CALGARY, ALBERTA — (Marketwired) — 11/06/14 — Commenting on third quarter results, Steve Laut, President of Canadian Natural (TSX: CNQ)(NYSE: CNQ), stated, “Canadian Natural continued the effective execution of our proven strategy. Our strong, well-balanced asset base generates free cash flow to fund our transition to longer life, low decline assets. Quarterly production increased by approximately 94,000 barrels of oil equivalent per day over third quarter 2013 levels, representing a 13% increase to approximately 797,000 barrels of oil equivalent per day, generating strong quarterly cash flow of $2.44 billion.
Canadian Natural–s transition to longer life, low decline assets remains on track. The Horizon coker expansion tie-in was completed in the third quarter of 2014, ahead of the original 2015 schedule, increasing Horizon production capacity by 12,000 barrels per day. Horizon production averaged approximately 123,100 barrels per day in October 2014, reflecting the effective startup of the expanded facility. Expansion activities remain on track and on budget, with Phase 2B targeted to add 45,000 barrels per day of production capacity in late 2016, and Phase 3 targeted to add another 80,000 barrels per day of production capacity in late 2017.
At Pelican Lake our leading edge polymer flood achieved another quarterly record, with production of approximately 51,900 barrels per day of heavy crude oil, reflecting the continued excellent reservoir performance. At Kirby South, our latest thermal in situ project, reservoir performance has been as expected. With the steam generator issues behind us, production is targeted to ramp up to 40,000 barrels per day in line with original projections of reservoir performance.
Our balanced and diverse asset base combined with the effectiveness of our teams enables us to remain nimble and flexible. The integration of acquisitions continues to progress smoothly, and approximately $70 million in cost efficiencies will be realized in 2014 due to synergies achieved.
As always, we remain focused on effective and efficient operations and optimizing our capital allocation to maximize value for shareholders.”
Canadian Natural–s Chief Financial Officer, Corey Bieber, continued, “We are in an enviable position with our diverse asset base supported by a strong balance sheet. Our liquidity and credit remain robust with current available liquidity of approximately $2.4 billion through our committed banking facilities. Our capital programs are flexible, allowing us to proactively respond to market conditions and enabling us to allocate capital to those projects which generate the highest returns.”
(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 $2.44 billion in Q3/14 compared to approximately $2.45 billion in Q3/13 and $2.63 billion in Q2/14. The reduction in cash flow from Q2/14 levels reflects lower synthetic crude oil (“SCO”) sales volumes at Horizon Oil Sands (“Horizon”) operations as a result of the planned turnaround for the coker tie-in, as well as lower benchmark pricing, partially offset by higher sales in the North America Exploration and Production segment.
– Adjusted net earnings from operations for Q3/14 were $984 million, compared to adjusted net earnings of $1,009 million in Q3/13 and $1,150 million Q2/14. Changes in adjusted net earnings reflect the changes in cash flow.
– Total production for Q3/14 increased approximately 94,000 BOE/d, or 13%, to 796,931 BOE/d from Q3/13 levels of 702,938 BOE/d and decreased 3% from Q2/14 levels of 817,471 BOE/d. The increase from Q3/13 levels is as a result of strong production in all areas, as well as acquisitions made in 2014. The decrease in production from Q2/14 levels was largely due to the planned 25 day turnaround required at Horizon for the coker tie-in.
– During Q3/14 Horizon continued to achieve strong and reliable operating performance and successfully completed the coker tie-in, originally scheduled for 2015. Horizon achieved quarterly SCO production of approximately 82,000 bbl/d, reflecting the 25 day planned turnaround. Horizon achieved an effective ramp up of production after the coker tie-in, with strong October 2014 production of approximately 123,100 bbl/d, representing a 94% plant utilization rate. Production levels are targeted to average approximately 127,000 bbl/d for the remainder of the year, at the high end of the expected plant utilization rate of 94 – 96%.
– North America light crude oil and NGLs achieved quarterly production of approximately 93,500 bbl/d in Q3/14. Production increased 33% from Q3/13 levels, and is comparable to Q2/14 levels, largely as a result of the successful integration of light crude oil and NGLs production volumes acquired in 2014, as well as a successful drilling program.
– In Q3/14, primary heavy crude oil operations achieved record quarterly production of approximately 143,400 bbl/d. Primary heavy crude oil production increased 2% from Q3/13 levels and achieved a slight increase from Q2/14 levels. The strong performance from Canadian Natural–s primary heavy crude oil assets is largely due to the Company–s large undeveloped land base.
