CALGARY, ALBERTA — (Marketwired) — 08/08/13 — Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
“Canadian Natural achieved in the second quarter of 2013 strong quarterly production from our balanced and diverse asset base,” commented Steve Laut, President of Canadian Natural. “On a per barrel of oil equivalent basis, our overall Exploration and Production operating costs decreased from last quarter resulting in excellent overall netbacks. This, along with strong WTI benchmark pricing, tighter WCS to WTI differentials and better natural gas pricing helped the Company generate solid cash flow in the quarter.
At Kirby South, we are in the final stages of commissioning. Steam injection is expected to commence in late August or early September 2013, approximately three months ahead of the original schedule. Project costs remain within
our targeted budget. By the fourth quarter of 2014, thermal in situ production at Kirby South is targeted to grow to 40,000 bbl/d.
Horizon reliability continues to improve after the completion of our first major maintenance turnaround of the plant in May 2013. We continue to achieve safe, steady and reliable operations. In June and July 2013, synthetic crude oil production was 101,000 bbl/d and 110,000 bbl/d, respectively.
During the second quarter, our North America Exploration and Production crude oil and NGL assets, excluding thermal in situ oil sands, achieved record quarterly production of approximately 241,000 bbl/d. These volumes were driven by record quarterly production at our primary heavy crude oil and Pelican Lake operations. This quarter marks the tenth consecutive quarter that our heavy crude oil assets have achieved record production and demonstrates the strong performance ability of the Pelican Lake pool.
As we move into the third quarter of 2013, we expect production volumes to grow in the quarter. Higher production volumes from thermal in situ operations, increased reliability at Horizon Oil Sands Mining operations and continued strong production performance from all other operating areas of the Company are anticipated. We will continue to operate efficiently and effectively to ensure industry competitive operating costs.”
Corey Bieber, Canadian Natural–s Chief Financial Officer, stated, “We are in an excellent position to realize strong cash flow metrics over the last half of 2013. Midpoint guidance for crude oil production in Q3/13 reflects an increase of approximately 19% over Q2/13 volumes. Furthermore, heavy oil differentials have narrowed as expected. At the same time, benchmark North American crude oil pricing has increased and condensate premium costs have reduced. We target very robust netbacks in the last half of 2013, which ultimately results in debt levels reflective of 2012, making our balance sheet even stronger, despite substantial capital investments of approximately $2.075 billion in the calendar year of 2013 on the Horizon Project Phase 2/3 expansion.”
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.
– Canadian Natural generated cash flow from operations of approximately $1.67 billion in Q2/13 compared to approximately $1.57 billion in Q1/13 and approximately $1.75 billion in Q2/12. The increase from Q1/13 reflects higher crude oil and NGLs and natural gas netbacks and higher realized synthetic crude oil (“SCO”) pricing partially offset by lower crude oil and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments. The cash flow variance from Q2/12 reflects higher crude oil and NGLs sales volumes, higher natural gas netbacks, higher realized SCO pricing and the impact of a weaker Canadian dollar offset by expected lower SCO sales volumes in the Oil Sands Mining and Upgrading segment and expected lower natural gas sales volumes.
– Adjusted net earnings from operations in Q2/13 were $462 million compared to $401 million in Q1/13 and $606 million in Q2/12. Changes in adjusted net earnings primarily reflect the changes in cash flow from operations.
– Total production for Q2/13 averaged 623,315 BOE/d, within the Company–s previously announced corporate guidance, which ranged from 617,000 BOE/d to 646,000 BOE/d. As expected, production volumes varied from Q2/12 and Q1/13 levels primarily as a result of expected lower volumes in the Oil Sands Mining and Upgrading segment due to the Company–s first major maintenance turnaround at Horizon Oil Sands (“Horizon”) and in the Thermal In Situ Oil Sands segment due to production cycle timing.
– In Q2/13, primary heavy crude oil operations achieved record quarterly production of approximately 136,000 bbl/d, representing the Company–s tenth consecutive quarter of record primary heavy crude oil production. Primary heavy crude oil production increased 2% and 11% from Q1/13 and Q2/12, respectively. The Company expects continued strong performance from its primary heavy crude oil assets during the second half of 2013, which are targeted to deliver a 13% production increase over 2012 levels.
– In mid-May 2013, facility constraints at Pelican Lake were alleviated with the completion of a new battery. Both Pelican Lake and Woodenhouse production volumes ramped up soon afterward. In Q2/13, Pelican Lake operations achieved record quarterly production volumes of approximately 42,000 bbl/d, 10% higher than Q1/13 volumes. In June and July 2013, monthly average production increased to between 45,000 bbl/d and 46,000 bbl/d, demonstrating the reservoir–s continued strong performance. Further production volume increases are expected through the second half of 2013, with targeted exit volumes for 2013 of approximately 50,000 bbl/d.
