CNQ Canadian Natural Resources Ltd

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

Pursuant to Section 13a-16 or 15d-16 of the

Securities Exchange Act of 1934

Interim Report

Third Quarter

2015

Commission File Number: 333-12138

(Exact name of registrant as specified in its charter)

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

 

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1). ____

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ____

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Exhibit Number	Description
99.1	Unaudited Interim Consolidated Financial Statements for the period ended September 30, 2015 and Management's Discussion and Analysis relating to the period ended September 30, 2015.

EXHIBIT 99.1

CANADIAN NATURAL RESOURCES LIMITED ANNOUNCES
2015 THIRD QUARTER RESULTS

Commenting on third quarter results, Steve Laut, President of Canadian Natural stated, “The third quarter was a very strong operational quarter, as we continue to make significant progress in reducing costs while maintaining effective, efficient and reliable operations across our business segments. Our disciplined approach has led to operating costs per barrel equivalent reductions in 2015 equating to approximately $945 million.  At the same time our average production has increased 11% despite a very significant drop in capital program spending. We look to maintain this positive momentum into 2016, with 2016 production volumes targeted at roughly the same level as in 2015. We currently anticipate 2016 cash flows to cover 2016 capital expenditures between $4.5 and $5.0 billion, which includes approximately $2.1 billion of Horizon expansion project expenditures. Importantly, we target to exit 2016 with Horizon production volumes at 170,000 bbl/d and the Phase 3 expansion well advanced toward completion in Q4/17. For 2017, Horizon expansion project expenditure levels are targeted between $1.0 and $1.3 billion, as we complete the Horizon expansion.”

Canadian Natural’s Chief Financial Officer, Corey Bieber, continued, “In 2015, we have been exceptionally proactive in managing our balance sheet and exhibiting capital discipline, given the significant decline in commodity prices.  To date, and including the most recent reduction in capital expenditure guidance of $65 million, we have reduced our targeted capital expenditures by approximately $3.2 billion in 2015 from the original budget, while at the same time increasing crude oil and natural gas production by a targeted 9% year over year. For the first nine months, our cash flow funded all but $300 million of our capital expenditures and dividends paid, including over $1.6 billion of Horizon Phase 2/3 expansion costs. Our liquidity remains robust at $3.4 billion, and the balance sheet remains resilient through this commodity price cycle with our solid access to debt capital markets, as we maintain strong investment grade credit ratings.”

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 maintained its focus on safe, effective and efficient operations in the third quarter of 2015 demonstrated by solid production volumes. 2015 third quarter production volumes averaged 848,701 BOE/d, an increase of 6% and 5% from Q3/14 and Q2/15 volumes respectively. Q3/15 operational highlights include:

 

§

The expansion activities at Horizon continue to progress on track with overall physical completion of 74%. Horizon project capital costs continue to trend below budget estimates. Over the next twenty months, the Company is targeted to complete the Phase 2/3 expansion, adding an incremental 125,000 bbl/d of SCO to the Company’s large, balanced and diversified asset base. Horizon will provide significant and sustainable production for decades to come.

§

Canadian Natural continues to execute capital discipline by proactively managing its drilling programs. As a result of the decrease in commodity pricing and other external events, the Company’s drilling activity for the first nine months of 2015 consisted of 134 net wells, excluding strat/service wells, compared to 768 net wells for the first nine months of 2014, a reduction of 83%.

§	Canadian Natural remains committed to its effective and efficient operations, with an enhanced focus on cost optimization. During the third quarter, the Company achieved strong operating cost reductions in the following areas:

(1)	Horizon Q3/14 operating costs adjusted to reflect the impact of the maintenance turnaround completed in Q3/14.

§

Due to the timing of liftings from the various fields in Offshore Africa that have different cost structures, and a weaker Canadian dollar, a quarterly cost comparison year over year is not indicative of performance. However, on an annual basis, due to the ongoing infill drilling program in Côte d’Ivoire and a continued focus on effective and efficient operations, Offshore Africa crude oil operating costs are targeted to reduce by 37% on a produced barrel basis, 2015 year over 2014 year.

§

Given the cyclical nature of Primrose operations and the continued ramp up of production volumes at Kirby South, quarterly cost comparison year over year is not indicative of performance. However, on an annual basis, with a continued focus on effective and efficient operations, thermal operating costs are targeted to reduce by 16% on a produced barrel basis, 2015 year over 2014 year.

