Canadian Natural Resources Limited Announces 2015 First Quarter Results
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 05/07/15 -- Commenting on first quarter results, Steve Laut, President of Canadian Natural (TSX: CNQ) (NYSE: CNQ) stated, "As expected, low commodity prices impacted first quarter cash flow and earnings. Operationally, the first quarter was very strong with record quarterly production approaching 900,000 BOE/d. Crude oil production increased by 23% and natural gas production increased by 51% from the first quarter of 2014. Canadian Natural's operations continue to be effective and efficient as operating costs reduced by 22% for total liquids and 10% for North America natural gas in the first quarter of 2015 versus the same quarter in 2014. Our performance reflects the resilience of our strong, diverse and well balanced asset base, the robustness of our business model, and the effectiveness of our strategies combined with our ability to execute these strategies."
Canadian Natural's Chief Financial Officer, Corey Bieber, continued, "Canadian Natural continues to prudently manage its balance sheet and liquidity. Following the precipitous fall in crude oil pricing, we proactively adjusted our capital spending profile to reflect targeted internal cash flow generation while optimizing the value of investments made and protecting the growth profile of the Horizon Project. We continue to focus on cost reduction and efficiency improvements to further improve returns in the current price environment. Our balance sheet metrics remain strong, giving us the financial flexibility to deliver our defined growth plan and continue to drive long-term shareholder value creation irrespective of the business cycle."
QUARTERLY HIGHLIGHTS
(1) Adjusted net 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.
- Strong operational performance continues for all business segments of the Company. Canadian Natural's Exploration and Production ("E&P") assets continue to generate free cash flow and support the transition to a longer life and lower decline asset base. Q1/15 operational highlights include:
-- Record overall quarterly corporate production of 898,053 BOE/d driven by records in both quarterly crude oil and NGL, and natural gas production volumes.
-- Corporate quarterly crude oil and NGL production reached record levels averaging 602,809 bbl/d for Q1/15, an increase of 23% and 5% from Q1/14 and Q4/14 levels respectively.
--- The Company's E&P crude oil and NGL segment showed strong overall production volumes driven by:
a. Record North America light crude oil and NGL quarterly production volumes of 97,561 bbl/d.
b. Record thermal in situ oil sands ("thermal") quarterly production performance of 146,086 bbl/d.
c. Strong primary heavy crude oil production volumes of 137,687 bbl/d.
d. Strong Pelican Lake quarterly production volumes of 51,085 bbl/d.
e. International quarterly production volumes of 36,224 bbl/d.
--- Record quarterly production volumes of 134,166 bbl/d were achieved at Horizon Oil Sands ("Horizon").
-- Natural gas production achieved record quarterly volumes averaging 1,771 MMcf/d in Q1/15, an increase of 51% and 2% from Q1/14 and Q4/14 levels respectively.
- Canadian Natural's 2015 capital expenditure guidance has been updated to reflect capital cost savings across all business segments. The Company's targeted 2015 capital expenditure guidance has been reduced further by approximately $300 million, as compared to capital guidance released in March 2015, to approximately $5.7 billion. Annual production guidance remains unchanged and is targeted to deliver 11% annual production growth in 2015 over 2014 levels.
- Canadian Natural targets to achieve approximately $390 million of additional operating costs savings in 2015 in comparison to the 2015 original budgeted operating cost targets announced in November 2014. In comparison to 2014, these savings plus the initiatives underway through effective and efficient operations, innovation initiatives, reduced energy costs and higher production volumes result in 2015 operating costs being approximately $925 million less than what they would have been at 2014 unit cost rates.
-- Overall corporate crude oil and NGL operating costs of $19.03/bbl in Q1/15 decreased by $5.33/bbl and $3.01/bbl from Q1/14 and Q4/14 levels, respectively.
a. In Q1/15, North America E&P (including thermal) crude oil and NGL quarterly operating costs were $13.75/bbl, which decreased by 16% and 4% from Q1/14 and Q4/14 levels respectively. Annual operating cost guidance is targeted to range from $12.50/bbl to $14.50/bbl.
b. Horizon quarterly operating costs showed significant improvement at $29.73/bbl in Q1/15, with decreases of 28% from $41.11/bbl in Q1/14 and 13% from $34.34/bbl in Q4/14. The annual operating cost guidance has been reduced and is targeted to range from $31.00/bbl to $34.00/bbl in 2015. Strong operating costs reflect safe, steady, reliable production and improved operating efficiencies.