– Kirby South, the next step in the Company–s well defined thermal growth plan, is now in the final stages of commissioning, with first steam-in expected in late August or early September 2013, three months ahead of schedule. Production is targeted to ramp up to 40,000 bbl/d of bitumen by Q4/14.
– During May 2013, the first major maintenance turnaround at Horizon was completed with no major changes to the scope. The sequential start-up of the operation was executed as planned. Q3/13 Horizon SCO production is targeted to increase to between 110,000 bbl/d and 115,000 bbl/d as greater reliability and consistent production is realized after the turnaround. Safe, steady, and reliable operations continue to be a priority at Horizon. Annual SCO production is unchanged and is targeted to range from 100,000 bbl/d to 108,000 bbl/d in 2013.
– At Septimus, the Company–s liquids rich natural gas Montney play, the plant expansion was completed and expanded production volumes were achieved in July 2013. At the end of July, total production at Septimus reached approximately 90 MMcf/d of natural gas and approximately 8,600 bbl/d of liquids. During Q2/13, Canadian Natural drilled 6 net wells at Septimus and targets to drill 7 additional net wells in Q3/13. By early September 2013, production is targeted to grow to plant expansion capacity of 125 MMcf/d of natural gas sales, yielding approximately 12,200 bbl/d of liquids, through the plant and deep cut facilities.
– Subsequent to Q2/13, Canadian Natural announced the acquisition of Barrick Energy Inc. The production and undeveloped land base is complementary to Canadian Natural–s existing assets and is concentrated in light oil weighted assets with strong netbacks and a long reserve life. This acquisition adds approximately 4,200 bbl/d of light crude oil and NGLs and 4.4 MMcf/d of natural gas production.
– Subsequent to Q2/13, TransCanada Corporation announced a successful open season on its Energy East Pipeline project which is anticipated to add 1.1 MMbbl/d of incremental pipeline capacity to the east coast of Canada. Canadian Natural is a strong supporter of this project and has made commitments of 80,000 bbl/d of crude oil. This commitment is in addition to previously announced commitments of crude oil to Keystone XL and Trans Mountain Expansion of 120,000 bbl/d and 75,000 bbl/d respectively.
(i) Based on current indicative pricing as at July 31, 2013.
– As expected, heavy crude oil differentials narrowed during the second quarter, resulting in more favorable price realizations for the Company. The WCS heavy crude oil differential (“WCS differential”) as a percent of WTI averaged 20% in Q2/13 compared to 34% in Q1/13 and 24% in Q2/12. In July, August and September 2013, the WCS differential, based on current indicative pricing, narrowed to 14%, 15% and 20%, respectively.
– The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During Q2/13, condensate price premiums to WTI narrowed to US$7.27/bbl in Q2/13 compared to US$12.84/bbl in Q1/13. Lower condensate price premiums are expected to continue in the second half of 2013 resulting in higher netbacks for the Company–s heavy crude oil sales volumes.
– As expected, the Dated Brent to WTI differential narrowed to US$8.21/bbl in Q2/13 compared to US$18.09/bbl in Q1/13 and US$14.71/bbl in Q2/12. Overall pricing relative to Dated Brent pricing for Canadian Natural–s North American crude oil production continues to improve as a result of this narrowing.
– SCO pricing improved in Q2/13 to US$99.10/bbl compared to US$95.24/bbl in Q1/13 and US$89.54/bbl in Q2/12 resulting in more favorable price realizations for the Company.
– Q3/13 production volumes are expected to be strong and will be driven by increased production volumes from Primrose, strong SCO production due to improved Horizon reliability, and continued solid performance from the Company–s remaining operating areas. Combining this strong production performance with favorable WTI pricing, narrow heavy oil differentials, and strong SCO premiums should result in a strong third quarter performance for the Company.
– Year to date, Canadian Natural has purchased for cancellation 6,937,500 common shares at a weighted average price of $30.86 per common share.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.125 per share payable on October 1, 2013.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where it can own 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. Further, 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.
OPERATIONS REVIEW
North America Exploration and Production
– North America crude oil and NGLs operations achieved record quarterly production of 241,402 bbl/d in Q2/13, an increase of 9% and 2% from Q2/12 and Q1/13 levels respectively.
– Canadian Natural drilled 121 net primary heavy crude oil wells in Q2/13. Canadian Natural–s primary heavy crude oil continues to provide strong netbacks and a high return on capital in the Company–s portfolio of diverse and balanced assets. In Q2/13 primary heavy crude oil operations achieved record production volumes of approximately 136,000 bbl/d, resulting in the tenth consecutive quarter of record primary heavy crude oil production volumes, contributing to the targeted 13% primary heavy crude oil production growth in 2013. The Company is targeting to drill another 255 net primary heavy crude oil wells in Q3/13.
– Production volumes at Woodenhouse during Q2/13 averaged approximately 13,500 bbl/d, representing an increase of 13% from Q1/13 levels of approximately 12,000 bbl/d. Current production from Woodenhouse is approximately 15,000 bbl/d.