– In Q3/14, Pelican Lake operations achieved record quarterly heavy crude oil production volumes of approximately 51,900 bbl/d, a 14% increase from Q3/13 volumes and a 5% increase from Q2/14 volumes. This is the seventh consecutive quarter of production increases, which reflects Canadian Natural–s continued success in developing, implementing and optimizing leading edge polymer flood technology at Pelican Lake.
– Q3/14 thermal in situ production volumes were approximately 115,300 bbl/d, within the Company–s previously issued guidance of 110,000 bbl/d to 120,000 bbl/d.
— At Kirby South, Q3/14 production averaged approximately 18,100 bbl/d, reflecting the impact of the previously announced mechanical issues at the steam generating facility. Canadian Natural has remedied these issues and the production ramp up has resumed. October 2014 production averaged approximately 22,000 bbl/d, and current production is averaging approximately 25,000 bbl/d, reflecting the strong performance of the reservoir.
— To date, the Kirby North Phase 1 (“Kirby North”) project has received all regulatory permits. Targeted project capital for Kirby North is $1.45 billion, or approximately $36,000 per flowing barrel at a project capacity of 40,000 bbl/d. The overall project is 33% complete and in Q3/14 site construction commenced on the Central Processing Facility. First steam-in is targeted for Q4/16.
— Canadian Natural–s stepwise plan to return to steaming operations at Primrose with enhanced mitigation strategies in place has progressed:
— In September 2014, Canadian Natural received approval from the Alberta Energy Regulator (“AER”) to implement a low pressure steamflood in Primrose East Area 1. The steamflood commenced and production is ramping up as expected.
— Primrose South received approval for additional cyclic steam stimulation (“CSS”) on four pads in September 2014; production is targeted to ramp up in 2015.
— Additionally, during Q3/14, an application for low pressure CSS was submitted to the AER for Primrose East Area 2.
– Q3/14 total natural gas production was 1,674 MMcf/d, an increase of 44% and 2% from Q3/13 levels and Q2/14 levels respectively. The increase from Q3/13 levels was as a result of property acquisitions and the increase from Q2/14 levels was due to a continuing concentrated liquids-rich natural gas drilling program and the successful integration of acquired assets.
– In Q3/14, North Sea light crude oil production averaged 18,200 bbl/d, an increase of 17% and 44% from Q3/13 and Q2/14 levels respectively. The increase in production over Q2/14 levels was primarily due to the reinstatement of the Banff/Kyle Floating Production Storage and Offtake vessel (“FPSO”) in July 2014. Production had been suspended in 2011 after the infrastructure suffered storm damage.
– Canadian Natural continues to review its royalty lands and royalty revenue portfolio. A thorough review process has been ongoing and Canadian Natural continues to evaluate the options to maximize the value of these assets for its shareholders. Based on the analysis completed to date, Canadian Natural reports the following information for quarterly royalty volumes:
(1) Based on the Company–s current estimate of revenue and volumes attributable to Q2/14 and subject to final revision.
(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.
— The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Production on the royalty lands continues to grow; as over 168 new wells have been rig released on royalty lands since June 1, 2014, of which 19 wells were drilled by Canadian Natural.
— The Company continues to focus on lease compliance, well commitments, offset drilling obligations and compensatory royalties payable, with 97 offset obligations currently identified.
— Canadian Natural is reviewing the best option to maximize value for its shareholders as it relates to its fee title and royalty lands and is targeting to finalize its strategy in this regard by late 2014 or early 2015.
— Royalty production volumes highlighted above 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.
– Under the Company–s Normal Course Issuer Bid, year to date, Canadian Natural has purchased for cancellation 9,675,000 common shares at a weighted average price of $45.01 per common share.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.225 per share payable on January 1, 2014.
CORPORATE UPDATE
Canadian Natural is pleased to announce the appointment of Annette Verschuren to the Board of Directors of the Company. Ms. Verschuren is Chair and CEO of NRStor Inc., an energy storage project developer accelerating the development and construction of industry leading energy storage technologies. She began her career in the coal mining industry with Cape Breton Development Corporation and held various executive positions with Canada Development Investment Corporation and Imasco Ltd. She is former president of The Home Depot Canada and Asia and prior to that was president and co-owner of the arts and crafts retailer, Michaels of Canada. Ms. Verschuren is an Officer of The Order of Canada and holds honorary doctorate degrees from several notable Canadian universities including St. Francis Xavier University, where she also earned a Bachelor of Business Administration degree. She currently serves on two other publicly traded company boards, sits on a number of not-for-profit boards and serves as Chancellor of Cape Breton University.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where the Company owns a substantial land base and associated infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning and operating associated infrastructure, the Company is able to maximize utilization of production facilities by processing its own or third party volumes, 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, natural gas and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
– North America crude oil and NGLs achieved record quarterly production of approximately 288,900 bbl/d in Q3/14, an increase of 13% from Q3/13 levels and 1% from Q2/14 levels.