-- In Q1/15, North America natural gas operating costs were $1.38/Mcf, a 10% decrease from Q1/14 levels of $1.54/Mcf, reflecting a continued focus on cost optimization after acquiring higher cost production volumes in 2014. In 2015, the Company will continue its strong, effective and efficient operations with a focus on cost optimization. As a result, annual operating cost guidance has been reduced and is targeted to range from $1.25/Mcf to $1.35/Mcf.
- Canadian Natural generated cash flow from operations of approximately $1.4 billion in Q1/15 compared to approximately $2.1 billion in Q1/14 and $2.4 billion in Q4/14. The decrease in Q1/15 from Q1/14 and Q4/14 primarily reflects lower crude oil, NGL and natural gas realized pricing in North America, lower synthetic crude oil ("SCO") realized pricing, partially offset by higher North America crude oil and NGL and SCO sales volumes and the impact of a weaker Canadian dollar as compared to the US dollar.
- The Company incurred a net loss in Q1/15 of $252 million, compared to net earnings of $622 million in Q1/14 and $1,198 million in Q4/14. Adjusted net earnings from operations for Q1/15 were $21 million, compared to adjusted net earnings of $921 million in Q1/14 and $756 million in Q4/14. Changes in net earnings and adjusted net earnings largely reflect the changes in cash flow.
- Canadian Natural is continuing its review of its royalty lands and royalty revenue portfolio and the best options to maximize shareholder value. Options for a final strategy as it relates to its fee title and royalty lands are as follows:
-- Divestiture of the portfolio assets,
-- Spin-off of the portfolio assets (IPO), or
-- Retention of the portfolio assets in their current state.
--- The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Q4/14 production volumes on the royalty lands increased 3% and 14% from Q3/14 and Q2/14 levels respectively. Drilling activity has been strong on the Company's royalty lands with 144 wells drilled in Q4/14 and 75 wells drilled in Q1/15.
- Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on
July 1, 2015.
CORPORATE UPDATE
Dr. Eldon Smith, due to reaching the mandatory retirement age, and Mr. Keith A.J. MacPhail, due to a desire to free up more time for personal interests, have chosen to not stand for re-election to the Company's Board of Directors in 2015. The Board of Directors and the Senior Management of Canadian Natural wish to thank Dr. Smith and Mr. MacPhail for their service and for their contributions over the years to the success of the Company.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate 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 downturn in crude oil and natural gas pricing commencing in the second half of 2014, the Company reduced its 2015 drilling programs. Drilling activity in Q1/15 consisted of 139 net wells compared to 629 net wells in Q1/14.
North America Exploration and Production
- North America crude oil and NGLs achieved quarterly production of 286,333 bbl/d in Q1/15, an increase of 8% from Q1/14 levels and a slight decrease of 2% from Q4/14 levels.
- North America light crude oil and NGLs achieved record quarterly production averaging 97,561 bbl/d in Q1/15. Production increased 29% and 2% from Q1/14 levels and Q4/14 levels respectively, largely as a result of the successful integration of light crude oil and NGL production volumes acquired in 2014, complemented by a successful drilling program.
- As expected, Pelican Lake operations achieved solid quarterly heavy crude oil production volumes of 51,085 bbl/d, a 6% increase from Q1/14 levels and comparable to Q4/14 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake.
- In Q1/15, primary heavy crude oil production averaged 137,687 bbl/d, a decrease of 3% and 5% from Q1/14 and Q4/14 levels respectively. The decrease in production volumes reflects a reduced drilling program, as a result of a prudent reduction in capital allocation due to unfavorable commodity pricing and economic conditions. The Company's high working interest, large undeveloped land base of over 8,000 potential well locations and extensive operated infrastructure enable Canadian Natural to exercise a nimble, flexible capital allocation program. Canadian Natural drilled 36 net primary heavy crude oil wells in Q1/15 compared to 224 and 305 net primary heavy crude oil wells drilled in Q1/14 and Q4/14 respectively.
- In Q1/15, record thermal in situ quarterly production volumes were achieved averaging 146,086 bbl/d, an increase of 78% and 23% from Q1/14 and Q4/14 production volumes respectively. The increase in Q1/15 from Q1/14 reflects record production volumes at Primrose and increased Kirby South production volumes.
- Primrose production volumes reached record quarterly average levels of 122,386 bbl/d in Q1/15, resulting from the Company's execution excellence in optimizing operations and reflecting the cyclic nature of the operations. As expected, Q2/15 total thermal production volumes are targeted to range from 106,000 bbl/d to 115,000 bbl/d.
