Canadian Natural Resources Limited Announces 2016 First Quarter Results
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 05/05/16 -- Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on first quarter 2016 results, Steve Laut, President of Canadian Natural stated, "The first three months of 2016 were operationally strong for Canadian Natural. The Company delivered production volumes within guidance and lower operating costs, with an operating cost reduction of 13% in E&P crude oil and NGLs and 14% in North America natural gas, on a per unit cost basis from Q1/15 levels. At Horizon, we achieved record low operating costs of $26.55/bbl and strong production volumes of approximately 128,000 bbl/d. Positive cash flow was delivered for all categories of our assets and reflects the strength of our diverse portfolio. The advancement of the Horizon Phase 2B expansion is progressing as planned and commissioning of certain Phase 2B systems commenced in March 2016. Our teams at Horizon are ready for execution of the scheduled 35 day major turnaround in early July 2016, where we will also tie in major components of Phase 2B. Following the turnaround, Phase 2B commissioning will continue in a staged approach to enhance the safe and effective targeted start-up of the expansion in October 2016."
Canadian Natural''s Chief Financial Officer, Corey Bieber, continued, "Cash flow of $657 million realized during the quarter was indicative of Canadian Natural''s positive netbacks on a per BOE basis reflecting the Company''s ability to respond quickly to unfavorable market changes through a flexible capital program and our commitment to achieving low cost structures. The first three months of 2016 reflected the lowest quarter for WTI benchmark pricing since the beginning of 2004, and yet the Company retained its investment grade status and maintained a strong balance sheet as we exited the quarter with a debt to book capitalization ratio of 38%."
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 Q1/16 of $657 million compared with $1,370 million for Q1/15 and $1,379 million for Q4/15. The decrease in Q1/16 from Q1/15 and Q4/15 primarily reflects lower benchmark pricing and lower sales volumes of North America crude oil and NGLs.
- For Q1/16, the Company had a net loss of $105 million compared to a net loss of $252 million in Q1/15 and net earnings of $131 million in Q4/15. Adjusted net loss from operations was $543 million in Q1/16 compared to adjusted net earnings of $21 million in Q1/15 and adjusted net loss of $49 million in Q4/15. Changes in adjusted net earnings primarily reflect the changes in cash flow from operations.
- Canadian Natural''s corporate production volumes averaged 844,531 BOE/d in Q1/16, were comparable to Q4/15 levels and within the Company''s guidance range of 829,000 BOE/d to 860,000 BOE/d. As expected, Q1/16 production volumes were 6% lower than Q1/15 levels due to natural production declines and a $315 million reduction in the Company''s Exploration & Production ("E&P") net capital expenditures, representing a 46% decrease year over year.
- Crude oil and NGL production volumes averaged 546,927 bbl/d in Q1/16, within the Company''s guidance range of 532,000 to 557,000 bbl/d.
-- During the quarter, strong operational performance at Horizon Oil Sands ("Horizon") continued and was demonstrated by quarterly production volumes averaging 127,909 bbl/d of synthetic crude oil ("SCO") and record low quarterly operating costs of $26.55/bbl (US$19.33/bbl).
-- International E&P quarterly crude oil production volumes averaged 49,031 bbl/d, representing a 35% and 2% increase over Q1/15 and Q4/15 levels.
-- Infilling drilling programs at Espoir and Baobab increased Offshore Africa crude oil production volumes by 95% and 4% from Q1/15 and Q4/15 levels respectively. Overall, the programs were successful as production exceeded targets and costs were below original sanction targets. The drilling programs at Espoir and Baobab are now complete and International E&P crude oil production volumes are targeted to increase by 27% at the midpoint of 2016 annual guidance over 2015 levels.
-- Continued success of production and waterflood optimization in the North Sea is reflected by maintaining crude oil production volumes in Q1/16 relative to Q1/15 and Q4/15 levels respectively. Quarterly crude oil operating costs for the North Sea averaged $47.69/bbl, reductions of 27% and 16% from Q1/15 and Q4/15 levels respectively, as a result of the Company''s continued focus on effective and efficient operations.