§

In addition to the operating cost efficiencies achieved during the quarter, Canadian Natural has lowered its targeted 2015 capital spending program by an additional $65 million from $5,500 million to $5,435 million. This reduction is a result of the Company’s ability to optimize its execution strategy, enhance productivity, right scope projects, leverage technology, and achieve lower energy and material costs.

§

Year to date, Canadian Natural has been able to attain drilling and completions cost reductions from 20% to 35% and facility cost decreases from 20% to 30% throughout its North America Exploration & Production (“E&P”) operations. These reductions have contributed to the Company’s ability to decrease its targeted 2015 capital expenditure program by a total of approximately $3.2 billion since November 2014.

§

Canadian Natural generated cash flow from operations of approximately $1.5 billion in Q3/15 compared to approximately $2.4 billion in Q3/14 and $1.5 billion in Q2/15. The decrease in Q3/15 from Q3/14 primarily reflects lower benchmark pricing partially offset by reduced operating costs and increased crude oil production volumes.

§

The Company incurred a net loss in Q3/15 of $111 million, compared to net earnings of $1,039 million in Q3/14 and a net loss of $405 million in Q2/15. Adjusted net earnings from operations for Q3/15 were $113 million, compared to adjusted net earnings of $984 million in Q3/14 and $178 million in Q2/15. Changes in adjusted net earnings largely reflect the changes in cash flow from operations.

§	Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on December 31, 2015.

PRELIMINARY GUIDANCE ON 2016

§	At this time, due to the current volatile issues facing the energy industry on both a national and global basis, Canadian Natural has not finalized its 2016 Budget plan. However, below we provide preliminary guidance for 2016.

In 2016, the Company is committed to the following priorities:

—

Continued focus on lowering cost structures,

—

Completion of Horizon Phase 2B and progression of Phase 3 toward completion in Q4/17,

—

Maintenance of the Company’s strong balance sheet,

—

Maintenance of the Company’s dividend program, and

—

Preservation of the optionality of the Company’s reserves and land base.

§	Operational Targets

Canadian Natural’s overall production levels in 2016 is targeted to be between 840,000 BOE/d and 850,000 BOE/d, with a product mix of approximately 65% crude oil and NGLs and 35% natural gas.

§	Target Capital Program

Canadian Natural anticipates a 2016 capital program in the range of $4.5 billion to $5.0 billion, with approximately $2.1 billion allocated to Horizon Phase 2B and Phase 3 construction.

§	Lowering Cost Structures

Canadian Natural has made significant strides in 2015 to lower the Company’s overall cost structures. In 2016, the Company will continue to focus on productivity improvements in all areas of our business.

§	Horizon Operations and Expansion Highlights

Canadian Natural’s plan is to complete Phase 2B of the Horizon expansion in Q4/16, and Phase 3 in Q4/17. Phase 2B is targeted to add 45,000 bbl/d of production capacity once fully commissioned in early Q4/16. Project capital in 2016 is targeted to be approximately $2.1 billion, the majority of which will be spent over the first nine months of 2016. In 2017, Horizon project capital is targeted to decline to a range of $1.0 billion to $1.3 billion for Phase 3 completion, which will add incremental production volumes of 80,000 bbl/d. At expansion completion, targeted for Q4/17, total Horizon production volumes are targeted at 250,000 bbl/d of SCO with targeted operating costs below $25.00/bbl.

§	Maintenance of Strong Balance Sheet

Balance Sheet metrics are fundamental to the Company’s success and well within range of Management’s debt to book capitalization parameters of 25% to 45%. As at September 30, 2015, unused bank lines of credit were approximately $3.4 billion. Canadian Natural is in a strong position to carry through on its plans for 2016.

§	Canadian Natural’s Dividend Program

Canadian Natural instituted the payment of a quarterly dividend in 2001 and has increased the dividend for 15 consecutive years. It is the current intention of the Board of Directors and the Management Committee to continue the program through the completion of the Horizon expansion project.

§	Preservation of the optionality of the Company’s reserves and undeveloped lands

Canadian Natural has a strong, balanced and diversified portfolio of short-, mid- and long-term natural gas, heavy crude oil and light crude oil projects, which will be maintained to ensure optionality of the Company’s asset base. Drilling activity will continue to be focused on value growth, not production growth.

 

OPERATIONS REVIEW AND CAPITAL ALLOCATION

In order to facilitate effective and efficient operations, Canadian Natural focuses its activities in core regions where the Company owns a substantial land base and associated infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning and operating associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Furthermore, the Company maintains large project inventories and production diversification among each of the commodities it produces; light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein collectively referred to as “crude oil”), natural gas and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.