- Subsequent to Q1/15, Canadian Natural submitted its Primrose Flow-to-Surface ("FTS") Final Report. The report reflects the Company's initial findings as reported in its Primrose FTS Causation Report submitted in early 2014.
- The Company commenced a low pressure steamflood at Primrose East Area 1 in September 2014. Production ramp up is meeting expectations with current volumes of approximately 11,000 bbl/d. Additionally, low pressure cyclic steam stimulation ("CSS") operations at Primrose East Area 2 received regulatory approval and steaming was subsequently implemented in February 2015 with production ramping up as expected.
- At Kirby South, Q1/15 production volumes increased to 23,700 bbl/d as operations continue to ramp up to the targeted 40,000 bbl/d of design capacity. The reservoir continues to perform as expected with very good thermal efficiencies. For wells on Steam Assisted Gravity Drainage ("SAGD"), steam to oil ratio ("SOR") in Q1/15 was 2.4. For April 2015, Kirby South's production continues to ramp up to volumes averaging approximately 27,500 bbl/d.
- North America natural gas production reached record quarterly levels averaging 1,713 MMcf/d for Q1/15, an increase of 49% from Q1/14 and comparable to Q4/14 levels. The increase from Q1/14 levels resulted from additional production volumes acquired in 2014, complemented by a focused liquids-rich natural gas drilling program.
- North America natural gas quarterly operating costs were $1.38/Mcf in Q1/15, a 10% decrease from Q1/14 levels of $1.54/Mcf, reflecting a continued focus on cost optimization after acquiring higher cost production volumes in 2014. In 2015, the Company will continue its strong, effective and efficient operations with a focus on cost optimization. As a result, annual operating cost guidance has been reduced and is targeted to range from $1.25/Mcf to $1.35/Mcf.
International Exploration and Production
- International crude oil production averaged 36,224 bbl/d during Q1/15, an increase of 32% from Q1/14 levels and a 7% increase from Q4/14 levels. The increase in production over Q1/14 levels was primarily due to the reinstatement of the Banff/Kyle Floating Production Storage and Offtake Vessel ("FPSO") in July 2014 and increased production from Baobab after experiencing downtime in Q1/14. Q1/15 production volumes also reflect the return to production on the Tiffany platform which experienced unplanned downtime during Q4/14, and higher production at Espoir.
- In offshore Cote d'Ivoire, Canadian Natural has contracted a drilling rig to undertake a 10 well (5.9 net) infill development drilling program targeted to add 5,900 BOE/d of net production at the Espoir Field. In Q1/15, the first oil well was brought on stream and is currently producing at a net rate of approximately 3,000 bbl/d. In April 2015, the Company commenced production from its second well at a net production rate of approximately 2,100 bbl/d. Production from both wells is above expectations and the program is progressing below budget and on schedule.
- The Company has also contracted a drilling rig to undertake a 6 well (3.5 net) infill development drilling program targeted to add 11,000 BOE/d of net production at the Baobab Field, offshore Cote d'Ivoire. Drilling has commenced and first oil is targeted in June 2015.
- In Q2/14, an exploratory well was drilled on Block CI-514, in which the Company has a 36% working interest. The well demonstrated the presence of a working petroleum system. In April 2015, a second exploration well was drilled to evaluate the up-dip potential of the initial well. The well has been plugged and abandoned, and the results will be evaluated and integrated into our understanding of the block.
North America Oil Sands Mining and Upgrading - Horizon
(1) The Company has commenced production of diesel for internal use at Horizon. First quarter 2015 SCO production before royalties excludes 1,676 bbl/d of SCO consumed internally as diesel (fourth quarter 2014 - 1,288 bbl/d; first quarter 2014 - nil).
- Horizon achieved record quarterly production of 134,166 bbl/d of SCO, an increase of 19% from Q1/14 levels and an increase of 5% from Q4/14 levels. As previously discussed in Canadian Natural's Q4/14 and Year End Results, new equipment performance and the execution of an optimized mining strategy have increased the stability of the extraction and upgrading processes, resulting in increased nameplate capacity to 137,000 bbl/d. Horizon productive capacity reflects target utilization rates ranging from 92% to 96% of the plant nameplate capacity. During Q1/15, utilization rates were exceptional reaching 98%. April 2015 average production volumes at Horizon were approximately 123,000 bbl/d, slightly below the target utilization rate range. Annual production guidance range remains between 121,000 bbl/d and 131,000 bbl/d.