-- The Company achieved record quarterly natural gas volumes of 1,786 MMcf/d, 1% and 5% higher than Q1/15 and Q4/15 levels respectively. North America natural gas operating costs in Q1/16 averaged $1.18/Mcf compared to $1.38/Mcf in Q1/15, representing a 14% decrease which reflects a continued focus on cost optimization.
- The Company continues to execute capital discipline by proactively managing its crude oil and natural gas drilling programs. In Q1/16, the Company''s drilling activity consisted of 12 net wells compared to 53 net wells in Q1/15, a 77% decrease while Q1/16 production volumes decreased by 6% to 844,531 BOE/d from 898,053 BOE/d in Q1/15.
- During Q1/16, Canadian Natural continued to realize positive results from its commitment to the enhancement of its effective and efficient operations. A comparison of per unit operating cost reductions achieved in the quarter is demonstrated below.
- Due to the timing of liftings from the various fields in Offshore Africa that have different cost structures, and a weaker Canadian dollar, a quarterly cost comparison for Offshore Africa year over year is not indicative of performance. However, on an annual basis, due to a continued focus on effective and efficient operations, Offshore Africa crude oil operating costs are targeted to reduce by 50% on a produced barrel basis, based on the midpoint of the Company''s 2016 annual guidance over 2015.
- In early July 2016, the Company targets to begin a scheduled 35 day major turnaround at Horizon to complete maintenance activities within the plant facilities. Planning activities for the turnaround are complete, and the teams and systems are in place and ready to execute. Concurrent with the completion of maintenance activities, tie in of the major components of the Horizon Phase 2B expansion will be accomplished during the planned outage.
- 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 5 months. 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 with a targeted utilization rate range of 92% to 96%, resulting in a step change in the sustainability of the production and cash flow profiles for the Company.
-- Construction execution of the Horizon Phase 2B expansion is progressing as scheduled and at March 31, 2016, achieved 84% physical completion. Commissioning activities of the plant systems commenced in March 2016 and are on schedule. The Phase 2B expansion''s commissioning plan will be a staged approach, and the targeted completion of commissioning for all systems are as follows; 20% by May 2016, 60% by June 2016 and 80% by July 2016. Commissioning in the latter half of Q3/16 will primarily consist of non-critical, non-process systems.
-- By taking a staged approach to commissioning of the plant systems, the Company is able to enhance the safe and effective start-up of the expansion in October 2016. The commissioning teams have been in place for over 2 years with key Horizon operational personnel in place for approximately 1.5 years, ensuring that the Company has the ability to complete construction and effectively commission and start up Horizon Phase 2B on schedule and on budget.
-- 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 Q1/16 totalled $422 million. 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. Canadian Natural''s total Horizon production volumes are targeted to average 250,000 bbl/d of SCO with operating costs trending below C$25.00/bbl (US$19.38/bbl).
- Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. As at March 31, 2016, the Company had in place bank credit facilities of approximately $7.4 billion, of which approximately $2.3 billion was undrawn and available.
- Canadian Natural maintained its strong balance sheet with debt to book capitalization of 38% at March 31, 2016, equivalent to December 31, 2015 levels, despite Q1/16 WTI pricing of US$33.51/bbl and AECO pricing of $2.00/GJ.
- Canadian Natural declared a quarterly cash dividend on its common shares of C$0.23 per share payable on July 1, 2016.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate effective and efficient operations, Canadian Natural focuses its activities in core regions where the Company owns a substantial land base and associated infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning and operating associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Furthermore, the Company maintains large project inventories and production diversification among each of the commodities it produces; 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. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
Drilling Activity
- As a direct result of the decrease in crude oil and natural gas pricing, the Company''s flexible capital allocation program and other external events, the Company proactively reduced its 2016 drilling programs. Drilling activity, excluding strat/service wells, in Q1/16 consisted of 12 net wells compared to 53 net wells in Q1/15.