Drilling Activity

§	As a direct result of the decrease in crude oil and natural gas pricing and other external events, the Company has proactively reduced its 2015 drilling programs. Drilling activity, excluding strat/service wells, in Q3/15 consisted of 74 net wells compared to 300 net wells in Q3/14.

North America Exploration and Production

§

Quarterly production volumes of North America crude oil and NGLs were 264,709 bbl/d in Q3/15, a decrease of 8% and 2% from Q3/14 and Q2/15 levels respectively. The year over year production decline reflects the 84% reduction in drilling activity from 689 net wells in the first nine months of 2014 to 111 net wells in the first nine months of 2015.

§

North America light crude oil and NGL quarterly production averaged 88,195 bbl/d in Q3/15, a decrease of 6% from Q3/14 volumes and comparable to Q2/15 levels. Year over year decline primarily resulted from expected production declines as no wells were drilled in Q3/15 compared to 22 net wells drilled in Q3/14.

§	Despite the reduction in production volumes, North America light crude oil and NGL quarterly operating costs decreased to $14.37/bbl in Q3/15, 19% lower than Q3/14 levels of $17.67/bbl and 6% lower than Q2/15 levels of $15.29/bbl.

§	Pelican Lake operations averaged 50,852 bbl/d of quarterly heavy crude oil production, a 2% decrease from Q3/14 and Q2/15 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake.

§	Industry leading quarterly operating costs were achieved at Pelican Lake during Q3/15. Operating costs decreased to $6.64/bbl, 15% lower than Q3/14 and 5% lower than Q2/15.

§

In Q3/15, primary heavy crude oil production averaged 125,662 bbl/d, a decrease of 12% and 2% from Q3/14 and Q2/15 levels respectively. This production decline from Q3/14 to Q3/15 reflects expected declines, the Company’s proactive decision to reduce its primary heavy crude oil drilling program by 73% year over year, and the Company’s prudent decision to shut-in approximately 5,700 bbl/d of current primary heavy crude oil production volumes as a result of unfavorable economic conditions. In Q3/15, 67 net wells were drilled compared to 245 net wells in Q3/14.

§

Canadian Natural continues to demonstrate its strong focus on operating efficiencies achieving quarterly cost reductions in its primary heavy crude oil asset base. Primary heavy crude oil quarterly operating costs decreased in Q3/15 to $13.81/bbl compared to $17.52/bbl in Q3/14 and $14.92/bbl in Q2/15, cost reductions of 21% and 7% respectively.

§

In Q3/15, thermal in situ production volumes averaged 133,183 bbl/d, an increase of 16% and 27% from Q3/14 and Q2/15 production volume levels respectively. The increase in Q3/15 from Q2/15 production volumes primarily reflects increased production volumes from Primrose operations and the ramp up of Kirby South operations.

§

At Kirby South, quarterly production volumes continued to increase in Q3/15 to 34,069 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. The steam to oil ratio (“SOR”) in Q3/15 was 2.5. For October 2015, Kirby South’s production volumes exited at an approximate rate of 36,000 bbl/d following a short shut down for maintenance on the oil treating vessels.

§

The Company continues to progress the low pressure steamflood operations at Primrose East Area 1 and the low pressure cyclic steam stimulation (“CSS”) operations at Primrose East Area 2. Operations at Primrose East are meeting expectations with current production volumes ranging from 15,000 bbl/d to 20,000 bbl/d.

§	North America natural gas quarterly production volumes averaged 1,592 MMcf/d for Q3/15, a decrease of 3% and 7% from Q3/14 and Q2/15 levels respectively. The decrease from Q2/15 levels reflects unplanned and planned pipeline take away capacity constraints in Alberta.

§	Operations at Septimus, Canadian Natural’s liquids-rich Montney natural gas play in British Columbia, continue to perform above expectations, with industry leading quarterly operating costs of $0.20/Mcfe in Q3/15.

 

§

Canadian Natural’s North America natural gas production volumes during Q3/15 were negatively impacted by transportation restrictions on the NOVA pipeline system by 89 MMcf/d. An additional 16 MMcf/d of natural gas production volumes were also negatively impacted as a result of an unexpected seven day outage of the Alliance pipeline system.

§

Further restrictions on the NOVA pipeline system are expected in Q4/15 which will lower North America natural gas production volumes by approximately 70 MMcf/d. Canadian Natural’s Q4/15 total natural gas production guidance reflects these impacts and is targeted to range from 1,735 MMcf/d to 1,775 MMcf/d.