- Strong quarterly operating costs at Horizon averaged $29.73/bbl in Q1/15, representing a decrease of 28% from $41.11/bbl in Q1/14 and a decrease of 13% from $34.34/bbl in Q4/14. Decreases in operating costs reflect safe, steady and reliable operations, the impact of cost reduction initiatives across the site, the production and internal use of mine diesel, lower energy costs, and higher production volumes on a relatively fixed cost structure. As a result of these factors, Horizon's 2015 operating cost guidance range has been reduced to $31.00/bbl to $34.00/bbl. As production volumes increase with the expansion to 250,000 bbl/d, which is targeted for completion at the end of 2017, production costs are targeted to reduce further, ranging between $25.00/bbl and $27.00/bbl.
- The 2015 maintenance turnaround targeted for this fall has been accelerated to June 2015. Along with performing critical maintenance activities of the plant, the Horizon team will also take advantage of the opportunity to enhance reliability, optimize vessel performance and potentially increase capacity of the Diluent Recovery Unit ("DRU").
- Canadian Natural continues to deliver on its strategy to transition to a longer life, low decline asset base while providing significant and growing free cash flow. Canadian Natural's staged expansion of Horizon to 250,000 bbl/d of SCO production capacity continues to progress ahead of schedule. Compared to the Company's original 2015 budget released in November 2014, $300 million is targeted to be reduced in 2015 on Horizon Phase 2/3 Expansion activities, with no impact to the current targeted schedule. Canadian Natural has committed to approximately 77% of the Engineering, Procurement and Construction contracts with over 72% of the construction contracts awarded to date, 85% being lump sum, ensuring greater cost certainty and efficiency.
- Overall Horizon Phase 2/3 expansion is 60% physically complete as at Q1/15:
-- Reliability - Tranche 2 is 100% physically complete. Completion occurred in 2014 resulting in increased performance and overall production reliability. This contributed approximately 5% increase in production levels from Phase 1 production levels.
-- Directive 74 includes technological investment and research into tailings management. This project remains on track and is 53% physically complete.
-- Phase 2A is a coker expansion that was originally scheduled to be completed in mid-2015; however, due to strong construction performance and the early completion of the coker installation, the Company accelerated the tie-in to August 2014. The expanded Coker Unit is now fully operational and the project was completed on time and below budget. Horizon SCO production levels increased by approximately 12,000 bbl/d with the completion of the coker tie-in. Through the completion of Phase 2A, additional coker capacity and equipment were added, increasing the plant nameplate capacity to 133,000 bbl/d. New equipment performance combined with an optimized mining strategy have increased the stability of the extraction and upgrading processes, resulting in a further increase to plant nameplate capacity to 137,000 bbl/d.
-- Phase 2B is 54% physically complete. This Phase expands the capacity of major components such as gas/oil hydrotreatment, froth treatment and the hydrogen plant. Due to continued strong construction performance on the Horizon expansion, certain components of this project will be tied-in during the May 2016 turnaround. Production volumes after the turnaround are targeted to increase by 4,000 bbl/d in Q3/16 and 10,000 bbl/d in Q4/16, above the original planned production ramp up. Full commissioning of the Phase 2B equipment will be completed as planned in late 2016, adding 45,000 bbl/d of production capacity.
-- Phase 3 is on track and on schedule. This Phase is 51% physically complete, and includes the addition of extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in late 2017 and will result in additional reliability, redundancy and significant operating cost savings for the Horizon project.
ROYALTY PRODUCTION AND REVENUE
Based on the analysis completed to date, Canadian Natural reports the following information for quarterly royalty volumes, which are based on the Company's current estimate of revenue and volumes attributable to Q4/14:
- The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Q4/14 production volumes on the royalty lands increased 3% and 14% from Q3/14 and Q2/14 levels respectively. Drilling activity has been strong on the Company's royalty lands with 144 wells drilled in Q4/14, of which 127 wells were drilled by third parties and 17 wells were drilled by Canadian Natural. In Q1/15, drilling activity consisted of 75 wells drilled, 72 wells were drilled by third parties and 3 wells were drilled by Canadian Natural.
- The Company continues to focus on lease compliance, well commitments, offset drilling obligations and compensatory royalties payable.
- Royalty production volumes highlighted below are not reported in Canadian Natural's quarterly production volumes. Third party royalty revenues are included in reported Product Sales in the Company's consolidated statement of earnings.