– During Q2/13, reservoir performance from Canadian Natural–s industry leading Pelican Lake polymer flood remained strong. Ten net horizontal production wells were drilled during the quarter and 13 net horizontal production wells are targeted in Q3/13. Construction of the new battery at Pelican Lake was successfully completed in mid-May 2013. Facility constraints that began in Q4/12 have been alleviated by the expansion and as a result, production volumes at Pelican Lake and Woodenhouse have increased. Pelican Lake operations achieved record quarterly crude oil production of approximately 42,000 bbl/d in Q2/13, representing a 10% increase from Q1/13 and a 12% increase from Q2/12.
– North America light crude oil and NGLs Q2/13 production decreased 2% from Q1/13 due to downtime as a result of expansion activities at Septimus and Wembley, spring break-up activities and planned turnarounds. The Company drilled 5 net light crude oil wells in Q2/13 and targets to drill 29 additional net wells in Q3/13. Canadian Natural–s light crude oil drilling program will continue to utilize and advance horizontal multi-frac well technology to access new reserves in pools across the Company–s land base.
– Total planned drilling activity for Q3/13 includes 297 net crude oil wells, excluding stratigraphic (“strat”) and service wells.
– Q2/13 thermal in situ oil sands (“thermal in situ”) production volumes averaged approximately 90,000 bbl/d due to the timing of steaming and production cycles.
– During the second quarter of 2013, bitumen emulsion was discovered at surface at four separate locations in the Company–s Primrose development area. The bitumen emulsion seepage has been controlled to specific containment areas totaling 13.5 hectares where it is effectively recovered as it reaches the surface. The rate of bitumen emulsion seepage in all four locations has declined as expected and currently totals less than 20 bbl/d. Canadian Natural believes the cause of the bitumen emulsion seepage is mechanical failures of wellbores in the vicinity of the impacted locations. A complete review is ongoing and Canadian Natural has a specialized team focused on investigating wells in the impacted areas for potential required remediation work.
– The Company–s near term steaming plan at Primrose has been modified, with restrictions on steaming in some areas until the investigation with the Alberta Energy Regulator is complete. Canadian Natural–s July 2013 production was approximately 120,000 bbl/d with an additional 20,000 bbl/d of production capacity that was restricted due to available plant capacity. The Company targets 2013 thermal in situ production to range from 100,000 bbl/d to 107,000 bbl/d. For 2014, even with these modified steaming strategies, the Company anticipates thermal in situ production, excluding Kirby South, to range from 100,000 bbl/d to 110,000 bbl/d, approximately 10,000 bbl/d less than originally targeted. The Company is of the view that reserves recovered from the Primrose area over its life cycle will be substantially unchanged.
– Kirby South remains ahead of plan and on budget. Drilling was successfully completed on the seventh and final pad in Q2/13. Commissioning is nearing completion with first steam-in expected in late August or early September 2013, ahead of the originally scheduled steam-in date of November 2013. Production is targeted to grow to 40,000 bbl/d by Q4/14.
– Detailed engineering is progressing for Kirby North Phase 1. As of June 30, 2013, the engineering portion was 64% complete. Construction of the main access road has been completed and site preparation will continue into Q3/13.
– Kirby South and Kirby North Phase 1 will contribute to a targeted staged expansion of production volumes from the greater Kirby area over time to 140,000 bbl/d, with the overall thermal in situ development plan targeted to increase to 510,000 bbl/d of production capacity.
– Planned drilling activity for Q3/13 includes 47 net thermal in situ wells, excluding strat and service wells.
– During Q2/13, North America natural gas production averaged 1,092 MMcf/d, representing a 11% decrease from Q2/12 levels and a 3% decrease from Q1/13 levels. The decrease in production levels year over year was due to expected production declines, reflecting Canadian Natural–s strategic decision to allocate capital to higher return crude oil projects. Q3/13 production volumes are targeted to increase to 1,135 MMcf/d to 1,155 MMcf/d.
– At Septimus, the Company–s liquids rich natural gas Montney play, the plant expansion was completed and first production was achieved in July 2013. At the end of July, total production at Septimus reached approximately 90 MMcf/d of natural gas and approximately 8,600 bbl/d of liquids. During Q2/13, Canadian Natural drilled 6 net wells at Septimus and targets to drill 7 additional net wells in Q3/13. By early September 2013, production is targeted to grow to plant expansion capacity of 125 MMcf/d of natural gas sales, yielding 12,200 bbl/d of liquids, through the plant and deep cut facilities.
– Canadian Natural has a dominant Montney land position with over one million high quality net acres, the largest in the industry. In Q1/13, the Company commenced the process to monetize approximately 243,000 net acres (approximately 380 net sections) of its Montney land base in the liquids rich fairway in the Graham Kobes area of Northeast British Columbia. In Q2/13, the Information Memorandum was completed. The Company targets to open the associated data room in mid to late August 2013 and conduct presentations in September 2013.