§	North America natural gas quarterly operating costs were $1.25/Mcf in Q3/15, an 8% decrease from Q3/14 levels of $1.36/Mcf, and a 2% decrease from Q2/15 levels of $1.28/Mcf, reflecting a continued focus on cost optimization.

International Exploration and Production

§

International crude oil production averaged 43,464 bbl/d during Q3/15, an increase of 36% from Q3/14 levels and a 16% increase from Q2/15 levels. The increase in Q3/15 production volumes over Q3/14 levels was primarily due to completion and tie-in of new wells at the Baobab and Espoir fields during the second and third quarters of 2015 and the reinstatement of production from both the Banff FPSO and the Tiffany platform outages during 2014. The increase in Q3/15 production volumes from Q2/15 was primarily due to bringing new wells onstream at the Baobab and Espoir fields during Q3/15 and production volume increases from the Ninian field after planned turnaround activity performed in Q2/15.

§	The infill drilling programs at the Espoir and Baobab fields in Côte d’Ivoire continue to be successfully executed with results meeting expectations.

—

To date, the Espoir infill drilling program has added approximately 5,300 bbl/d net to the Company. Espoir is targeted to add overall net production volumes of 5,900 bbl/d through a 10 gross well (5.9 net well) program which includes 4 water injection wells and is currently tracking below sanctioned costs and on track for production. For the first nine months of 2015, 5 gross wells were drilled and completed for production (no water injection wells drilled to date).

—

At Baobab, 3 gross wells were drilled and completed for production during the first nine months of 2015. Net incremental production volumes currently average approximately 6,300 bbl/d. Production from the fourth gross well is targeted to come on stream in the fourth quarter of 2015. Baobab is targeted to add overall net production volumes of 11,000 bbl/d through a 6 gross well (3.4 net well) program, where progress is currently tracking below sanctioned costs and on track for production.

North America Oil Sands Mining and Upgrading – Horizon

(1)

The Company has commenced production of diesel for internal use at Horizon. Third quarter 2015 SCO production before royalties excludes 2,058 bbl/d of SCO consumed internally as diesel (second quarter 2015 – 2,410 bbl/d; third quarter 2014 – 875 bbl/d; nine months ended September 30, 2015 – 2,049 bbl/d; nine months ended September 30, 2014 – 295 bbl/d).

§

Horizon quarterly production volumes were strong in Q3/15 averaging 131,779 bbl/d of SCO, an increase of 61% and 36% from Q3/14 and Q2/15 levels respectively. Increased production volumes in Q3/15, as compared to Q3/14 and Q2/15, reflect normal operating conditions as planned maintenance activities impacted previous quarters. Q4/15 production guidance is targeted to range from 123,000 bbl/d to 129,000 bbl/d, with a targeted utilization rate of 92% at the midpoint. 2015 annual production guidance remains unchanged at 121,000 bbl/d to 131,000 bbl/d.

§	The Company achieved record quarterly operating costs at Horizon of $27.04/bbl as a result of safe, steady and reliable operations in Q3/15. 2015 annual operating cost guidance has been lowered and is now targeted to range from $29.00/bbl to $32.00/bbl.

§

Canadian Natural continues to execute on its strategy to transition to a longer life, low decline asset base while delivering significant and sustainable production. Canadian Natural’s staged expansion of Horizon to 250,000 bbl/d of SCO production capacity continues to progress ahead of schedule. Canadian Natural has committed to approximately 82% of the Engineering, Procurement and Construction contracts with over 78% of the construction contracts awarded to date, 85% being lump sum, ensuring greater cost certainty and efficiency.

§	Overall Horizon Phase 2/3 expansion is 74% physically complete as at Q3/15:

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Directive 74 includes technological investment and research into tailings management. This project remains on track and is 57% physically complete.

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Phase 2B is 72% 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 mid-2016 turnaround. Full commissioning of the Phase 2B equipment will be completed as planned in early Q4/16, adding 45,000 bbl/d of production capacity.

—

Phase 3 is currently on budget and on schedule. This Phase is 67% physically complete, and includes the addition of extraction trains. Phase 3 is targeted to increase production capacity by 80,000 bbl/d in Q4/17 and will result in additional reliability, redundancy and significant operating cost savings for the Horizon project.

—

Horizon project capital in 2016 is targeted to be approximately $2.1 billion, the majority of which will be spent over the first nine months of 2016. In 2017, Horizon project capital is targeted to decline to $1.0 billion to $1.3 billion for Phase 3 completion. Once Horizon expansion activities are completed in Q4/17, total Horizon production volumes are targeted to average 250,000 bbl/d of SCO with operating costs targeted below $25.00/bbl.