North America Exploration and Production
- Q1/16 production volumes of North America crude oil and NGLs averaged 251,943 bbl/d, representing an expected decrease of 12% and 3% from Q1/15 and Q4/15 levels. The year over year production decline was modest considering an 83% reduction in drilling activity from 40 net wells in Q1/15 to 7 net wells in Q1/16.
- North America light crude oil and NGL quarterly production averaged 90,067 bbl/d in Q1/16, representing a 7% decrease from Q1/15 levels and comparable to Q4/15 levels.
- Quarterly production volumes from Pelican Lake operations averaged 47,612 bbl/d, representing a 7% and 4% decrease from Q1/15 and Q4/15 levels respectively. The slight decrease in production from Q4/15 was due to downtime associated with increased wellbore cleanouts of injection and production wells, reduced polymer injection in some areas to improve reservoir conformance and natural production declines of non-polymer flooded areas of the field. Production volumes are currently exceeding 49,000 bbl/d. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake.
- Q1/16 primary heavy crude oil production averaged 114,264 bbl/d, a decrease of 17% and 5%, as expected, from Q1/15 and Q4/15 levels. This production decline reflects the Company''s proactive decision to reduce its primary heavy crude oil drilling program since 2014. Additionally during the quarter, as a result of unfavorable economic conditions, an average of approximately 900 bbl/d of primary heavy crude oil production volumes was shut in. In Q1/16, 6 net wells were drilled compared to 36 net wells in Q1/15.
- Canadian Natural continued to realize reduced quarterly operating costs of its North America E&P crude oil and NGL products on a per unit basis in Q1/16 from Q1/15 levels.
-- North America light crude oil and NGL quarterly operating costs were reduced by 21%.
-- At Pelican Lake, industry leading operating costs of $6.92/bbl were achieved, representing a 20% decrease.
-- Strong operating cost reductions of 24% were realized within the primary heavy crude oil operations.
- The Company''s North America E&P crude oil and NGL annual production guidance is targeted to range from 235,000 bbl/d - 245,000 bbl/d in 2016.
- Thermal in situ quarterly production achieved strong volumes of 118,044 bbl/d in Q1/16, slightly above the midpoint of the Company''s guidance range, representing a decrease of 19% and 13% from Q1/15 and Q4/15 levels. The decrease in production volumes reflect reduced drilling programs at Primrose since 2014 and the temporary curtailment of production volumes at Primrose East.
- Canadian Natural has a comprehensive pipeline and proactive inspection program and as a result of inspection of an above-ground pipeline, pipeline cracks were observed in January 2016 at Primrose East. Production volumes of approximately 15,000 bbl/d were temporarily shut in to allow for investigation, engineering assessment and repair of the pipeline. The Company now targets to ramp up Primrose East production volumes commencing in May 2016.
- Q1/16 production volumes at Kirby South averaged 34,570 bbl/d. Production was affected in the quarter as a result of a third party power outage in late December causing damage to three evaporators at the Kirby South facility. Repair of the evaporators was completed and production ramped up in March 2016. Current production volumes are approximately 38,000 bbl/d with a steam to oil ratio ("SOR") of 2.7.
- The Alberta Energy Regulator''s ("AER") final investigation report on the Primrose flow to surface events was released on March 21, 2016. The AER''s report is consistent with Canadian Natural''s interim Causation Report submitted to the AER on June 27, 2014 as well as Canadian Natural''s Final Report submitted on April 1, 2015.
- Record North America natural gas quarterly production volumes averaging 1,722 MMcf/d were achieved in Q1/16, an increase of 1% and 5% from Q1/15 and Q4/15 levels respectively. The increase from Q4/15 to Q1/16 levels reflects the reinstatement of production following third party pipeline transportation restrictions in 2015, partially offset by the impact of shut-in volumes of approximately 43 MMcf/d resulting from uneconomic natural gas pricing and continued third party pipeline transportation restrictions. Additionally, approximately 22 MMcf/d was shut in due to an unplanned restriction at a third party processing facility in Northeast British Columbia ("NE BC"), which is expected to impact Q2/16 production volumes by approximately 20 MMcf/d.
- 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 $0.21/Mcfe in Q1/16.