International Exploration and Production
– International crude oil production averaged 36,956 bbl/d during the quarter. The 6% increase in production from Q1/13 was primarily due to the stabilization of the midwater arch which resulted in a reinstatement of production at the Olowi Field in Gabon in late Q1/13. Crude oil production volumes declined 3% from Q2/12 as a result of natural field declines and the cessation of North Sea drilling activity following an increase in the Supplementary Charge Tax Rate in 2011.
– In Q2/13, the Company received a second Brownfield Allowance (“BFA”) approval for its Ninian Field development plan which includes four new production wells, four injectors and two well upgrades. The Company received its first BFA approval in Q1/13 for its Tiffany field development plan of a two well infill drilling program which achieved first oil in May 2013. In September 2012, the UK government announced the implementation of the BFA, which allows for a property development allowance on qualifying preapproved field developments. This allowance partially mitigates the impact of previous tax increases.
– The light crude oil infill drilling program at Espoir, Côte d–Ivoire, originally targeted to commence in late Q2/13, has been delayed as the Company is demobilizing the current drilling rig due to ongoing operational and safety issues with the drilling contractor. Canadian Natural is currently re-assessing its drilling options at Espoir, where the Company expects to undertake an 8-well drilling program.
– During Q2/13, Canadian Natural acquired operatorship and a 60% working interest of Block 12 in Côte d–Ivoire, located approximately 35 km west of the Company–s current production at Espoir and Baobab. The Company plans to commence new 3D seismic acquisition in Q4/13. Potential exploration drilling is targeted for 2015 to evaluate deepwater channel/fan structures similar to the Jubilee crude oil discoveries in Ghana and plays elsewhere in offshore Africa.
– Exploration work on Block 514 in Cote d–Ivoire, in which Canadian Natural has a 36% working interest, is underway and a seismic program has been completed. Drilling is targeted to commence in the first half of 2014. The Company believes this block is also prospective for deepwater channel/fan structures similar to Jubilee.
– A partner has been selected to jointly conduct exploratory drilling on Canadian Natural–s prospective offshore South Africa property. The Company will provide further details on the partnership terms upon receipt of regulatory approval. Targeted drilling windows are from Q4/13 to Q1/14 and from Q4/14 to Q1/15 and the necessary long-lead equipment has been ordered.
North America Oil Sands Mining and Upgrading – Horizon
– During Q2/13, SCO production averaged 67,954 bbl/d at Horizon Oil Sands. Production volumes were lower than Q1/13 and Q2/12 levels due to the completion of the Company–s first major maintenance turnaround in May 2013. Horizon SCO production averaged approximately 101,000 bbl/d in June 2013, approximately 110,000 bbl/d in July 2013 and Q3/13 production guidance is targeted to range from 110,000 bbl/d to 115,000 bbl/d. 2013 annual guidance remains unchanged at 100,000 bbl/d to 108,000 bbl/d of SCO production.
– Canadian Natural–s staged expansion to 250,000 bbl/d of SCO production capacity continues to progress on track. Capital expenditures to date on Phase 2/3 expansion are at or below cost estimates as the Company executes its cost focused strategy. Expansion work at Horizon will ultimately add an additional 140,000 bbl/d of SCO production in a staged, disciplined manner. Horizon provides high quality, long life SCO production without decline for decades.
– An update to the staged Phase 2/3 expansion on an Engineering, Procurement and Construction basis at the end of Q2/13 is as follows:
— Overall Horizon Phase 2/3 expansion is 24% complete.
— Reliability – Tranche 2 is 90% complete. An additional 5,000 bbl/d of production capacity is targeted to be added in 2014.
— Directive 74 includes technological investment and research into tailings management. This project remains on track and is currently 18% complete.
— Phase 2A is a coker expansion. The expansion is 62% complete, and is targeted to add 10,000 bbl/d of production capacity in 2015.
— Phase 2B is 15% complete. This phase includes lump sum contracts for major components such as gas/oil hydrotreatment, froth treatment and a hydrogen plant. This phase is targeted to add another 45,000 bbl/d of production capacity in 2016.
— Phase 3 is on track and engineering is underway. This phase is 15% complete, and includes the addition of supplementary extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in 2017.
— The projects which are currently under construction continue to trend at or below cost estimates.
– Total capital budgeted for the Horizon Phase 2/3 expansion in 2013 is $2.075 billion. Canadian Natural continues to be disciplined and cost driven in the Horizon Phase 2/3 expansion to ensure the expansion continues effectively and efficiently.
MARKETING
(1) West Texas Intermediate (“WTI”).
(2) Western Canadian Select (“WCS”).
(3) Average crude oil and NGLs pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities.
(i) Based on current indicative pricing as at July 31, 2013.