– In Q3/14, primary heavy crude oil operations achieved record quarterly production of approximately 143,400 bbl/d. Primary heavy crude oil production increased 2% from Q3/13 levels and achieved a slight increase from Q2/14 levels. The Company–s large undeveloped land base, effective and efficient drilling program and vast inventory of over 8,000 well locations enables Canadian Natural to remain the industry leading primary heavy crude oil producer. Canadian Natural continued with its large and cost efficient drilling program, drilling 245 net primary heavy crude oil wells in Q3/14.
– Canadian Natural–s primary heavy crude oil assets provide strong netbacks and the highest return on capital in the Company–s North America portfolio of diverse and balanced assets.
– In Q3/14, Pelican Lake operations achieved record heavy crude oil quarterly production volumes of approximately 51,900 bbl/d, a 14% increase from Q3/13 volumes and a 5% increase from Q2/14 volumes. This is the seventh consecutive quarter of production increases, which reflects Canadian Natural–s continued success in developing, implementing and optimizing polymer flood technology at Pelican Lake.
— Industry leading Pelican Lake operating costs drive high netbacks and significant free cash flow generation. These industry leading Q3/14 operating costs of $7.82/bbl represent a 17% decrease in operating costs from Q3/13 levels and a 12% decrease from Q2/14 levels. The increasing polymer flood production response combined with continued optimization and effective and efficient operations have driven cost improvements.
– North America light crude oil and NGLs achieved quarterly production of approximately 93,500 bbl/d in Q3/14. Production increased 33% from Q3/13 levels, and is comparable to Q2/14 levels, largely as a result of the successful integration of light crude oil and NGLs production volumes acquired in 2014, as well as a successful drilling program. The increase from Q3/13 levels also reflects the increased NGLs production associated with the Septimus project expansion completed in Q3/13.
– Q3/14 thermal in situ production volumes were approximately 115,300 bbl/d, within the Company–s previously issued quarterly guidance of 110,000 bbl/d to 120,000 bbl/d.
– At Kirby South, Q3/14 production averaged approximately 18,100 bbl/d, reflecting the impact of the previously announced mechanical issues at the associated steam generating facility. Canadian Natural has remedied these issues and the production ramp up has resumed. October 2014 production averaged approximately 22,000 bbl/d, and current production is averaging approximately 25,000 bbl/d, reflecting the strong performance of the reservoir. The total cost to repair the steam generators was approximately $5 million. Kirby South production is targeted to grow to facility capacity of 40,000 bbl/d.
– To date, the Kirby North project has received all regulatory permits. Targeted project capital for Kirby North is $1.45 billion, or approximately $36,000 per flowing barrel at a project capacity of 40,000 bbl/d. The overall project is 33% complete and in Q3/14 site construction commenced on the Central Processing Facility. First steam-in is targeted for Q4/16.
– Canadian Natural–s stepwise plan to return to steaming operations at Primrose with enhanced mitigation strategies in place has progressed:
— In September 2014, Canadian Natural received approval from the Alberta Energy Regulator (“AER”) to implement a low pressure steamflood in Primrose East Area 1. The steamflood commenced and production is ramping up as expected.
— Primrose South received approval for additional CSS on four pads in September 2014; production is targeted to ramp up in 2015.
— Additionally, during Q3/14, an application for low pressure CSS was submitted to the AER for Primrose East Area 2.
— Canadian Natural believes that reserves recovered from the Primrose area over its life cycle will be substantially unchanged.
– North America natural gas production averaged 1,644 MMcf/d for Q3/14, an increase of 45% and 2% from Q3/13 levels and Q2/14 levels respectively. The increase from Q3/13 levels was as a result of property acquisitions and the increase from Q2/14 levels was due to a continuing concentrated liquids-rich natural gas drilling program and the successful integration of acquired assets.
– In Q2/14, Canadian Natural completed natural gas and light crude oil property acquisitions in areas adjacent or proximal to the Company–s current operations. The integration and optimization of the acquired assets is progressing well. In Q3/14 Canadian Natural–s North America natural gas operating costs decreased to $1.36/Mcf, 8% below Q2/14 levels. The Company continues to enhance production while further reducing operating costs as the optimization process continues with facility consolidations, well reactivations and facility turnarounds.