Royalty Production Volumes Comparison (1)
Royalty Production Volumes (1)
Royalty Revenue by Product (1)
Revenue by Royalty Classification (1)
Royalty Realized Pricing (1)
Royalty Acreage
(1) Based on the Company's current estimate of revenue and volumes attributable to the noted period.
(2) Indicates Canadian Natural is both the Lessor and Lessee, thereby incurring intercompany royalties; in addition there are certain Canadian Natural fee title lands where the Company has production where no royalty burden has been recognized in this table.
(3) Includes sulphur revenue, bonus payments, lease rentals and compliance revenue.
(4) Includes Net Profit Interests and other royalties.
(5) Includes Fee title and Freehold.
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 5, 2015.
- Volatility in supply and demand factors and geopolitical events continued to affect WTI and Brent pricing. The Organization of the Petroleum Exporting Countries' ("OPEC") decision in November 2014 to not reduce crude oil production to offset the excess world supply put downward pressure on benchmark pricing. Additionally, the growth of North American shale oil production continues to contribute to this downturn in benchmark pricing.
- The WCS differential to WTI averaged US$14.75/bbl or 30% in Q1/15 compared to US$23.27/bbl or 24% in Q1/14. The WCS heavy differential widened during Q1/15 compared to Q1/14 due to the rapid decline in WTI benchmark pricing. May 2015 and June 2015 indications of the WCS heavy differential are trending lower to US$11.87/bbl or 20% and US$8.73/bbl or 14%, respectively. Seasonal demand fluctuations, changes in transportation logistics and refinery utilization and shutdowns will continue to be reflected in WCS pricing.
- Canadian Natural contributed approximately 179,000 bbl/d of its heavy crude oil stream to the WCS blend in Q1/15. The Company remains the largest contributor to the WCS blend, accounting for 54% of the total blend.
- SCO pricing averaged US$45.26/bbl during Q1/15, a decrease of 53% from Q1/14 pricing of US$96.45/bbl and a decrease of 36% from US$71.01/bbl in Q4/14, primarily due to a decrease in WTI benchmark pricing.
- AECO natural gas pricing in Q1/15 averaged $2.80/GJ, a decrease of 38% and 26% from Q1/14 and Q4/14 pricing respectively.
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 and commodity hedging policy 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 approximately 898,100 BOE/d for Q1/15 with approximately 98% of production located in G8 countries.
- Canadian Natural has a strong balance sheet with debt to book capitalization of 36% and debt to EBITDA of 1.7x at March 31, 2015.
- Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at March 31, 2015, the Company had in place bank credit facilities of $7,128 million, of which $3,269 million was available.
- In March 2015, the United Kingdom ("UK") government enacted a reduction in the corporate tax rate charged on profits from North Sea oil and gas production from 62% to 50%, effective January 1, 2015 and a reduction in the rate of Petroleum Revenue Tax ("PRT") from 50% to 35%, effective January 1, 2016. This resulted in a decrease to the overall effective corporate tax rate applicable to net operating income from oil and gas activities to 50% for non-PRT paying fields, 75% for PRT paying fields effective January 1, 2015, and a further reduction to 67.5% for PRT paying fields effective January 1, 2016, after allowing for deductions for capital and abandonment expenditures. Allowable abandonment expenditures eligible for carryback to prior taxation years for PRT purposes are still recoverable at the previous tax rate of 50%. As a result of the income tax rate changes, the Company's deferred income tax liability was decreased by $228 million. In addition, the UK government announced a new Investment Allowance replacing existing field allowances including Brown Field Allowance.
- The Company's commodity hedging program is utilized, as required, to protect investment returns, support ongoing balance sheet strength and the cash flow for its capital expenditure programs. Details of the Company's commodity hedging program can be found on the Company's website at .
- Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on July 1, 2015.
- Subsequent to Q1/15, Toronto Stock Exchange accepted notice of Canadian Natural's Normal Course Issuer Bid ("NCIB") through facilities of Toronto Stock Exchange and the New York Stock Exchange. The notice provides that Canadian Natural may, during the 12 month period commencing April 2015 and ending April 2016, purchase for cancellation on Toronto Stock Exchange and the New York Stock Exchange up to 54,640,607 common shares.
-- In 2015, the Company has not purchased any common shares under its NCIBs.
- The Company has a strong balance sheet and cash flow generation which enables it to weather volatility in commodity prices. Additionally, Canadian Natural retains significant capital expenditure program flexibility to proactively adapt to changing market conditions.