- North America natural gas quarterly operating costs were $1.18/Mcf in Q1/16, a 14% decrease from Q1/15 levels of $1.38/Mcf, reflecting a continued focus on cost optimization.
- In response to current natural gas pricing, the Company targets to shut in additional volumes throughout the remainder of 2016 of approximately 40 MMcf/d, primarily related to properties with high third party processing fees. Consequently, the Company''s total natural gas annual production guidance has been revised and is targeted to range from 1,725 MMcf/d - 1,785 MMcf/d in 2016.
International Exploration and Production
- International crude oil production averaged 49,031 bbl/d in Q1/16, an increase of 35% and 2% from Q1/15 and Q4/15 levels, respectively. The increase in production volumes from Q1/15 levels was primarily due to additional wells coming onstream during 2015 and Q1/16 as part of the infill drilling programs at the Baobab and Espoir fields. Production volumes were relatively flat compared to Q4/15 levels due to the impact of a temporary shut-in at the Baobab field due to a riser failure in late December 2015, which was reinstated in late January 2016 after inspection of the riser system. International E&P crude oil Q2/16 production volumes are targeted to range from 55,000 bbl/d - 60,000 bbl/d, representing a 17% increase at the midpoint over Q1/16 levels.
- Infilling drilling programs at Espoir and Baobab increased Offshore Africa crude oil production volumes by 95% and 4% from Q1/15 and Q4/15 levels respectively. Overall, the programs were successful as production exceeded targets and costs were below original sanction targets. The drilling programs at Espoir and Baobab are now complete and International E&P crude oil annual production volumes are targeted to increase by 27% at the midpoint of 2016 annual guidance over 2015 levels.
- Continued success of production and waterflood optimization in the North Sea is reflected by maintaining crude oil production volumes in Q1/16 relative to Q1/15 and Q4/15 levels respectively. Quarterly crude oil operating costs for the North Sea averaged $47.69/bbl, reductions of 27% and 16% from Q1/15 and Q4/15 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. First quarter 2016 SCO production before royalties excludes 2,562 bbl/d of SCO consumed internally as diesel (fourth quarter 2015 - 2,337 bbl/d; first quarter 2015 - 1,676 bbl/d).
- Horizon''s strong operational performance continued in Q1/16 as production volumes averaged 127,909 bbl/d of SCO, which met the upper end of the Company''s production guidance of 122,000 bbl/d - 128,000 bbl/d.
- The Company achieved record low quarterly operating costs at Horizon of $26.55/bbl (US$19.33/bbl), an 11% reduction from Q1/15 levels, as a result of safe, steady and reliable operations and a focus on continuous improvement during the quarter.
- In early July 2016, the Company targets to begin a scheduled 35 day major turnaround at Horizon to complete maintenance activities within the plant facilities. Planning activities for the turnaround are complete, and the teams and systems are in place and ready to execute. Concurrent with the completion of maintenance activities, tie in of major components of the Horizon Phase 2B expansion will be accomplished during the planned outage.
- The Horizon Phase 2B expansion is targeted to add 45,000 bbl/d of SCO production capacity. Construction execution of the Horizon Phase 2B expansion is progressing as scheduled and at March 31, 2016, achieved 84% physical completion. Commissioning activities of the plant systems commenced in March 2016 and are on schedule. The Phase 2B expansion''s commissioning plan will be a staged approach, and the targeted completion of commissioning for all systems are as follows; 20% by May 2016, 60% by June 2016 and 80% by July 2016. Commissioning in the latter half of Q3/16 will primarily consist of non-critical, non-process systems.
- By taking a staged approach to commissioning of the plant systems, the Company is able to enhance the safe and effective start-up of the expansion in October 2016. The commissioning teams have been in place for over 2 years with key Horizon operational personnel in place for approximately 1.5 years, ensuring that the Company has the ability to complete construction and effectively commission and start up Horizon Phase 2B on schedule and on budget.
- The Phase 3 expansion is currently on budget and on schedule. This Phase is 79% 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 74 of the Horizon expansion includes research into tailings management and technological investment. This project remains on track and is 59% physically complete.