– International crude oil production averaged approximately 31,900 bbl/d during Q3/14, comparable to Q3/13 levels and a 24% increase from Q2/14 levels. The increase in production over Q2/14 levels was primarily due to the reinstatement of the Banff/Kyle FPSO in July 2014. Production was suspended in 2011 after the infrastructure suffered storm damage.
– During Q2/14, Canadian Natural contracted a drilling rig to undertake the 12-month light crude oil infill development drilling program at Espoir, Cote d–Ivoire. Drilling is targeted to commence in late Q4/14 with a 10 well (5.9 net) drilling program. This program is targeted to add 5,900 BOE/d of net production when complete.
– During Q4/13 the Company contracted a drilling rig for a 6 well (3.5 net) infill development drilling program at the Baobab field in Cote d–Ivoire. This rig is expected to arrive no later than Q1/15 to commence an approximate 16- month light crude oil drilling program, which is targeted to add 11,000 BOE/d of net production when complete.
– Canadian Natural previously acquired a working interest in two exploration blocks in Cote d–Ivoire which are prospective for deepwater channel/fan structures similar to Jubilee crude oil discoveries in Offshore Africa. In Q2/14, an exploratory well was drilled on Block CI-514, in which the Company has a 36% working interest. The well demonstrated the presence of a working petroleum system. A second well is targeted to be drilled in the first half of 2015 to evaluate the up-dip potential of the initial well. These results enhance the prospectivity of Canadian Natural–s Block CI-12, located approximately 35 km west of Canadian Natural–s current production at Espoir and Baobab, where new 3D seismic has been acquired and is being evaluated for further exploration targets.
– Canadian Natural has a 50% interest in the Block 11B/12B Exploration Right located in the Outeniqua Basin, approximately 175 kilometers off the southern coast of South Africa. During Q3/14, the operator, Total E&P South Africa BV, a wholly owned subsidiary of Total SA, commenced drilling the first exploratory well. Subsequent to Q3/14, the exploration well was suspended due to mechanical issues with marine equipment on the drilling rig. The rig safely left the well location and, as the available drilling window has ended, it has since been demobilized by the operator. The South African authorities have formally confirmed that the well drilled satisfies the work obligation for the initial period of the Block 11B/12B Exploration Right. The operator is reviewing the course of action to re-enter the well as soon as possible, and has indicated drilling operations are unlikely to resume in the area before 2016.
(1) The Company has commenced production of diesel for internal use at Horizon. Q3/14 SCO production excludes 875 bbl/d of SCO consumed internally as diesel.
– During Q3/14 Horizon continued to achieve strong and reliable operating performance and successfully completed the coker tie-in, originally scheduled for 2015. Horizon achieved quarterly SCO production of approximately 82,000 bbl/d, reflecting the 25 day planned turnaround. Horizon achieved an effective ramp up of production after the coker tie-in, with strong October 2014 production of approximately 123,100 bbl/d, representing a 94% plant utilization rate. Production levels are targeted to average approximately 127,000 bbl/d for the remainder of the year, at the high end of the expected plant utilization rate of 94 – 96%.
– During Q3/14 the production of diesel for internal use commenced at Horizon. In Q4/14, 1,500 bbl/d of diesel production is targeted to be produced at Horizon. The production and use of internally produced diesel fuel at Horizon will reduce operating costs and provides additional volumes beyond reported production targets.
– Canadian Natural continues to deliver on its strategy to transition to a longer life, low decline asset base while providing significant and growing free cash flow. Canadian Natural–s staged expansion to 250,000 bbl/d of SCO production capacity continues to progress on track and within cost estimates.
– Overall Horizon Phase 2/3 expansion is 50% physically complete as at Q3/14:
— Reliability – Tranche 2 is 100% physically complete. This phase will increase performance, overall production reliability and the Gas Recovery Unit will recover additional SCO barrels in 2014.
— Directive 74 includes technological investment and research into tailings management. This project remains on track and is physically 41% complete.
— Phase 2A is a coker expansion which will utilize pre-invested infrastructure and equipment to expand the Coker Plant and alleviate the current bottleneck. The coker tie-in was originally scheduled to be completed in mid- 2015; however, due to strong construction performance and the early completion of the coker installation, the Company accelerated the tie-in to commence August 2014. The Coker Expansion Unit is fully operational and was completed on time and below budget. Horizon SCO production levels increased by approximately 12,000 bbl/d with the completion of the coker tie-in.
— Phase 2B is 42% physically complete. This phase expands the capacity of major components such as gas/oil hydrotreatment, froth treatment and the hydrogen plant. This phase is targeted to add another 45,000 bbl/d of production capacity in late 2016.