OUTLOOK
The Company forecasts 2015 production levels before royalties to average between 562,000 and 602,000 bbl/d of crude oil and NGLs and between 1,730 and 1,770 MMcf/d of natural gas. Q2/15 production guidance before royalties is forecast to average between 513,000 and 540,000 bbl/d of crude oil and NGLs and between 1,750 and 1,770 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 their 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, 2015 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2014.
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, 2015 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 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, as determined in accordance with IFRS, as an indication of the Company's performance. The non-GAAP measures adjusted net earnings from operations and cash flow from operations are reconciled to net earnings, 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, 2015 in relation to the first quarter of 2014 and the fourth quarter of 2014. 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, 2014, is available on SEDAR at , and on EDGAR at . This MD&A is dated May 6, 2015.
FINANCIAL HIGHLIGHTS
(1) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation "Adjusted Net Earnings 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 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 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.
Adjusted Net Earnings from Operations
(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 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 and 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) During the fourth quarter of 2014, the Company repaid US$500 million of 1.45% notes and US$350 million of 4.90% notes.
(5) The Company's investment in the 50% owned North West Redwater Partnership is accounted for using the equity method of accounting. The non-cash equity loss from investment represents the Company's pro rata share of the North West Redwater Partnership's accounting loss.
(6) During the fourth quarter of 2014, the Company recorded an after-tax gain of $137 million related to the acquisition of certain producing crude oil and natural gas properties.
(7) During the first quarter of 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and the Petroleum Revenue Tax ("PRT"), and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in deferred income tax liabilities of approximately $228 million.
Cash Flow from Operations
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net loss for the first quarter of 2015 was $252 million compared with net earnings of $622 million for the first quarter of 2014 and net earnings of $1,198 million for the fourth quarter of 2014. Net loss for the first quarter of 2015 included net after-tax expense of $273 million compared with $299 million for the first quarter of 2014 and net after-tax income of $442 million for the fourth quarter of 2014 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of a realized foreign exchange loss on repayment of long-term debt, the gain on corporate acquisition, and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, adjusted net earnings from operations for the first quarter of 2015 were $21 million compared with $921 million for the first quarter of 2014 and $756 million for the fourth quarter of 2014.
The decrease in adjusted net earnings for the first quarter of 2015 from the first quarter of 2014 was primarily due to:
- lower crude oil and NGLs netbacks in the North America and North Sea segments;
- lower realized SCO prices;
- lower natural gas netbacks in the North America segment; and
- higher depletion, depreciation and amortization expense;
partially offset by:
- higher crude oil and NGLs and natural gas sales volumes across all segments;
- higher SCO sales volumes in the Oil Sands Mining and Upgrading segment;
- higher realized risk management gains; and
- the impact of a weaker Canadian dollar relative to the US dollar.
The decrease in adjusted net earnings for the first quarter of 2015 from the fourth quarter of 2014 was primarily due to:
- lower crude oil and NGLs netbacks in the North America and North Sea segments;
- lower realized SCO prices;
- lower natural gas netbacks in the North America segment;
- lower crude oil sales volumes in the North Sea and Offshore Africa segments; and
- lower realized risk management gains;
partially offset by:
- higher crude oil and NGLs and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments;
- higher crude oil netbacks in the Offshore Africa segment; 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 quarterly 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 2015 was $1,370 million compared with $2,146 million for the first quarter of 2014 and $2,368 million for the fourth quarter of 2014. The decreases in cash flow from operations from the comparable periods were primarily due to the factors noted above relating to the decreases in adjusted net earnings, partially offset by the impact of lower cash taxes.
Total production before royalties for the first quarter of 2015 increased 31% to 898,053 BOE/d from 684,647 BOE/d for the first quarter of 2014 and increased 4% from 860,920 BOE/d for the fourth quarter of 2014.
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, 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 Dated 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 strong heavy crude oil drilling program throughout 2013 and 2014, the impact and timing of acquisitions, and the impact of turnarounds at Horizon. 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 pricing and the impact and timing of acquisitions.
- Production expense - Fluctuations primarily due to the impact of the demand 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 depletion, depreciation and amortization expense in the North Sea resulting from the planned early cessation of production at the Murchison platform, 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 predominately 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 corporate acquisitions/disposition of properties - Fluctuations due to the recognition of gains on corporate acquisitions/dispositions in the fourth quarter of 2014 and the third quarter of 2013.
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. In the first quarter of 2015, realized prices were impacted 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$48.57 per bbl for the first quarter of 2015, a decrease of 51% from US$98.61 per bbl for the first quarter of 2014, and a decrease of 34% from US$73.12 per bbl for the fourth quarter of 2014.