– As expected, heavy crude oil differentials narrowed during the second quarter, resulting in more favorable price realizations for the Company. The WCS differential averaged 20% in Q2/13 compared to 34% in Q1/13 and 24% in Q2/12. The differential narrowed during Q2/13 compared to Q1/13 due to increased seasonal demand for heavy crude oil, increased pipeline capacity resulting from improved pipeline reliability, and lower unplanned maintenance activity at refineries accessible to Canadian heavy crude oil. In July, August and September 2013, the WCS differential, based on current indicative pricing, narrowed to 14%, 15% and 20%, respectively.
– Canadian Natural contributed over 172,000 bbl/d of its heavy crude oil blends to the WCS blend in Q2/13. The Company remains the largest contributor to the WCS blend, accounting for over 62% of the total blend this quarter.
– The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. Condensate price premiums to WTI narrowed to US$7.27/bbl in Q2/13 compared to US$12.84/bbl in Q1/13, reflecting normal seasonality. Lower condensate price premiums are expected to continue in the second half of 2013 resulting in higher netbacks for the Company–s heavy crude oil sales volumes.
– As expected, the Dated Brent to WTI differential narrowed to US$8.21/bbl in Q2/13 compared to US$18.09/bbl in Q1/13 and US$14.71/bbl in Q2/12, reflecting continued debottlenecking of the logistical constraints between Cushing and the Gulf Coast as incremental pipeline capacity continued to grow. Overall pricing relative to Dated Brent pricing for Canadian Natural–s North American crude oil production continues to improve as a result of this narrowing.
– SCO pricing averaged US$99.10/bbl during Q2/13, representing a 4% and 11% increase from Q1/13 and Q2/12 pricing, respectively. Pricing increases from Q1/13 and Q2/12 reflect planned and unplanned supply disruptions in Northern Alberta and overall higher diesel demand and result in more favorable price realizations for the Company.
NORTH WEST REDWATER UPGRADING AND REFINING
In Q2/13 work continued on the North West Redwater refinery and completion is targeted for mid-2016. The North West Redwater refinery asset strengthens 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 volatility in pricing all Western Canadian heavy crude oil.
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, diverse asset base and related capital expenditure programs and commodity hedging policy all support a flexible financial position and provide the right 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 623,315 BOE/d for Q2/13 with approximately 96% of production located in G8 countries.
– Subsequent to Q2/13, the Company increased its forecasted 2013 capital spending as a result of the Cold Lake pipeline expansion, the Barrick Energy Inc. acquisition and a minor increase in capital allocated to Exploration and Production.
– Canadian Natural has a strong balance sheet with debt to book capitalization of 29% and debt to EBITDA of 1.4x at June 30, 2013.
– During Q2/13, Canadian Natural–s $3,000 million revolving syndicated credit facility was extended to June 2017. Additionally, the Company issued $500 million of 2.89% medium-term notes due August 2020. Proceeds from the securities issued were used to repay bank indebtedness and for general corporate purposes.
– In Q2/13, the Company completed a full quarter of its US commercial paper program. Borrowings of up to a maximum of US$1,500 million are authorized. The program further diversifies the Company–s borrowing base and has been well received.
– Canadian Natural maintains significant financial stability and liquidity represented by approximately $2.4 billion of available credit under its bank credit facilities, net of commercial paper issued.
– The Company–s commodity hedging program protects investment returns, ensures ongoing balance sheet strength and supports the Company–s cash flow for its capital expenditure programs. Approximately 58% of forecasted 2013 crude oil volumes are currently hedged using price collars and physical crude oil sales contracts with fixed WCS differentials. Through the use of collars, the Company has hedged approximately 300,000 bbl/d of crude oil volumes in the second half of 2013, and approximately 150,000 bbl/d of crude oil volumes in 2014. To partially mitigate its exposure to widening heavy crude oil differentials, the Company has entered into physical crude oil sales contracts with weighted average fixed WCS differentials as follows:
Details of the Company–s commodity hedging program can be found on the Company–s website at .
– Year to date, Canadian Natural has purchased for cancellation 6,937,500 common shares at a weighted average price of $30.86 per common share.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.125 per share payable on October 1, 2013.
OUTLOOK
The Company forecasts 2013 production levels before royalties to average between 482,000 and 513,000 bbl/d of crude oil and NGLs and between 1,085 and 1,145 MMcf/d of natural gas. Q3/13 production guidance before royalties is forecast to average between 506,000 and 529,000 bbl/d of crude oil and NGLs and between 1,135 and 1,155 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, construction of the proposed Keystone XL Pipeline from Hardisty, Alberta to the US Gulf Coast, construction of the proposed Energy East pipeline to transport crude oil from Alberta to Quebec and New Brunswick, the proposed Kinder Morgan Trans Mountain pipeline expansion from Edmonton, Alberta to Vancouver, British Columbia, and the construction and future operations of the North West Redwater bitumen upgrader and refinery 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 and six months ended June 30, 2013 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2012.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company–s consolidated financial statements for the period ended June 30, 2013 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 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 cash production costs is 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 synthetic crude oil.
