark pricing, the impact of industry wide planned upgrader outages, as well as unplanned production outages at several third party oil sands facilities due to the fires at Fort McMurray.
- AECO natural gas prices averaged $1.18/GJ ($1.64/Mcfe) for the Q2/16, a decrease of 53% from $2.53/GJ for Q2/15, and a decrease of 41% from $2.00/GJ for Q1/16. The decrease in natural gas prices in Q2/16 compared with Q2/15 and Q1/16 was primarily due to warmer than normal winter temperatures in 2016 as US natural gas inventories were at near record high levels at the end of the winter season. Subsequent to June 30, 2016, reduced natural gas production growth and warm weather have resulted in an upward movement in natural gas pricing. Natural gas prices are anticipated to remain volatile in the near term as a result of excess storage inventory and continued strong US natural gas production. AECO natural gas prices as at July 15, 2016 are improving for the remainder of the year to $2.05/GJ in Q3/16 and $2.59/GJ in Q4/16.
NORTH WEST REDWATER UPGRADING AND REFINING
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 783,988 BOE/d for Q2/16, with approximately 95% of total production located in G7 countries.
- Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. As at June 30, 2016, the Company had in place bank credit facilities of approximately $7.4 billion, of which approximately $1.7 billion, net of commercial paper was undrawn and available.
- Canadian Natural maintained its strong balance sheet with debt to book capitalization of 40% at June 30, 2016, slightly higher than December 31, 2015 levels, despite year-to-date WTI pricing of US$39.50/bbl and AECO pricing of $1.59/GJ.
- On June 6, 2016, the Company distributed approximately 21.8 million PrairieSky common shares to the shareholders of record of the Company at a volume weighted price of $24.89, completing the previously announced Plan of Arrangement. Subsequent to the distribution, the Company''s ownership interest in PrairieSky decreased to approximately 22.6 million shares with a market value of approximately $575 million as at July 31, 2016. Current ownership is less than 10% of the issued and outstanding common shares of PrairieSky, satisfying the requirements of the purchase and sale agreement with PrairieSky.
- Canadian Natural has several financial levers in addition to capital flexibility, current availability under its credit facilities, strong cash flow and access to debt capital markets to effectively manage its liquidity, if necessary. These financial levers include the Company''s investment in PrairieSky and cross currency swaps maturing after 2020 with a value of approximately $355 million as at July 31, 2016. Additionally, the Company could monetize its royalty land portfolio producing approximately 2,550 BOE/d, of which approximately 1,050 BOE/d are third party royalty volumes.
- In March 2016, the UK government enacted legislation to reduce the PRT rate from 35% to 0% effective January 1, 2016. Allowable abandonment expenditures eligible for carryback to 2015 and prior taxation years for PRT purposes are still recoverable at a PRT rate of 50%. Subject to legislative approval, the UK government is also proposing to reduce the Supplementary Corporation Tax rate from 20% to 10% effective January 1, 2016.
- Canadian Natural declared a quarterly cash dividend on its common shares of C$0.23 per share payable on October 1, 2016.
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. Q3/16 production guidance before royalties is forecast to average between 458,000 and 484,000 bbl/d of crude oil and NGLs and between 1,645 and 1,685 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company''s website at .
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 six months ended June 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 June 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 six months ended June 30, 2016 in relation to the comparable periods in 2015 and the first 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 August 3, 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. 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.
(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 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) 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 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 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 deferred income tax liability of $228 million.
SUMMARY OF CONSOLIDATED NET EARNINGS (LOSS) AND CASH FLOW FROM OPERATIONS
The net loss for the six months ended June 30, 2016 was $444 million compared with a net loss of $657 million for the six months ended June 30, 2015. The net loss for the six months ended June 30, 2016 included net after-tax income of $309 million compared with expenses of $856 million for the six months ended June 30, 2015 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, (gain) loss from investments, 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 six months ended June 30, 2016 was $753 million compared with adjusted net earnings of $199 million for the six months ended June 30, 2015.