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.
(i) Based on current indicative pricing as at May 1, 2016. Monthly USD/CAD exchange rates are based upon the average noon rates for each month. For June, the USD/CAD exchange rate was based upon the forward curve rate based on May 1, 2016 spot rate.
- Q1/16 WTI pricing averaged US$33.51/bbl as compared to US$48.57/bbl in Q1/15. Volatility in supply and demand factors and geopolitical events remain primary factors in the current WTI and Brent pricing environment. The Organization of the Petroleum Exporting Countries'' ("OPEC") decision not to curtail oil production to offset the excess world supply resulted in a year over year decline in benchmark pricing.
- In Q1/16, the WCS differential to WTI averaged US$14.24/bbl or 42% as compared to Q1/15 of US$14.75/bbl or 30%. May 2016 and June 2016 indications of the WCS blend differential of US$14.28/bbl or 31%
and US$13.55/bbl or 29% respectively, are normal given the trending WTI price curve. Seasonal demand fluctuations, changes in transportation logistics and refinery utilization and shutdowns will continue to be reflected in WCS pricing.
- Canadian Natural contributed approximately 226,000 bbl/d of its heavy crude oil stream to the WCS blend in Q1/16. The Company remains the largest contributor to the WCS blend, accounting for 52% of the total blend.
- Q1/16 SCO pricing averaged US$33.77/bbl in Q1/16 as compared to US$45.26/bbl in Q1/15 and US$42.77/bbl in Q4/15. Fluctuations in SCO pricing during Q1/16 were a result of changes in WTI benchmark pricing and unplanned industry upgrader outages.
- Q1/16 AECO pricing averaged $2.00/GJ, decreasing by 29% and 20% from $2.80/GJ and $2.51/GJ in Q1/15 and Q4/15 respectively. The decrease in natural gas prices in Q1/16 compared with Q1/15 and Q4/15 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. Strong natural gas production volumes in North America continue to put pressure on natural gas prices. Natural gas prices are anticipated to remain volatile in the near future as a result of the excess inventory at the end of the 2015/2016 winter season.
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 844,531 BOE/d for Q1/16, with approximately 96% of total production located in G8 countries.
- Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at March 31, 2016, the Company had in place bank credit facilities of approximately $7.4 billion, of which approximately $2.3 billion was undrawn and available.
-- In March 2016, Canadian Natural repaid US$500 million of US dollar denominated debt securities by drawing on its revolving bank facilities, net of cross currency contracts settled during the quarter.
- Canadian Natural maintained its strong balance sheet with debt to book capitalization of 38% at March 31, 2016, equivalent to December 31, 2015 levels, despite quarterly WTI pricing of US$33.51/bbl and AECO pricing of $2.00/GJ.
- Canadian Natural''s estimate of its current production volumes attributed to its royalty portfolio is approximately 2,200 BOE/d, of which approximately 1,000 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 July 1, 2016.
- The Company has a strong balance sheet and cash flow generation which enables it to weather volatility in commodity prices. Canadian Natural retains additional capital expenditure program flexibility to proactively adapt to changing market conditions.
OUTLOOK
The Company forecasts 2016 production levels before royalties to average between 514,000 and 563,000 bbl/d of crude oil and NGLs and between 1,725 and 1,785 MMcf/d of natural gas. Q2/16 production guidance before royalties is forecast to average between 504,000 and 529,000 bbl/d of crude oil and NGLs and between 1,720 and 1,760 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 months ended March 31, 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 March 31, 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 months ended March 31, 2016 in relation to the first quarter of 2015 and the fourth quarter of 2015. 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 May 4, 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.
(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.
(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. During the fourth quarter of 2015, the Company recorded a pre-tax gain of $690 million ($627 million after-tax) related to the disposition of a number of North America royalty income assets.