ROYALTY PRODUCTION AND REVENUE

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 Q2/15:

§	The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Total drilling activity for the nine months of 2015 consisted of 251 wells with 235 drilled by third parties and 16 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 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 lands.

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.

*Based on current indicative pricing as at November 2, 2015. SCO and Condensate December pricing based on current indicative pricing as at November 2, 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 to maintain crude oil production quotas resulted in a year over year decline in benchmark pricing.

§

The WCS differential to WTI averaged US$13.21/bbl or 28% in Q3/15 compared to US$20.19/bbl or 21% in Q3/14. The WCS differential widened during Q3/15 compared to Q2/15 due to planned and unplanned refinery shutdowns in the US Midwest and seasonal demand. November 2015 and December 2015 indications of the WCS heavy differential are trending higher to US$15.14/bbl or 33% and US$15.17/bbl or 32%, respectively. This widening is mainly due to the seasonality of heavy crude oil demand in the winter months. Seasonal demand fluctuations, changes in transportation logistics and refinery utilization and shutdowns will continue to be reflected in WCS pricing.

§	Canadian Natural contributed approximately 165,000 bbl/d of its heavy crude oil stream to the WCS blend in Q3/15. The Company remains the largest contributor to the WCS blend, accounting for 45% of the total blend.

§	SCO pricing averaged US$45.78/bbl during Q3/15 compared to US$94.31/bbl in Q3/14 and US$60.61/bbl in Q2/15, as a result of changes in WTI benchmark pricing.

§

AECO natural gas pricing in Q3/15 averaged $2.65/GJ, a decrease of 34% from Q3/14 and an increase of 5% from Q2/15 pricing. In Q3/15, US natural gas production was relatively constant to Q2/15 with natural gas inventories growing slightly above normal industry levels. Natural gas prices were lower in Q3/15 compared to Q3/14 primarily due to lower than average storage levels as a result of the cold winter temperatures in 2014.

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: www.nwrpartnership.com/brief-updates.

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 848,701 BOE/d for Q3/15, with approximately 97% of total production located in G8 countries.

§	Canadian Natural has a strong balance sheet with debt to book capitalization of 38% at September 30, 2015. All of the Company’s credit facilities are subject to a financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 65%.

§	Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at September 30, 2015, the Company had in place bank credit facilities of $7,480 million, of which $3,440 million was available.

§

Subsequent to September 30, 2015, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to $3,000 million of medium term notes in Canada, which expires in November 2017. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.

§

Subsequent to September 30, 2015, the Company filed a base shelf prospectus that allows for the offer for sale from time to time of up to US$3,000 million of debt securities in the United States, which expires in November 2017. If issued, these securities may be offered in amounts and at prices, including interest rates, to be determined based on market conditions at the time of issuance.

§	Canadian Natural’s strong investment grade ratings have been maintained.

§	The Company’s commodity hedging program is utilized 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 www.cnrl.com.

§	Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on December 31, 2015.

§	The Company has a strong balance sheet and cash flow generation which enables it to weather volatility in commodity prices. Canadian Natural retains additional capital expenditure program flexibility to proactively adapt to changing market conditions.

OUTLOOK

The Company forecasts 2015 production levels before royalties to average between 555,000 and 591,000 bbl/d of crude oil and NGLs and between 1,730 and 1,770 MMcf/d of natural gas. Q4/15 production guidance before royalties is forecast to average between 562,000 and 588,000 bbl/d of crude oil and NGLs and between 1,735 and 1,775 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company’s website at www.cnrl.com.

 

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 and nine months ended September 30, 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 September 30, 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 and nine months ended September 30, 2015 in relation to the comparable periods in 2014 and the second quarter of 2015. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2014, is available on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. This MD&A is dated November 3, 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, natural gas and foreign exchange.

(3)

Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings.

(4)

The Company's investment in the 50% owned North West Redwater Partnership is accounted for using the equity method of accounting. The non-cash equity loss (gain) from investment represents the Company's pro rata share of the North West Redwater Partnership's accounting loss (gain).

(5)

During the third quarter of 2015, the Company recorded a pre-tax gain of $49 million ($36 million after-tax) related to the disposition of a number of North America crude oil and natural gas properties.

(6)

During the second quarter of 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. During the first quarter of 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and the Petroleum Revenue Tax (“PRT”), and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company’s deferred income tax liability of $228 million.