The net loss for the second quarter of 2016 was $339 million compared with a net loss of $405 million for the second quarter of 2015 and a net loss of $105 million for the first quarter of 2016. The net loss for the second quarter of 2016 included net after-tax expenses of $129 million compared with net after-tax expenses of $583 million for the second quarter of 2015 and net after-tax income of $438 million for the first quarter of 2016 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, (gain) loss from investments, gains 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 second quarter of 2016 was $210 million compared with adjusted net earnings of $178 million for the second quarter of 2015 and an adjusted net loss of $543 million for the first quarter of 2016.
The decrease in adjusted net earnings (loss) for the three and six months ended June 30, 2016 from the comparable periods in 2015 was primarily due to:
- lower crude oil and NGLs and natural gas netbacks in the Exploration and Production segments;
- lower crude oil and NGL sales volumes in the North America segment;
- lower realized SCO prices; and
- lower realized risk management gains;
partially offset by:
- higher SCO sales volumes in the Oil Sands Mining and Upgrading segment;
- higher crude oil and NGL sales volumes in the Offshore Africa segment;
- lower depletion, depreciation and amortization expense in the Exploration and Production segments; and
- the impact of a weaker Canadian dollar relative to the US dollar.
The decrease in adjusted net loss for the second quarter of 2016 from the first quarter of 2016 was primarily due to:
- higher crude oil and NGLs netbacks in the Exploration and Production segments; and
- higher realized SCO prices;
partially offset by:
- lower natural gas netbacks in the Exploration and Production segments;
- lower crude oil and NGLs and natural gas sales volumes in the North America segment;
- lower SCO sales volumes in the Oil Sands Mining and Upgrading segment;
- lower realized risk management gains; and
- the impact of a stronger Canadian dollar relative to the US dollar.
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 six months ended June 30, 2016 was $1,595 million compared with $2,873 million for the six months ended June 30, 2015. Cash flow from operations for the second quarter of 2016 was $938 million compared with $1,503 million for the second quarter of 2015 and $657 million for the first 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 second quarter of 2016 decreased 3% to 783,988 BOE/d from 805,547 BOE/d for the second quarter of 2015 and decreased 7% from 844,531 BOE/d for the first 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 increased 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 increased 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, as well as 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 second 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$39.56 per bbl for the six months ended June 30, 2016, a decrease of 26% from US$53.29 per bbl for the six months ended June 30, 2015. WTI averaged US$45.60 per bbl for the second quarter of 2016, a decrease of 21% from US$57.96 per bbl for the second quarter of 2015, and an increase of 36% from US$33.51 per bbl for the first 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$39.86 per bbl for the six months ended June 30, 2016, a decrease of 31% from US$57.90 per bbl for the six months ended June 30, 2015. Brent averaged US$45.80 per bbl for the second quarter of 2016, a decrease of 26% from US$61.95 per bbl for the second quarter of 2015, and an increase of 35% from US$33.92 per bbl for the first quarter of 2016.
WTI and Brent pricing for the six months ended June 30, 2016 continued to reflect volatility in supply and demand factors and geopolitical events. Benchmark pricing in the second quarter of 2016 increased from the first quarter of 2016, primarily due to expected declines in production and inventory as a result of reduced industry wide drilling activity, together with a slight increase in demand.
The WCS Heavy Differential averaged 35% for the six months ended June 30, 2016, compared with 25% for the six months ended June 30, 2015. The WCS Heavy Differential averaged 29% for the second quarter of 2016 compared with 20% for the second quarter of 2015 and 42% for the first quarter of 2016. Fluctuations in the WCS Heavy Differential reflect seasonal demand, changes in transportation logistics, and refinery utilization and shutdowns.
The SCO price averaged US$40.58 per bbl for the six months ended June 30, 2016, a decrease of 23% from US$52.98 per bbl for the six months ended June 30, 2015. The SCO price averaged US$47.39 per bbl for the second quarter of 2016, a decrease of 22% from US$60.61 per bbl for the second quarter of 2015, and an increase of 40% from US$33.77 per bbl for the first quarter of 2016. The fluctuations in SCO pricing for the second quarter of 2016 from the comparable periods were primarily due to changes in benchmark pricing, the impact of industry wide planned upgrader outages, and unplanned production outages at several third party oilsands facilities due to the Fort McMurray forest fires.