(7) In connection with the Company''s notice of withdrawal from Block CI-514 in Cote d''Ivoire, Offshore Africa in the fourth quarter of 2015, the Company derecognized $96 million ($70 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 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 first quarter of 2016 was $105 million compared with a net loss of $252 million for the first quarter of 2015 and net earnings of $131 million for the fourth quarter of 2015. The net loss for the first quarter of 2016 included net after-tax income of $438 million compared with net after-tax expenses of $273 million for the first quarter of 2015 and net after-tax income of $180 million for the fourth quarter of 2015 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 effect of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, adjusted net loss from operations for the first quarter of 2016 was $543 million compared with adjusted net earnings of $21 million for the first quarter of 2015 and an adjusted net loss of $49 million for the fourth quarter of 2015.
The decrease in adjusted net earnings (loss) for the first quarter of 2016 from the first quarter of 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 SCO sales volumes in the Oil Sands Mining and Upgrading segment;
- lower realized SCO prices;
- lower realized risk management gains; and
- higher realized foreign exchange losses;
partially offset by:
- 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 increase in adjusted net loss for the first quarter of 2016 from the fourth quarter of 2015 was primarily due to:
- lower crude oil and NGLs and natural gas netbacks in the Exploration and Production segments;
- lower realized SCO prices;
- lower crude oil and NGLs sales volumes in the North America segment; and
- lower realized risk management gains;
partially offset by:
- higher natural gas sales volumes in the North America 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 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 first quarter of 2016 was $657 million compared with $1,370 million for the first quarter of 2015 and $1,379 million for the fourth quarter of 2015. The fluctuations in cash flow from operations from the comparable periods were primarily due to the factors noted above relating to the decrease in adjusted net earnings (loss), as well as due to the impact of cash taxes.
Total production before royalties for the first quarter of 2016 decreased 6% to 844,531 BOE/d from 898,053 BOE/d for the first quarter of 2015 and decreased 1% from 855,800 BOE/d for the fourth quarter of 2015.
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 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 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, and the impact of turnarounds at Horizon and higher drilling in Cote d''Ivoire in Offshore Africa. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore Africa.
- 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 natural gas production due to third party pipeline restrictions and related pricing impacts, shut-in volumes 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, and turnarounds at Horizon.
- Depletion, depreciation and amortization - Fluctuations due to changes in sales volumes including the impact and timing of acquisitions, 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 commodity volumes hedged and the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company''s risk management activities.
- Foreign exchange rates - Changes 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 on 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 first quarter of 2016, realized prices continued to be supported by the weaker Canadian dollar, which increased the Canadian dollar sales price the Company received for its crude oil and natural gas sales, as realized pricing 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$33.51 per bbl for the first quarter of 2016, a decrease of 31% from US$48.57 per bbl for the first quarter of 2015, and a decrease of 21% from US$42.17 per bbl for the fourth quarter of 2015.
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$33.92 per bbl for the first quarter of 2016, a decrease of 37% from US$53.80 per bbl for the first quarter of 2015, and a decrease of 22% from US$43.59 per bbl for the fourth quarter of 2015.
WTI and Brent pricing continued to reflect volatility in supply and demand factors and geopolitical events. An oversupply of crude oil in the world market contributed to a further decrease in crude oil benchmark pricing in the first quarter of 2016. OPEC''s decision not to curtail crude oil production to offset the excess world supply continues to put downward pressure on benchmark pricing.
The WCS Heavy Differential averaged 42% for the first quarter of 2016 compared with 30% for the first quarter of 2015 and 34% for the fourth quarter of 2015. Fluctuations in the WCS Heavy Differential reflect seasonal demand, changes in transportation logistics, and refinery utilization and shutdowns.
The SCO price averaged US$33.77 per bbl for the first quarter of 2016, a decrease of 25% from US$45.26 per bbl for the first quarter of 2015, and a decrease of 21% from US$42.77 per bbl for the fourth quarter of 2015. The fluctuations in SCO pricing for the first quarter of 2016 from the comparable periods were primarily due to changes in WTI benchmark pricing and the impact of industry wide unplanned upgrader outages.
NYMEX natural gas prices averaged US$2.04 per MMBtu for the first quarter of 2016, a decrease of 31% from US$2.96 per MMBtu for the first quarter of 2015, and a decrease of 11% from US$2.28 per MMBtu for the fourth quarter of 2015.