 

Cash Flow from Operations

SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS

Net loss for the nine months ended September 30, 2015 was $768 million compared with net earnings of $2,731 million for the nine months ended September 30, 2014. Net loss for the nine months ended September 30, 2015 included net after-tax expenses of $1,080 million compared with $324 million for the nine months ended September 30, 2014 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, equity loss from investment, gain on disposition of properties, 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 nine months ended September 30, 2015 were $312 million compared with $3,055 million for the nine months ended September 30, 2014.

Net loss for the third quarter of 2015 was $111 million compared with net earnings of $1,039 million for the third quarter of 2014 and net loss of $405 million for the second quarter of 2015. Net loss for the third quarter of 2015 included net after-tax expenses of $224 million compared with net after-tax income of $55 million for the third quarter of 2014 and net after-tax expenses of $583 million for the second quarter of 2015 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, equity loss (gain) from investment, gain on disposition of properties, 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 third quarter of 2015 were $113 million compared with $984 million for the third quarter of 2014 and $178 million for the second quarter of 2015.

The decrease in adjusted net earnings for the nine months ended September 30, 2015 from the comparable period in 2014 was primarily due to:

§	lower crude oil and NGLs netbacks in the Exploration and Production 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, SCO and natural gas sales volumes across all segments;

§	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 third quarter of 2015 from the third quarter of 2014 was primarily due to:

§	lower crude oil and NGLs netbacks in the Exploration and Production segments;

§	lower realized SCO prices;

§	lower natural gas netbacks in the North America segment;

§	lower crude oil and NGLs and natural gas sales volumes in the North America segment; and

§	higher depletion, depreciation and amortization expense;

partially offset by:

§	higher crude oil and natural gas and SCO sales volumes in the International and Oil Sands Mining and Upgrading segments;

§	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 third quarter of 2015 from the second quarter of 2015 was primarily due to:

§	lower crude oil and NGLs netbacks in the Exploration and Production segments;

§	lower realized SCO prices;

§	lower crude oil and NGLs sales volumes in the North Sea segment; and

§	lower natural gas sales volumes in the North America segment;

partially offset by:

§	higher SCO and crude oil and NGLs sales volumes in the Oil Sands Mining and Upgrading, North America and Offshore Africa segments;

§	higher realized risk management gains; and

§	the impact of a weaker Canadian dollar relative to the US dollar.

 

Cash flow from operations for the nine months ended September 30, 2015 was $4,406 million compared with $7,219 million for the nine months ended September 30, 2014. Cash flow from operations for the third quarter of 2015 was $1,533 million compared with $2,440 million for the third quarter of 2014 and $1,503 million for the second quarter of 2015. The fluctuations in cash flow from operations from the comparable periods were primarily due to the factors noted above relating to the decrease in adjusted net earnings, as well as due to the impact of cash taxes.

 

Total production before royalties for the nine months ended September 30, 2015 increased 11% to 850,587 BOE/d from 766,871 BOE/d for the nine months ended September 30, 2014. Total production before royalties for the third quarter of 2015 increased 6% to 848,701 BOE/d from 796,931 BOE/d for the third quarter of 2014 and increased 5% from 805,547 BOE/d for the second quarter of 2015.

 

SUMMARY OF QUARTERLY RESULTS

 

 

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 heavy crude oil drilling program, 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 third party pipeline restrictions and 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 acquisitions/disposition of properties – Fluctuations due to the recognition of gains on dispositions in the third quarter of 2015 and acquisitions in the fourth quarter of 2014.

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 third quarter of 2015, realized prices continued to be impacted by the weak 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$50.98 per bbl for the nine months ended September 30, 2015, a decrease of 49% from US$99.60 per bbl for the nine months ended September 30, 2014. WTI averaged US$46.44 per bbl for the third quarter of 2015, a decrease of 52% from US$97.21 per bbl for the third quarter of 2014, and a decrease of 20% from US$57.96 per bbl for the second quarter of 2015.

Crude oil sales contracts for the Company’s North Sea and Offshore Africa segments are typically based on Brent pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$55.37 per bbl for the nine months ended September 30, 2015, a decrease of 48% from US$106.55 per bbl for the nine months ended September 30, 2014. Brent averaged US$50.39 per bbl for the third quarter of 2015, a decrease of 51% from US$101.90 per bbl for the third quarter of 2014, and a decrease of 19% from US$61.95 per bbl for the second quarter of 2015.

WTI and Brent pricing continued to reflect volatility in supply and demand factors and geopolitical events. An oversupply of crude oil in the world market together with the Organization of the Petroleum Exporting Countries’ (“OPEC”) decision to continue to maintain crude oil production quotas resulted in a decline in year-over-year benchmark pricing.