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 refers primarily to the Company–s financial results for the three and six months ended June 30, 2013 in relation to the comparable periods in 2012 and the first quarter of 2013. 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, 2012, is available on SEDAR at , and on EDGAR at . This MD&A is dated August 7, 2013.
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 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.
(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 first quarter of 2013, the Company repaid US$400 million of 5.15% unsecured notes.
(5) All substantively enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company–s balance sheets in determining deferred income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings during the period the legislation is substantively enacted. During the second quarter of 2013, the government of British Columbia substantively enacted legislation to increase its provincial corporate income tax rate effective April 1, 2013, resulting in an increase in the Company–s deferred income tax liability of $15 million.
Cash Flow from Operations
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the six months ended June 30, 2013 were $689 million compared with $1,180 million for the six months ended June 30, 2012. Net earnings for the six months ended June 30, 2013 included net after-tax expenses of $174 million compared with net after-tax income of $274 million for the six months ended June 30, 2012 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of a realized foreign exchange gain on repayment of long-term debt, 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 six months ended June 30, 2013 were $863 million compared with $906 million for the six months ended June 30, 2012.
Net earnings for the second quarter of 2013 were $476 million compared with $753 million for the second quarter of 2012 and $213 million for the first quarter of 2013. Net earnings for the second quarter of 2013 included net after-tax income of $14 million compared with $147 million for the second quarter of 2012 and net after-tax expenses of $188 million for the first quarter of 2013 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of a realized foreign exchange gain on repayment of long-term debt, 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 second quarter of 2013 were $462 million compared with $606 million for the second quarter of 2012 and $401 million for the first quarter of 2013.
The decrease in adjusted net earnings for the six months ended June 30, 2013 from the comparable period in 2012 was primarily due to:
– lower crude oil and NGLs netbacks;
– lower natural gas sales volumes; and
– higher depletion, depreciation and amortization expense;
partially offset by:
– higher crude oil and synthetic crude oil (“SCO”) sales volumes in the North America and Oil Sands Mining and Upgrading segments;
– higher realized natural gas netbacks;
– higher realized SCO prices;
– higher realized risk management gains; and
– the impact of a weaker Canadian dollar.
The decrease in adjusted net earnings for the second quarter of 2013 from the comparable period in 2012 was primarily due to:
– lower SCO sales volumes in the Oil Sands Mining and Upgrading segment due to the May 2013 turnaround;
– lower natural gas sales volumes;
– lower realized risk management gains; and
– higher depletion, depreciation and amortization expense;
partially offset by:
– higher crude oil and NGLs sales volumes;
– higher natural gas netbacks;
– higher realized SCO prices; and
– the impact of a weaker Canadian dollar.
The increase in adjusted net earnings for the second quarter of 2013 from the first quarter of 2013 was primarily due to:
– higher crude oil and NGLs and natural gas netbacks;
– higher realized SCO prices; and
– the impact of a weaker Canadian dollar;
partially offset by:
– lower crude oil and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments; and
– lower realized risk management gains.
The impacts of share-based compensation, risk management activities and changes in foreign exchange rates are expected to continue to contribute to quarterly volatility in consolidated net earnings and are discussed in detail in the relevant sections of this MD&A.
Cash flow from operations for the six months ended June 30, 2013 was $3,241 million compared with $3,034 million for the six months ended June 30, 2012. Cash flow from operations for the second quarter of 2013 was $1,670 million compared with $1,754 million for the second quarter of 2012 and $1,571 million for the first quarter of 2013. The fluctuations in cash flow from operations from the comparable periods were primarily due to the factors noted above relating to the fluctuations in adjusted net earnings, excluding depletion, depreciation and amortization expense, as well as due to the impact of cash taxes.
Total production before royalties for the six months ended June 30, 2013 increased 1% to 651,921 BOE/d from 645,943 BOE/d for the six months ended June 30, 2012. Total production before royalties for the second quarter of 2013 decreased 8% to 623,315 BOE/d from 679,607 BOE/d for the second quarter of 2012 and 680,844 BOE/d for the first quarter of 2013.
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 fluctuating demand, inventory storage levels and 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 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, the results from the Pelican Lake water and polymer flood projects, the record heavy crude oil drilling program, and the impact of the turnaround/suspension and subsequent recommencement of production 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 strategic decision to reduce natural gas drilling activity in North America and the 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, the impact of seasonal costs that are dependent on weather, production and cost optimizations in North America, acquisitions of natural gas producing properties in 2011 that had higher operating costs per Mcf than the Company–s existing properties, and the turnaround/suspension and subsequent recommencement of production at Horizon.
– Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes, 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, and the impact of the turnaround/suspension and subsequent recommencement of production 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 – Changes in the Canadian dollar relative to the US dollar that 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.