— Phase 3 is on track and on schedule. This phase is 38% physically complete, and includes the addition of extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in late 2017 and will result in additional reliability, redundancy and significant operating cost savings.
— The projects currently under construction continue to progress on track and within sanctioned cost estimates.
– For the Phase 2/3 expansion Canadian Natural has committed to approximately 67% of the Engineering, Procurement and Construction contracts. Over 68% of the construction contracts have been awarded to date, with 85% being lump sum, ensuring greater cost certainty.
(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 October 31, 2014.
– Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$97.21/bbl for Q3/14, a decrease of 8% from US$105.82/bbl for Q3/13, and a decrease of 6% from US$102.98/bbl for Q2/14. However, Q3/14 realized prices were offset by the impact of the weaker Canadian dollar, which increased the Canadian dollar sales price the Company received for its crude oil sales, based on US dollar denominated benchmarks. The Company realized Canadian dollar WTI benchmark pricing of C$109.96/bbl for July 2014, C$104.98/bbl for August 2014 and C$102.45/bbl for September 2014.
– The WCS differential averaged 21% during Q3/14 compared with 16% in Q3/13 and 19% in Q2/14. The WCS differential averaged 21% for the nine months ended September 30, 2014, compared with 23% for the nine months ended September 30, 2013.
– Subsequent to Q3/14, the WCS differential averaged 16% in October 2014, and the indicative WCS differential for November 2014 is approximately 16% and December 2014 is approximately 19%.
– Canadian Natural contributed approximately 160,000 bbl/d of its heavy crude oil stream to the WCS blend in Q3/14. The Company remains the largest contributor to the WCS blend, accounting for over 56% of the total blend this quarter.
– SCO pricing during Q3/14 decreased 14% and 9% from Q3/13 levels and Q2/14 levels respectively, primarily due to a decrease in benchmark pricing.
– During Q3/14, AECO natural gas prices increased 49% over Q3/13 levels and decreased 10% from Q2/14 levels. Natural gas prices increased from the comparable period in 2013 due to increased winter weather related natural gas demand. The colder than normal winter resulted in natural gas storage inventories falling below five-year lows in the US and Canada. The decrease from Q2/14 levels is due to decreased summer weather related natural gas demand and an increase in natural gas storage levels.
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. Work is progressing and site preparation and deep underground construction is targeted to be completed in Q4/14.
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 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 796,931 BOE/d for Q3/14 with approximately 98% of production located in G8 countries.
– Canadian Natural has a strong balance sheet with debt to book capitalization of 33% and debt to EBITDA of 1.4x at September 30, 2014.
– Canadian Natural maintains significant financial stability and liquidity represented by bank credit facilities. As at September 30, 2014, the Company had in place bank credit facilities of $5,802 million, of which $2,358 million, net of commercial paper issuances of $560 million, was available.
– The Company–s commodity hedging program is utilized, as required, to protect investment returns, ensure ongoing balance sheet strength and support the Company–s cash flow for its capital expenditure programs. Details of the Company–s commodity hedging program can be found on the Company–s website at .
– Under the Company–s Normal Course Issuer Bid, Canadian Natural has purchased year to date 9,675,000 common shares for cancellation at an average price of $45.01 per common share, which includes 790,000 common shares purchased subsequent to September 30, 2014 at a weighted average price of $39.49 per common share.
– Canadian Natural–s Board of Directors has declared a quarterly cash dividend on common shares of C$0.225 per share payable on January 1, 2014.
– The Company has a strong balance sheet and cash flow generation which enables it to weather volatility in commodity prices. Additionally, Canadian Natural retains significant capital expenditure program flexibility to proactively adapt to changing market conditions.
OUTLOOK
The Company forecasts 2014 production levels before royalties to average between 531,000 and 557,000 bbl/d of crude oil and NGLs and between 1,550 and 1,570 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company–s website at .
MANAGEMENT–S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the “Company”) in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as “forward-looking statements”) within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words “believe”, “anticipate”, “expect”, “plan”, “estimate”, “target”, “continue”, “could”, “intend”, “may”, “potential”, “predict”, “should”, “will”, “objective”, “project”, “forecast”, “goal”, “guidance”, “outlook”, “effort”, “seeks”, “schedule”, “proposed” or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, operating costs, capital expenditures, income tax expenses and other guidance provided throughout this Management–s Discussion and Analysis (“MD&A”), constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the construction and future operations of the North West Redwater bitumen upgrader and refinery, 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, 2014 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2013.
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, 2014 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 refers primarily to the Company–s financial results for the three and nine months ended September 30, 2014 in relation to the comparable periods in 2013 and the second quarter of 2014. The accompanying tables form an integral part of this MD&A. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2013, is available on SEDAR at , and on EDGAR at . This MD&A is dated November 4, 2014.