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$53.80 per bbl for the first quarter of 2015, a decrease of 50% from US$108.20 per bbl for the first quarter of 2014, and a decrease of 29% from US$75.99 per bbl for the fourth quarter of 2014.
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 together with the Organization of the Petroleum Exporting Countries' ("OPEC") decision in November 2014 to not reduce crude oil production resulted in a decline in benchmark pricing. The growth of North American shale oil production continues to put downward pressure on crude oil benchmark pricing. In April 2015, WTI averaged US$54.63 per bbl and Brent averaged US$59.76 per bbl.
The WCS Heavy Differential averaged 30% for the first quarter of 2015 compared with 24% for the first quarter of 2014 and 20% for the fourth quarter of 2014. The WCS Heavy Differential widened for the first quarter of 2015 from the comparable periods in connection with the rapid decline in WTI benchmark pricing. In April 2015, the WCS Heavy Differential averaged US$14.37 per bbl or 26%.
The WCS Heavy Differential is expected to continue to reflect seasonal demand fluctuations, changes in transportation logistics, and refinery utilization and shutdowns.
The SCO price averaged US$45.26 per bbl for the first quarter of 2015, a decrease of 53% from US$96.45 per bbl for the first quarter of 2014, and decreased 36% from US$71.01 per bbl for the fourth quarter of 2014. The decrease in SCO pricing for the first quarter of 2015 from the comparable periods was primarily due to a decrease in WTI benchmark pricing.
NYMEX natural gas prices averaged US$2.96 per MMBtu for the first quarter of 2015, a decrease of 39% from US$4.89 per MMBtu for the first quarter of 2014, and a decrease of 25% from US$3.95 per MMBtu for the fourth quarter of 2014.
AECO natural gas prices for the first quarter of 2015 averaged $2.80 per GJ, a decrease of 38% from $4.52 per GJ for the first quarter of 2014, and a decrease of 26% from $3.80 per GJ for the fourth quarter of 2014.
US natural gas production continued to grow in the first quarter of 2015, resulting in natural gas inventories remaining at normal industry levels, leading to downward pressure on natural gas prices. Natural gas prices were higher in the comparable periods reflecting lower than average storage levels due to the cold winter temperatures in 2014.
DAILY PRODUCTION, before royalties
(1) First quarter 2015 SCO production before royalties excludes 1,676 bbl/d of SCO consumed internally as diesel (fourth quarter 2014 - 1,288 bbl/d; first quarter 2014 - nil).
(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 2015 increased 23% to 602,809 bbl/d from 488,788 bbl/d for the first quarter of 2014 and increased 5% from 572,040 bbl/d for the fourth quarter of 2014. The increase in production for the first quarter of 2015 from the comparable periods was primarily due to the increased production at the Company's thermal areas including Kirby South, strong and reliable production in Horizon, and higher production in North Sea and Offshore Africa. The increase from the first quarter of 2014 also reflected the increase in NGLs production associated with increased natural gas production. Crude oil and NGLs production for the first quarter of 2015 was within the Company's previously issued guidance of 591,000 to 617,000 bbl/d.
Natural gas production for the first quarter of 2015 increased 51% to 1,771 MMcf/d from 1,175 MMcf/d for the first quarter of 2014 and increased 2% from 1,733 MMcf/d for the fourth quarter of 2014. The increase in natural gas production for the first quarter of 2015 from the first quarter of 2014 was primarily a result of acquisitions of producing Canadian natural gas properties in 2014. The increase in natural gas production from the fourth quarter of 2014 was primarily due to acquisitions of producing Canadian natural gas properties in 2014 and higher production volumes in the North Sea and Offshore Africa segments. Natural gas production for the first quarter of 2015 was below the Company's previously issued guidance of 1,785 to 1,805 MMcf/d primarily due to lower natural gas production from an extended unplanned third party processing facility outage in British Columbia and lower than expected production in the North Sea. Late in the fourth quarter of 2014, the Company began exporting natural gas from the Banff field through the Banff FPSO. Natural gas exports have been impacted by FPSO operational reliability issues. Currently, the Company is working with the FPSO service provider to resolve these matters.