BUSINESS ENVIRONMENT
Commodity Prices
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$94.28 per bbl for the six months ended June 30, 2013, a decrease of 4% from US$98.22 per bbl for the six months ended June 30, 2012. WTI averaged US$94.23 per bbl for the second quarter of 2013 and was consistent with the comparative periods.
Crude oil sales contracts for the Company–s North Sea and Offshore Africa segments are typically based on Dated Brent (“Brent”) pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$107.41 per bbl for the six months ended June 30, 2013, a decrease of 5% from US$113.34 per bbl for the six months ended June 30, 2012. Brent averaged US$102.44 per bbl for the second quarter of 2013, a decrease of 5% from US$108.21 per bbl for the second quarter of 2012, and a decrease of 9% from US$112.43 per bbl for the first quarter of 2013.
The Brent differential from WTI tightened for the three and six months ended June 30, 2013 from the comparable periods due to incremental pipeline capacity reflecting a continued debottlenecking of logistical constraints from Cushing to the US Gulf Coast.
The WCS Heavy Differential averaged 27% for the six months ended June 30, 2013 compared with 23% for the six months ended June 30, 2012. The WCS Heavy Differential averaged 20% for the second quarter of 2013 compared with 24% for the second quarter of 2012, and 34% for the first quarter of 2013. The WCS Heavy Differential tightened in the second quarter of 2013 from the comparable periods as a result of increased seasonal heavy oil demand and increased pipeline capacity as pipeline reliability in the second quarter of 2013 improved. The WCS Heavy Differential per barrel tightened in July 2013 to average US$14.20 per bbl and in August 2013 to average US$15.57 per bbl. To partially mitigate its exposure to widening heavy crude oil differentials, as at June 30, 2013, the Company has entered into physical crude oil sales contracts with weighted average fixed WCS differentials as follows: 20,000 bbl/d in the third quarter of 2013 at US$21.27 per bbl; 15,000 bbl/d in the fourth quarter of 2013 at US$21.52 per bbl; 8,000 bbl/d in the first quarter of 2014 at US$21.89 per bbl; 9,000 bbl/d in the second quarter of 2014 at US$21.93 per bbl; and 10,000 bbl/d in the third and fourth quarters of 2014 at US$20.81.
The SCO price averaged US$97.18 per bbl for the six months ended June 30, 2013, an increase of 4% from US$93.82 per bbl for the six months ended June 30, 2012. The SCO price averaged US$99.10 per bbl for the second quarter of 2013, an increase of 11% from US$89.54 per bbl for the second quarter of 2012, and an increase of 4% from US$95.24 per bbl for the first quarter of 2013. The increase in SCO pricing for the three and six months ended June 30, 2013 from the comparable periods was due to planned and unplanned shutdowns of various upgrading facilities in Northern Alberta.
The Company uses condensate as a blending diluent for heavy crude oil pipeline shipments. During the second quarter of 2013, condensate price premiums to WTI narrowed, reflecting normal seasonality.
The Company anticipates continued volatility in crude oil pricing benchmarks due to supply and demand factors, geopolitical events, and the timing and extent of the economic recovery. The WCS Heavy Differential is expected to continue to reflect seasonal demand fluctuations, changes in transportation logistics, and refinery utilization and shutdowns.
NYMEX natural gas prices averaged US$3.72 per MMBtu for the six months ended June 30, 2013, an increase of 48% from US$2.52 per MMBtu for the six months ended June 30, 2012. NYMEX natural gas prices averaged US$4.09 per MMBtu for the second quarter of 2013, an increase of 81% from US$2.26 per MMBtu for the second quarter of 2012, and an increase of 22% from US$3.35 per MMBtu for the first quarter of 2013.
AECO natural gas prices for the six months ended June 30, 2013 averaged $3.16 per GJ, an increase of 53% from $2.06 per GJ for the six months ended June 30, 2012. AECO natural gas prices for the second quarter of 2013 averaged $3.41 per GJ, an increase of 96% from $1.74 per GJ for the second quarter of 2012, and an increase of 17% from $2.92 per GJ for the first quarter of 2013.
During the second quarter of 2013, natural gas prices continued to recover from the low pricing levels in 2012. A steady North America production supply forecast and a return to normal winter weather in North America in 2013 has allowed natural gas inventories to return to seasonal levels.
The Company continues to focus on its crude oil marketing strategy including a blending strategy that expands markets within current pipeline infrastructure, supporting pipeline projects that provide crude oil transportation to new markets, and supporting incremental heavy crude oil conversion capacity. Subsequent to June 30, 2013, the Company entered into a 20 year transportation agreement to ship 80,000 bbl/d of crude oil on the proposed Energy East pipeline, subject to regulatory approval.
DAILY PRODUCTION, before royalties
(1) Net of blending costs and excluding risk management activities.
(2) Comparative figures have been adjusted to reflect realized product prices before transportation costs.
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 natural gas, light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and SCO.