FINANCIAL HIGHLIGHTS
(1) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation “Adjusted Net Earnings from Operations” presents the after-tax effects of certain items of a non-operational nature that are included in the Company–s financial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company–s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Cash Flow from Operations” presents certain non-cash items that are included in the Company–s financial results. Cash flow from operations may not be comparable to similar measures presented by other companies.
Adjusted Net Earnings from Operations
(1) The Company–s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company–s balance sheets and periodic changes in the fair value are recognized in net earnings or are capitalized to Oil Sands Mining and Upgrading construction costs.
(2) Derivative financial instruments are recorded at fair value on the Company–s balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil and natural gas.
(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% notes.
(5) During the third quarter of 2013, the Company recorded an after-tax gain of $231 million related to the acquisition of Barrick Energy Inc. and the disposition of a 50% working interest in an exploration right in South Africa.
(6) 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 nine months ended September 30, 2014 were $2,731 million compared with $1,857 million for the nine months ended September 30, 2013. Net earnings for the nine months ended September 30, 2014 included net after-tax expenses of $324 million compared with $15 million for the nine months ended September 30, 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, the gain on corporate acquisition/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, 2014 were $3,055 million compared with $1,872 million for the nine months ended September 30, 2013.
Net earnings for the third quarter of 2014 were $1,039 million compared with $1,168 million for the third quarter of 2013 and $1,070 million for the second quarter of 2014. Net earnings for the third quarter of 2014 included net after-tax income of $55 million compared with $159 million for the third quarter of 2013 and net after-tax expenses of $80 million for the second quarter of 2014 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates, and the gain on corporate acquisition/disposition of properties. Excluding these items, adjusted net earnings from operations for the third quarter of 2014 were $984 million compared with $1,009 million for the third quarter of 2013 and $1,150 million for the second quarter of 2014.
The increase in adjusted net earnings for the nine months ended September 30, 2014 from the comparable period in 2013 was primarily due to:
– higher crude oil and NGLs, natural gas, and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments;
– higher crude oil and NGLs and natural gas netbacks in the North America segment;
– higher realized SCO prices; and
– the impact of a weaker Canadian dollar relative to the US dollar;
partially offset by:
– lower crude oil sales volumes in the North Sea and Offshore Africa segments.
The decrease in adjusted net earnings for the third quarter of 2014 from the third quarter of 2013 was primarily due to:
– lower crude oil and NGLs netbacks in the North America segment;
– lower SCO sales volumes in the Oil Sands Mining and Upgrading segment due to the completion of the Horizon coker expansion tie-in;
– lower crude oil sales volumes in the North Sea segment; and
– lower realized SCO prices;
partially offset by:
– higher crude oil and NGLs and natural gas sales volumes in the North America segment;
– higher crude oil sales volumes in the Offshore Africa segment;
– higher natural gas netbacks in the North America segment; and
– the impact of a weaker Canadian dollar relative to the US dollar.
The decrease in adjusted net earnings for the third quarter of 2014 from the second quarter of 2014 was primarily due to:
– lower SCO sales volumes in the Oil Sands Mining and Upgrading segment;
– lower crude oil and NGLs and natural gas netbacks in the North America segment; and
– lower realized SCO prices;
– lower crude oil sales volumes in the North Sea segment;
partially offset by:
– higher crude oil and NGLs sales volumes in the North America segment.
The impacts of share-based compensation, risk management activities and fluctuations in foreign exchange rates are expected to continue to contribute to quarterly volatility in consolidated net earnings and are discussed in detail in the relevant sections of this MD&A.
Cash flow from operations for the nine months ended September 30, 2014 was $7,219 million compared with $5,695 million for the nine months ended September 30, 2013. Cash flow from operations for the third quarter of 2014 was $2,440 million compared with $2,454 million for the third quarter of 2013 and $2,633 million for the second quarter of 2014. 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 the impact of cash taxes.
Total production before royalties for the nine months ended September 30, 2014 increased 15% to 766,871 BOE/d from 669,170 BOE/d for the nine months ended September 30, 2013. Total production before royalties for the third quarter of 2014 increased 13% to 796,931 BOE/d from 702,938 BOE/d for the third quarter of 2013 and decreased 3% from 817,471 BOE/d for the second quarter of 2014.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company–s quarterly results for the eight most recently completed quarters:
Volatility in the quarterly net earnings 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 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, the results from the Pelican Lake water and polymer flood projects, the strong 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 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 in North America, 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 due to the cessation of production of 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 – 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.