NYMEX natural gas prices averaged US$2.00 per MMBtu for the six months ended June 30, 2016, a decrease of 29% from US$2.81 per MMBtu for the six months ended June 30, 2015. NYMEX natural gas prices averaged US$1.95 per MMBtu for the second quarter of 2016, a decrease of 27% from US$2.67 per MMBtu for the second quarter of 2015, and a decrease of 4% from US$2.04 per MMBtu for the first quarter of 2016.
AECO natural gas prices averaged $1.59 per GJ for the six months ended June 30, 2016, a decrease of 40% from $2.67 per GJ for the six months ended June 30, 2015. AECO natural gas prices averaged $1.18 per GJ for the second quarter of 2016, a decrease of 53% from $2.53 per GJ for the second quarter of 2015, and a decrease of 41% from $2.00 per GJ for the first quarter of 2016.
The decrease in natural gas prices in the second quarter of 2016 compared with the second quarter of 2015 and the first quarter of 2016 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 winter season. Subsequent to June 30, 2016, reduced natural gas production growth and warm weather have resulted in an upward movement in natural gas pricing. Natural gas prices are anticipated to remain volatile in the near term as a result of excess storage inventory and continued strong US natural gas production.
DAILY PRODUCTION, before royalties
(1) Second quarter 2016 SCO production before royalties excludes 2,227 bbl/d of SCO consumed internally as diesel (first quarter 2016 - 2,562 bbl/d; second quarter 2015 - 2,410 bbl/d; six months ended June 30, 2016 - 2,394 bbl/d; six months ended June 30, 2015 - 2,045 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 six months ended June 30, 2016 decreased 6% to 524,668 bbl/d from 555,669 bbl/d for the six months ended June 30, 2015. Crude oil and NGL production for the second quarter of 2016 of 502,410 bbl/d was comparable with 509,047 bbl/d for the second quarter of 2015, and decreased 8% from 546,927 bbl/d for the first quarter of 2016. The decrease in crude oil and NGL production for the three and six months ended June 30, 2016 from the comparable periods in 2015 was primarily due to lower drilling activity and natural field declines in North America, partially offset by the impact of higher production at Horizon and in Offshore Africa. The decrease in crude oil and NGLs production for the second quarter of 2016 from the first quarter of 2016 primarily reflected lower drilling activity, natural field declines, the cyclic nature of thermal oil production at Primrose, and minor production disruptions in various fields. Crude oil and NGLs production for the second quarter of 2016 was slightly below the Company''s previously issued guidance of 504,000 to 529,000 bbl/d.
For 2016, annual production guidance is targeted to average between 514,000 and 563,000 bbl/d of crude oil and NGLs. Third quarter 2016 production guidance is targeted to average between 458,000 and 484,000 bbl/d of crude oil and NGLs.
Natural gas production for the six months ended June 30, 2016 decreased 2% to 1,738 MMcf/d from 1,775 MMcf/d for the six months ended June 30, 2015. Natural gas production for the second quarter of 2016 decreased 5% to 1,689 MMcf/d from 1,779 MMcf/d for the second quarter of 2015, and decreased 5% from 1,786 MMcf/d for the first quarter of 2016. The decrease in natural gas production for the three and six months ended June 30, 2016 from comparable periods primarily reflected lower production in North America due to the shut in of a third party processing facility and third party pipeline transportation restrictions. During the period mid-June to late July 2016, the Company had approximately 176 MMcf/d of production shut in due to the third party processing facility outage. On August 8, 2016 approximately 50 MMcf/d of volumes are targeted to return to service. In late September 2016 approximately 40 MMcf/d of additional production is targeted to return to service, with the remaining 86 MMcf/d of production targeted to return to service by December 2016.