Crude oil and NGLs production for the six months ended June 30, 2013 increased 7% to 462,615 bbl/d from 432,993 bbl/d for the six months ended June 30, 2012. Crude oil and NGLs production for the second quarter of 2013 decreased 7% to 436,363 bbl/d from 470,523 bbl/d for the second quarter of 2012 and decreased 11% from 489,157 bbl/d for the first quarter of 2013. The increase in production for the six months ended June 30, 2013 from the comparable period in 2012 was primarily due to the impact of a strong heavy crude oil drilling program, and the increased production from the Company–s cyclic thermal operations and Horizon. The decrease in production for the second quarter of 2013 from the comparable periods was primarily due to the decrease in production volumes resulting from Horizon–s planned maintenance turnaround in May 2013 and from fluctuations in the Company–s cyclic thermal operations, partially offset by the impact of a strong heavy crude oil drilling program. Crude oil and NGLs production in the second quarter of 2013 was within the Company–s previously issued guidance of 435,000 to 461,000 bbl/d.
Natural gas production for the six months ended June 30, 2013 decreased 11% to 1,136 MMcf/d from 1,277 MMcf/d for the six months ended June 30, 2012. Natural gas production for the second quarter of 2013 decreased 11% to 1,122 MMcf/d from 1,255 MMcf/d for the second quarter of 2012 and decreased 2% from 1,150 MMcf/d for the first quarter of 2013. The decrease in natural gas production for the three and six months ended June 30, 2013 from the comparable periods was primarily a result of a strategic reduction of natural gas drilling as the Company allocated capital to higher return crude oil projects, as well as expected production declines. Natural gas production in the second quarter of 2013 exceeded the Company–s previously issued guidance of 1,090 to 1,110 MMcf/d.
For 2013, annual production guidance is targeted to average between 482,000 and 513,000 bbl/d of crude oil and NGLs and between 1,085 and 1,145 MMcf/d of natural gas. Third quarter 2013 production guidance is targeted to average between 506,000 and 529,000 bbl/d of crude oil and NGLs and between 1,135 and 1,155 MMcf/d of natural gas.
North America – Exploration and Production
North America crude oil and NGLs production for the six months ended June 30, 2013 increased 9% to average 338,433 bbl/d from 311,048 bbl/d for the six months ended June 30, 2012. For the second quarter of 2013, crude oil and NGLs production increased 5% to average 331,453 bbl/d compared with 316,483 bbl/d for the second quarter of 2012 and decreased 4% from 345,489 bbl/d for the first quarter of 2013. The increase in crude oil and NGLs production for the three and six months ended June 30, 2013 from the comparable periods in 2012 was primarily due to the impact of a strong heavy crude oil drilling program. The decrease for the second quarter of 2013 from the first quarter of 2013 was primarily due to the decrease in production from the Company–s cyclic thermal operations. Second quarter 2013 production of crude oil and NGLs was within the Company–s previously issued guidance of 326,000 to 342,000 bbl/d. Third quarter 2013 production guidance is targeted to average between 365,000 and 380,000 bbl/d for crude oil and NGLs.
Natural gas production for the six months ended June 30, 2013 decreased 12% to 1,108 MMcf/d compared with 1,255 MMcf/d for the six months ended June 30, 2012. Natural gas production decreased 11% to 1,092 MMcf/d for the second quarter of 2013 compared with 1,230 MMcf/d in the second quarter of 2012 and decreased 3% from 1,125 MMcf/d for the first quarter of 2013. The decrease in natural gas production for the three and six months ended June 30, 2013 from the comparable periods was primarily a result of a strategic reduction of natural gas drilling as the Company allocated capital to higher return crude oil projects, as well as expected production declines.
North America – Oil Sands Mining and Upgrading
Production averaged 88,255 bbl/d for the six months ended June 30, 2013 compared with 80,957 bbl/d for the six months ended June 30, 2012. For the second quarter of 2013, SCO production averaged 67,954 bbl/d compared with 115,823 bbl/d for the second quarter of 2012 and 108,782 bbl/d for the first quarter of 2013. Production increased for the six months ended June 30, 2013 from the comparable period due to the unplanned maintenance completed during the first quarter of 2012. Second quarter 2013 production reflected the impact of the planned maintenance turnaround. Due to a 6 day extension of the planned turnaround to 30 days from the 24 days originally forecasted, SCO production was below the Company–s previously issued guidance of 77,000 to 83,000 bbl/d for the second quarter of 2013. Third quarter 2013 production guidance is targeted to average between 110,000 and 115,000 bbl/d. Annual 2013 production guidance remains unchanged and is targeted to average between 100,000 and 108,000 bbl/d.
North Sea
North Sea crude oil production for the six months ended June 30, 2013 decreased 7% to 18,838 bbl/d from 20,333 bbl/d for the six months ended June 30, 2012. Second quarter 2013 North Sea crude oil production increased 7% to 18,901 bbl/d compared with 17,619 bbl/d for the