– Gains on corporate acquisition/disposition of properties – Fluctuations due to the recognition of gains on corporate acquisitions/dispositions in the third quarter of 2013.
BUSINESS ENVIRONMENT
Commodity Prices
Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. WTI averaged US$99.60 per bbl for the nine months ended September 30, 2014, an increase of 1% from US$98.17 per bbl for the nine months ended September 30, 2013. WTI averaged US$97.21 per bbl for the third quarter of 2014, a decrease of 8% from US$105.82 per bbl for the third quarter of 2013, and a decrease of 6% from US$102.98 per bbl for the second quarter of 2014. For the three and nine months ended September 30, 2014 realized prices were also impacted by the weaker Canadian dollar that increased the Canadian dollar sales price the Company received for its crude oil sales as realized pricing is based on US dollar denominated benchmarks.
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$106.55 per bbl for the nine months ended September 30, 2014, a decrease of 2% from US$108.40 per bbl for the nine months ended September 30, 2013. Brent averaged US$101.90 per bbl for the third quarter of 2014, a decrease of 8% from US$110.35 per bbl for the third quarter of 2013, and a decrease of 7% from US$109.63 per bbl for the second quarter of 2014.
WTI and Brent pricing continued to reflect volatility in supply and demand factors and geopolitical events. The Brent differential from WTI tightened for the nine months ended September 30, 2014 from the comparable period due to continued debottlenecking of logistical constraints from Cushing to the US Gulf Coast. Subsequent to September 30, 2014, WTI and Brent benchmark crude oil prices have continued to decline reflecting overall world supply and demand factors.
The WCS Heavy Differential averaged 21% for the nine months ended September 30, 2014 compared with 23% for the nine months ended September 30, 2013. The WCS Heavy Differential averaged 21% for the third quarter of 2014 compared with 16% for the third quarter of 2013 and 19% for the second quarter of 2014. In October 2014, the WCS Heavy Differential averaged US$13.74 per bbl or 16%. To partially mitigate its exposure to fluctuating heavy crude oil differentials, the Company entered into 20,000 bbl/d of physical crude oil sales contracts for the fourth quarter of 2014 at a weighted average fixed WCS differential of US$20.68 per bbl. In addition, the Company has entered into crude oil WCS differential swaps with weighted average fixed WCS differentials as follows: 30,000 bbl/d in the fourth quarter of 2014 at US$21.07 per bbl and 30,000 bbl/d in the first quarter of 2015 at US$21.49 per bbl.
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$98.20 per bbl for the nine months ended September 30, 2014, a decrease of 3% from US$101.49 per bbl for the nine months ended September 30, 2013. The SCO price averaged US$94.31 per bbl for the third quarter of 2014, a decrease of 14% from US$109.97 per bbl for the third quarter of 2013, and decreased 9% from US$103.87 per bbl for the second quarter of 2014. The decrease in SCO pricing for the three and nine months ended September 30, 2014 from the comparable periods was primarily due to a decrease in WTI benchmark pricing.
NYMEX natural gas prices averaged US$4.51 per MMBtu for the nine months ended September 30, 2014, an increase of 23% from US$3.68 per MMBtu for the nine months ended September 30, 2013. NYMEX natural gas prices averaged US$4.07 per MMBtu for the third quarter of 2014, an increase of 13% from US$3.60 per MMBtu for the third quarter of 2013, and a decrease of 11% from US$4.57 per MMBtu for the second quarter of 2014.
AECO natural gas prices for the nine months ended September 30, 2014 averaged $4.32 per GJ, an increase of 44% from $3.00 per GJ for the nine months ended September 30, 2013. AECO natural gas prices for the third quarter of 2014 averaged $4.00 per GJ, an increase of 49% from $2.68 per GJ for the third quarter of 2013, and a decrease of 10% from $4.44 per GJ for the second quarter of 2014.
Natural gas prices increased for the three and nine months ended September 30, 2014 from the comparable periods in 2013 due to lower natural gas storage levels in 2014. The colder than normal winter resulted in natural gas storage inventories falling to below five-year lows in the US and Canada as at September 30, 2014. Natural gas prices decreased for the third quarter of 2014 from the second quarter of 2014 due to decreased summer weather related natural gas demand and a strong rebuild in storage inventory levels.
DAILY PRODUCTION, before royalties
(1) The Company has commenced production of diesel for internal use at Horizon. Third quarter 2014 SCO production before royalties excludes 875 bbl/d of SCO consumed internally as diesel.
(2) Net of blending costs and excluding risk management activities.