The WCS Heavy Differential averaged 26% for the nine months ended September 30, 2015, compared with 21% for the nine months ended September 30, 2014. The WCS Heavy Differential averaged 28% for the third quarter of 2015 compared with 21% for the third quarter of 2014 and 20% for the second quarter of 2015. The WCS Heavy Differential widened for the third quarter of 2015 from the second quarter of 2015 primarily due to planned and unplanned refinery shutdowns in the US Midwest.

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$50.55 per bbl for the nine months ended September 30, 2015, a decrease of 49% from US$98.20 per bbl for the nine months ended September 30, 2014. The SCO price averaged US$45.78 per bbl for the third quarter of 2015, a decrease of 51% from US$94.31 per bbl for the third quarter of 2014, and a decrease of 24% from US$60.61 per bbl for the second quarter of 2015. The fluctuations in SCO pricing for the three and nine months ended September 30, 2015 from the comparable periods were primarily due to changes in WTI benchmark pricing.

NYMEX natural gas prices averaged US$2.80 per MMBtu for the nine months ended September 30, 2015, a decrease of 38% from US$4.51 per MMBtu for the nine months ended September 30, 2014. NYMEX natural gas prices averaged US$2.77 per MMBtu for the third quarter of 2015, a decrease of 32% from US$4.07 per MMBtu for the third quarter of 2014, and an increase of 4% from US$2.67 per MMBtu for the second quarter of 2015.

AECO natural gas prices for the nine months ended September 30, 2015 averaged $2.66 per GJ, a decrease of 38% from $4.32 per GJ for the nine months ended September 30, 2014. AECO natural gas prices for the third quarter of 2015 averaged $2.65 per GJ, a decrease of 34% from $4.00 per GJ for the third quarter of 2014, and an increase of 5% from $2.53 per GJ for the second quarter of 2015.

In the third quarter of 2015, natural gas pricing was comparable with the second quarter of 2015. US natural gas production was comparable between the second and third quarters of 2015 with natural gas inventories growing slightly above normal levels. Natural gas prices were lower in the third quarter of 2015 than the third quarter of 2014 primarily due to lower than average storage levels in 2014 as a result of the colder than normal winter temperatures.

DAILY PRODUCTION, before royalties

(1)	Third quarter 2015 SCO production before royalties excludes 2,058 bbl/d of SCO consumed internally as diesel (second quarter 2015 – 2,410 bbl/d; third quarter 2014 – 875 bbl/d; nine months ended September 30, 2015 – 2,049 bbl/d; nine months ended September 30, 2014 – 295 bbl/d).

(2)	Net of blending costs and excluding risk management activities.

 

DAILY PRODUCTION, net of royalties

The Company’s business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO and natural gas.

Crude oil and NGLs production for the nine months ended September 30, 2015 increased 9% to 561,554 bbl/d from 517,428 bbl/d for the nine months ended September 30, 2014. Crude oil and NGLs production for the third quarter of 2015 increased 11% to 573,135 bbl/d from 518,007 bbl/d for the third quarter of 2014 and increased 13% from 509,047 bbl/d for the second quarter of 2015. The increase in production for the three and nine months ended September 30, 2015 from the comparable periods was primarily due to increased production in the Horizon and International segments as well as from acquisitions of producing Canadian crude oil properties in 2014. Crude oil and NGLs production for the third quarter of 2015 was within the Company’s previously issued guidance of 559,000 to 590,000 bbl/d.

Natural gas production for the nine months ended September 30, 2015 increased 16% to 1,734 MMcf/d from 1,497 MMcf/d for the nine months ended September 30, 2014. Natural gas production for the third quarter of 2015 decreased 1% to 1,653 MMcf/d from 1,674 MMcf/d for the third quarter of 2014 and decreased 7% from 1,779 MMcf/d for the second quarter of 2015. The increase in natural gas production for the nine months ended September 30, 2015 from comparable period was primarily a result of acquisitions of producing Canadian natural gas properties in 2014 and growth from higher production volumes in the North Sea. Natural gas production for the three months ended September 30, 2015 decreased from the comparable periods primarily due to third party transmission pipeline restrictions in Northwest Alberta, involving certain transmission pipeline operators. The Company shut in total natural gas volumes averaging approximately 105 MMcf/d, higher than the 80 MMcf/d originally expected. These additional pipeline restrictions resulted in natural gas production of 1,653 MMcf/d for the third quarter of 2015, slightly below the Company’s previously issued guidance of 1,670 to 1,690 MMcf/d.