For 2015, annual revised production guidance is targeted to average between 562,000 and 602,000 bbl/d of crude oil and NGLs and between 1,730 and 1,770 MMcf/d of natural gas. Second quarter 2015 production guidance is targeted to average between 513,000 and 540,000 bbl/d of crude oil and NGLs and between 1,750 and 1,770 MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the first quarter of 2015 increased 24% to average 432,419 bbl/d compared with 348,187 bbl/d for the first quarter of 2014 and increased 5% from 409,976 bbl/d for the fourth quarter of 2014. The increase in production for the first quarter of 2015 from the first quarter of 2014 was primarily due to increased production in the Company's thermal areas including Kirby South and increased production related to the acquisitions of producing Canadian crude oil properties in 2014. The increase in production from the fourth quarter of 2014 was primarily related to the cyclic nature of the Company's thermal operations. First quarter 2015 production of crude oil and NGLs was within the Company's previously issued guidance of 427,000 to 442,000 bbl/d. Second quarter 2015 production guidance is targeted to average between 372,000 and 389,000 bbl/d of crude oil and NGLs.
Natural gas production increased 49% to 1,713 MMcf/d for the first quarter of 2015 compared with 1,147 MMcf/d in the first quarter of 2014 and was comparable with the fourth quarter of 2014. The increase in natural gas production for the first quarter of 2015 from the comparable periods was primarily a result of the acquisitions of producing Canadian natural gas properties in 2014 and growth from the current drilling program, partially offset by lower natural gas production from an extended unplanned third party processing facility outage in British Columbia.
North America - Oil Sands Mining and Upgrading
SCO production for the first quarter of 2015 increased 19% to 134,166 bbl/d from 113,095 bbl/d for the first quarter of 2014 and increased 5% from 128,090 bbl/d for the fourth quarter of 2014. Production increased for the first quarter of 2015 from the comparable periods as the Company continued to optimize operations, with the plant running at near nameplate capacity after the successful completion of the coker expansion in 2014. First quarter 2015 production of SCO was within the Company's previously issued guidance of 129,000 to 136,000 bbl/d. The turnaround originally planned for Fall 2015 has now been rescheduled to June 2015 to perform maintenance and other activities to enhance throughput and reliability. Second quarter 2015 production guidance is targeted to average between 107,000 to 113,000 bbl/d. Targeted average annual production guidance remains unchanged at 121,000 to 131,000 bbl/d.
North Sea
North Sea crude oil production for the first quarter 2015 increased 38% to 23,036 bbl/d from 16,715 bbl/d for the first quarter of 2014, and increased 5% from 21,927 bbl/d for the fourth quarter of 2014. The increase in production for the first quarter of 2015 from the comparable periods primarily reflected the reinstatement of production from both the Banff FPSO and the Tiffany platform in 2014. Late in the fourth quarter of 2014, the Company initiated natural gas exports from the Banff field through the Banff FPSO.
Offshore Africa
Offshore Africa crude oil production for the first quarter of 2015 averaged 13,188 bbl/d, increasing 22% from 10,791 bbl/d for the first quarter of 2014 and increasing 9% from 12,047 bbl/d for the fourth quarter of 2014. The increase in first quarter 2015 production reflected the Company's completion of a turnaround in the fourth quarter of 2014 and new well production on stream at the Espoir field in the first quarter of 2015, partially offset by natural field declines. The increase in production volumes from the first quarter of 2014 was due to the Baobab FPSO outage in early 2014 and new well production from the Espoir field in 2015.
International Guidance
The Company's North Sea and Offshore Africa first quarter 2015 crude oil production was 36,224 bbl/d and was within the Company's previously issued guidance of 35,000 to 39,000 bbl/d. Second quarter 2015 production guidance is targeted to average between 34,000 and 38,000 bbl/d of crude oil.
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 on crude oil volumes that were stored in various storage facilities, pipelines, 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 $35.22 per bbl for the first quarter of 2015, a decrease of 55% compared with $77.54 per bbl for the first quarter of 2014 and a decrease of 43% compared with $61.28 per bbl for the fourth quarter of 2014. The decrease in realized crude oil prices for the first quarter of 2015 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 2015 contributed approximately 179,000 bbl/d of heavy crude oil blends to the WCS stream.
North America realized natural gas prices decreased 44% to average $3.14 per Mcf for the first quarter of 2015 compared with $5.56 per Mcf in the first quarter of 2014, and decreased 26% compared with $4.22 per Mcf for the fourth quarter of 2014. US natural gas production continued to grow in the first quarter of 2015, resulting in natural gas inventories remaining at normal industry levels, leading to downward pressure on natural gas prices. Realized natural gas prices were higher in the comparable periods reflecting lower than average storage levels due to the cold winter temperatures in 2014.
Comparisons of the prices received in North America Explo
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Datum: 07.05.2015 - 09:00 Uhr
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