AECO natural gas prices averaged $2.00 per GJ for the first quarter of 2016, a decrease of 29% from $2.80 per GJ for the first quarter of 2015, and a decrease of 20% from $2.51 per GJ for the fourth quarter of 2015.
The decrease in natural gas prices in the first quarter of 2016 compared with the first quarter of 2015 and the fourth quarter of 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 winter season. Strong natural gas production volumes continue to put pressure on natural gas prices. Natural gas prices are anticipated to remain volatile in the near term as a result of the excess inventory at the end of the 2015/2016 winter season.
DAILY PRODUCTION, before royalties
(1) First quarter 2016 SCO production before royalties excludes 2,562 bbl/d of SCO consumed internally as diesel (fourth quarter 2015 - 2,337 bbl/d; first quarter 2015 - 1,676 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 first quarter of 2016 decreased 9% to 546,927 bbl/d from 602,809 bbl/d for the first quarter of 2015, and decreased 4% from 572,000 bbl/d for the fourth quarter of 2015. The decrease in crude oil and NGLs production from comparable periods primarily reflected lower drilling activity in North America and natural field declines, partially offset by optimization activities in various fields and increased production in the international segments. Crude oil and NGLs production for the first quarter of 2016 was within the Company''s previously issued guidance of 532,000 to 557,000 bbl/d.
For 2016, annual production guidance is targeted to average between 514,000 and 563,000 bbl/d of crude oil and NGLs. Second quarter 2016 production guidance is targeted to average between 504,000 and 529,000 bbl/d of crude oil and NGLs.
Natural gas production for the first quarter of 2016 increased 1% to 1,786 MMcf/d from 1,771 MMcf/d for the first quarter of 2015, and increased 5% from 1,703 MMcf/d for the fourth quarter of 2015. The increase in natural gas production for the first quarter of 2016 from the first quarter of 2015 primarily reflected higher production in Offshore Africa and North America. The increase from the fourth quarter of 2015 was primarily due to increased production in the first quarter of 2016 following partial reinstatement of volumes related to third party pipeline transportation restrictions in 2015. Production volumes in the first quarter of 2016 were reduced by approximately 43 MMcf/d related to sustained low natural gas prices and continued third party pipeline transportation restrictions. Additionally, approximately 22 MMcf/d was shut in due to an unplanned restriction at a third party processing facility in Northeast British Columbia. These third party processing facility issues are expected to have a similar volume impact in the second quarter of 2016.
In response to current natural gas pricing, the Company targets to shut in additional volumes throughout the remainder of 2016 of approximately 40 MMcf/d, primarily related to properties with high third party processing fees. Annual production guidance has been revised and is now targeted to average between 1,725 and 1,785 MMcf/d.
Natural gas production for the first quarter of 2016 was within the Company''s previously issued guidance of 1,780 to 1,820 MMcf/d. Second quarter 2016 production guidance is targeted to average between 1,720 and 1,760 MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the first quarter of 2016 decreased 14% to 369,987 bbl/d from 432,419 bbl/d for the first quarter of 2015, and decreased 6% from 395,008 bbl/d for the fourth quarter of 2015. The decrease in production for the first quarter of 2016 from comparable periods primarily reflected lower drilling activity and natural field declines, partially offset by optimization activities in various fields. Crude oil and NGLs production for the first quarter of 2016 was within the Company''s previously issued guidance of 363,000 to 377,000 bbl/d. Second quarter 2016 production guidance is targeted to average between 327,000 and 341,000 bbl/d of crude oil and NGLs.
Natural gas production for the first quarter of 2016 increased 1% to 1,722 MMcf/d from 1,713 MMcf/d for the first quarter of 2015, and increased 5% from 1,635 MMcf/d for the fourth quarter of 2015. The increase in natural gas production from the fourth quarter of 2015 was primarily due to the partial reinstatement of volumes related to third party pipeline transportation restrictions in 2015. Production volumes in the first quarter of 2016 reflected the impact of sustained low natural gas prices and continued third party pipeline transportation restrictions as well as additional volumes shut in due to an unplanned restriction at a third party processing facility in Northeast British Columbia. These third party processing facility issues are expected to have a similar volume impact in the second quarter of 2016.