2015 annual production guidance is now targeted to average between 555,000 and 591,000 bbl/d of crude oil and NGLs and between 1,730 and 1,770 MMcf/d of natural gas. Fourth quarter 2015 production guidance is targeted to average between 562,000 and 588,000 bbl/d of crude oil and NGLs and between 1,735 and 1,775 MMcf/d of natural gas.

North America – Exploration and Production

North America crude oil and NGLs production for the nine months ended September 30, 2015 increased 5% to average 401,657 bbl/d from 384,356 bbl/d for the nine months ended September 30, 2014. For the third quarter of 2015, crude oil and NGLs production decreased 2% to average 397,892 bbl/d compared with 404,114 bbl/d for the third quarter of 2014 and increased 6% from 375,040 bbl/d for the second quarter of 2015. The increase in production for the nine months ended September 30, 2015 from the comparable period 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 for the third quarter of 2015 from the second quarter of 2015 was primarily due to the reinstatement of production in the thermal production areas after the forest fires in Northeastern Alberta in the second quarter of 2015. Third quarter 2015 production of crude oil and NGLs was within the Company’s previously issued guidance of 393,000 to 413,000 bbl/d. Fourth quarter 2015 production guidance is targeted to average between 388,000 and 404,000 bbl/d of crude oil and NGLs.

Natural gas production for the nine months ended September 30, 2015 increased 14% to 1,673 MMcf/d compared with 1,468 MMcf/d for the nine months ended September 30, 2014. Natural gas production decreased 3% to 1,592 MMcf/d for the third quarter of 2015 compared with 1,644 MMcf/d in the third quarter of 2014 and decreased 7% from 1,716 for the second quarter of 2015. The increase in natural gas production for the nine months ended September 30, 2015 from the comparable period was primarily a result of acquisitions of producing Canadian natural gas properties in 2014. Natural gas production for the three months ended September 30, 2015 decreased from the comparable periods primarily due to third party transmission pipeline restrictions in Northwest Alberta, involving certain transmission pipeline operators. The Company shut in total natural gas volumes averaging approximately 105 MMcf/d, higher than the 80 MMcf/d originally expected.

North America – Oil Sands Mining and Upgrading

SCO production for the nine months ended September 30, 2015 increased 15% to 120,842 bbl/d from 104,667 bbl/d for the nine months ended September 30, 2014. For the third quarter of 2015, SCO production increased 61% to 131,779 bbl/d from 82,012 bbl/d for the third quarter of 2014 and increased 36% from 96,607 bbl/d for the second quarter of 2015. Production in the third quarter of 2015 continued to reflect high utilization rates and reliability, following the completion of the planned turnaround in the second quarter of 2015 and the coker expansion tie-in during the third quarter of 2014. Third quarter 2015 production of SCO exceeded the Company’s previously issued guidance of 124,000 to 131,000 bbl/d. Fourth quarter 2015 production guidance targeted to average between 123,000 to 129,000 bbl/d.

North Sea

North Sea crude oil production for the nine months ended September 30, 2015 increased 38% to 21,915 bbl/d from 15,848 bbl/d for the nine months ended September 30, 2014. Third quarter 2015 crude oil production increased 23% to 22,387 bbl/d from 18,197 bbl/d for the third quarter of 2014, and increased 10% from 20,330 bbl/d for the second quarter of 2015. The increase in production for the three and nine months ended September 30, 2015 from the comparable periods in 2014 primarily reflected the reinstatement of production from both the Banff FPSO and the Tiffany platform in 2014. The increase in production for the third quarter of 2015 from the second quarter of 2015 was primarily due to the impact of planned turnarounds performed at the Ninian platforms.

Offshore Africa

Offshore Africa crude oil production increased 36% to 17,140 bbl/d for the nine months ended September 30, 2015 from 12,557 bbl/d for the nine months ended September 30, 2014. Third quarter 2015 crude oil production increased 54% to 21,077 bbl/d from 13,684 bbl/d for the third quarter of 2014 and increased 23% from 17,070 bbl/d for the second quarter of 2015. The increase in production volumes for the three and nine months ended September 30, 2015 from the comparable periods was due to new wells on stream at both the Espoir and the Baobab fields in the second and third quarters of 2015, partially offset by natural field declines.

International Guidance

The Company’s North Sea and Offshore Africa third quarter 2015 crude oil production was 43,464 bbl/d and was within the Company’s previously issued guidance of 42,000 to 46,000 bbl/d. Fourth quarter 2015 production guidance is targeted to average between 51,000 and 55,000 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