Primarily as a result of the shut in of the third party processing facility, natural gas production for the second quarter of 2016 was slightly below the Company''s previously issued guidance of 1,720 to 1,760 MMcf/d. Annual production guidance is now targeted to average between 1,705 and 1,735 MMcf/d. Third quarter 2016 production guidance is targeted to average between 1,645 and 1,685 MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the six months ended June 30, 2016 decreased 13% to average 349,334 bbl/d from 403,571 bbl/d for the six months ended June 30, 2015. North America crude oil and NGLs production for the second quarter of 2016 decreased 12% to 328,681 bbl/d from 375,040 bbl/d for the second quarter of 2015, and decreased 11% from 369,987 bbl/d for the first quarter of 2016. The decrease in production for the three and six months ended June 30, 2016 from the comparable periods primarily reflected lower drilling activity, natural field declines, the cyclic nature of thermal oil production at Primrose, the temporary shut in of the Primrose East pipeline due to pipeline anomalies which was reinstated in late May 2016, as well as minor production disruptions at various fields. Crude oil and NGLs production for the second quarter of 2016 was within the Company''s previously issued guidance of 327,000 to 341,000 bbl/d. Third quarter 2016 production guidance is targeted to average between 337,000 and 351,000 bbl/d of crude oil and NGLs.
Natural gas production for the six months ended June 30, 2016 decreased 3% to average 1,672 MMcf/d from 1,715 MMcf/d for the six months ended June 30, 2015. Natural gas production for the second quarter of 2016 decreased 6% to 1,620 MMcf/d from 1,716 MMcf/d for the second quarter of 2015, and decreased 6% from 1,722 MMcf/d for the first quarter of 2016. The decrease in production for the three and six months ended June 30, 2016 from the comparable periods primarily reflected the shut in of a third party processing facility and third party pipeline transportation restrictions. During the period mid-June to late July 2016, the Company had approximately 176 MMcf/d of production shut in due to the third party processing facility outage. On August 8, 2016 approximately 50 MMcf/d of volumes are targeted to return to service. In late September 2016 approximately 40 MMcf/d of additional production is targeted to return to service, with the remaining 86 MMcf/d of production targeted to return to service by December 2016.
North America - Oil Sands Mining and Upgrading
SCO production for the six months ended June 30, 2016 increased 7% to 123,710 bbl/d from 115,283 bbl/d for the six months ended June 30, 2015. SCO production for the second quarter of 2016 increased 24% to average 119,511 bbl/d compared with 96,607 bbl/d for the second quarter of 2015 and decreased 7% from 127,909 bbl/d for the first quarter of 2016. The increase in production for the three and six months ended June 30, 2016 from the comparable periods in 2015 reflected high utilization rates and reliability following the turnaround completed in the prior year. The decrease in production in the second quarter of 2016 compared with the first quarter of 2016 reflected unplanned maintenance and repairs. Second quarter 2016 production of SCO was slightly below the Company''s previously issued guidance of 122,000 to 128,000 bbl/d. Third quarter 2016 production guidance is targeted to average between 72,000 and 80,000 bbl/d, reflecting the planned major maintenance turnaround.
North Sea
North Sea crude oil production for the six months ended June 30, 2016 increased 8% to 23,338 bbl/d from 21,676 bbl/d for the six months ended June 30, 2015. North Sea crude oil production for the second quarter of 2016 increased 15% to 23,360 bbl/d from 20,330 bbl/d for the second quarter of 2015 and was consistent with the first quarter of 2016 due to a focus on optimization activities, offsetting natural field declines.
Offshore Africa
Offshore Africa crude oil production for the six months ended June 30, 2016 increased 87% to 28,286 bbl/d from 15,139 bbl/d for the six months ended June 30, 2015. Offshore Africa crude oil production for the second quarter of 2016 increased 81% to 30,858 bbl/d from 17,070 bbl/d for the second quarter of 2015, and increased 20% from 25,714 bbl/d for the first quarter of 2016. Production volumes increased for the three and six months ended June 30, 2016 from the comparable periods reflecting the impact of additional wells coming on stream at the Espoir and Baobab fields during 2015 and 2016, partially offset by unplanned maintenance activities.
International Guidance
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Datum: 04.08.2016 - 03:00 Uhr
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