North America - Oil Sands Mining and Upgrading
SCO production for the first quarter of 2016 was comparable with the fourth quarter of 2015 and decreased 5% to average 127,909 bbl/d compared with 134,166 bbl/d for the first quarter of 2015. Production in the first quarter of 2016 continued to reflect high utilization rates and reliability. As expected, the decrease from the first quarter of 2015 reflected planned maintenance in the first quarter of 2016. First quarter 2016 production of SCO was at the high end of the Company''s previously issued guidance of 122,000 to 128,000 bbl/d. Second quarter 2016 production guidance is targeted to average between 122,000 and 128,000 bbl/d.
North Sea
North Sea crude oil production for the first quarter of 2016 of 23,317 bbl/d was comparable with 23,036 bbl/d for the first quarter of 2015 and 23,110 bbl/d for the fourth quarter of 2015 due to a focus on optimization activities, offsetting natural field declines.
Offshore Africa
Offshore Africa crude oil production for the first quarter of 2016 increased 95% to 25,714 bbl/d from 13,188 bbl/d for the first quarter of 2015, and increased 4% from 24,832 bbl/d for the fourth quarter of 2015. Production volumes increased for the first quarter of 2016 as an additional well came on stream at each of the Espoir and the Baobab fields during the quarter, partially offset by natural field declines as well as the impact of a temporary shut in at the Baobab field due to a riser failure in late December 2015. After inspection of the riser system, production was reinstated in late January 2016.
International Guidance
The Company''s North Sea and Offshore Africa first quarter 2016 crude oil production of 49,031 bbl/d was within the Company''s previously issued guidance of 47,000 to 52,000 bbl/d. Second quarter 2016 production guidance is targeted to average between 55,000 and 60,000 bbl/d of crude oil.
International Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. Revenue has not been recognized in the International business segments on crude oil volumes that were stored in various storage facilities or FPSOs, as follows:
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
PRODUCT PRICES - EXPLORATION AND PRODUCTION
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
North America
North America realized crude oil prices averaged $20.77 per bbl for the first quarter of 2016, a decrease of 41% compared with $35.22 per bbl for the first quarter of 2015 and a decrease of 34% compared with $31.51 per bbl for the fourth quarter of 2015. The decrease in realized crude oil prices for the first quarter of 2016 from the comparable periods was primarily due to lower WTI benchmark pricing and a widening WCS Heavy Differential as a percentage of WTI, partially offset by the impact of a weakening Canadian dollar. The Company continues to focus on its crude oil blending marketing strategy and in the first quarter of 2016 contributed approximately 226,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas prices decreased 35% to average $2.05 per Mcf for the first quarter of 2016 compared with $3.14 per Mcf for the first quarter of 2015, and decreased 25% compared with $2.73 per Mcf for the fourth quarter of 2015.
The decrease in natural gas prices in the first quarter of 2016 compared with the first quarter of 2015 and the fourth quarter of 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 winter season. Strong natural gas production volumes continue to put pressure on natural gas prices. Natural gas prices are anticipated to remain volatile in the near term as a result of the excess inventory at the end of the 2015/2016 winter season.
Comparisons of the prices received in North America Exploration and Production by product type were as follows:
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of blending costs and excluding risk management activities.
North Sea
North Sea realized crude oil prices decreased 30% to average $45.04 per bbl for the first quarter of 2016 from $64.59 per bbl for the first quarter of 2015 and decreased 22% from $57.50 per bbl for the fourth quarter of 2015. Realized crude oil prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings of each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. The decrease in realized crude oil prices for the first quarter of 2016 from the comparable periods reflected prevailing Brent benchmark pricing at the time of liftings, partially offset by the weaker Canadian dollar.
Offshore Africa
Offshore Africa realized crude oil prices decreased 40% to average $42.99 per bbl for the first quarter of 2016 fro
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Datum: 05.05.2016 - 03:00 Uhr
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