DAILY PRODUCTION, net of royalties
(1) The Company has commenced production of diesel for internal use at Horizon. Third quarter 2014 SCO production before royalties excludes 875 bbl/d of SCO consumed internally as diesel.
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, 2014 increased 8% to 517,428 bbl/d from 478,308 bbl/d for the nine months ended September 30, 2013. Crude oil and NGLs production for the third quarter of 2014 increased 2% to 518,007 bbl/d from 509,182 bbl/d for the third quarter of 2013 and decreased 5% from 545,169 bbl/d for the second quarter of 2014. The increase in production for the nine months ended September 30, 2014 from the comparable period in 2013 was due to higher production in the North America segment and strong and reliable production in Horizon, partially offset by lower international production. The increase in production for the three months ended September 30, 2014 from the comparable period in 2013 reflected higher production in the North America segment offset by lower production at Horizon related to the successful completion of the coker expansion tie-in. The decrease in production for the third quarter of 2014 from the second quarter of 2014 reflected the impact of Horizon–s successful completion of the coker expansion tie-in, partially offset by increased production in the North America and North Sea segments. Crude oil and NGLs production in the third quarter of 2014 was within the Company–s previously issued guidance of 505,000 to 532,000 bbl/d.
Natural gas production for the nine months ended September 30, 2014 increased 31% to 1,497 MMcf/d from 1,145 MMcf/d for the nine months ended September 30, 2013. Natural gas production for the third quarter of 2014 increased 44% to 1,674 MMcf/d from 1,163 MMcf/d for the third quarter of 2013 and increased 2% from 1,634 MMcf/d for the second quarter of 2014. The increase in natural gas production for the three and nine months ended September 30, 2014 from the comparable periods in 2013 was primarily a result of the acquisitions of producing Canadian natural gas properties in the second quarter of 2014, and the completion of the Septimus drilling program and plant facility expansion in the third quarter of 2013. The increase in natural gas production for the third quarter of 2014 from the second quarter of 2014 was primarily the result of major turnarounds in the second quarter of 2014 and increases in production at Septimus. Natural gas production in the third quarter of 2014 was within the Company–s previously issued guidance of 1,645 to 1,675 MMcf/d.
For 2014, annual production guidance is targeted to average between 531,000 and 557,000 bbl/d of crude oil and NGLs and between 1,550 and 1,570 MMcf/d of natural gas.
North America – Exploration and Production
North America crude oil and NGLs production for the nine months ended September 30, 2014 increased 11% to average 384,356 bbl/d from 347,564 bbl/d for the nine months ended September 30, 2013. For the third quarter of 2014, crude oil and NGLs production increased 11% to average 404,114 bbl/d compared with 365,529 bbl/d for the third quarter of 2013 and increased 1% from 400,154 bbl/d for the second quarter of 2014. The increase in production for the three and nine months ended September 30, 2014 from the comparable periods in 2013 was due to increased production related primarily to the acquisitions of producing Canadian crude oil properties in the second quarter of 2014, production at the Company–s thermal areas including Kirby South, the ramp up of production at Pelican Lake, and the impact of a strong heavy crude oil drilling program. The increase in production for the third quarter of 2014 from the second quarter of 2014 was primarily related to production at Kirby South and the ramp up of production at Pelican Lake. Third quarter 2014 production of crude oil and NGLs was within the Company–s previously issued guidance of 393,000 to 410,000 bbl/d.
Natural gas production for the nine months ended September 30, 2014 increased 31 % to 1,468 MMcf/d compared with 1,118 MMcf/d for the nine months ended September 30, 2013. Natural gas production increased 45% to 1,644 MMcf/d for the third quarter of 2014 compared with 1,136 MMcf/d in the third quarter of 2013 and increased 2% from 1,606 MMcf/d for the second quarter of 2014. The increase in natural gas production for the three and nine months ended September 30, 2014 from the comparable periods in 2013 was primarily a result of the acquisitions of producing Canadian natural gas properties in the second quarter of 2014, and the completion of the Septimus drilling program and plant facility expansion in the third quarter of 2013. The increase in natural gas production for the third quarter of 2014 from the second quarter of 2014 was primarily the result of major turnarounds in the second quarter of 2014 and increases in production at Septimus.
North America – Oil Sands Mining and Upgrading
Production averaged 104,667 bbl/d for the nine months ended September 30, 2014 compared with 96,244 bbl/d for the nine months ended September 30, 2013. For the third quarter of 2014, SCO production decreased 27% to 82,012 bbl/d from 111,959 bbl/d for the third quarter of 2013 and decreased 31% from 119,236 bbl/d for the second quarter of 2014. Production increased for the nine months ended September 30, 2014 from the comparable period in 2013 due to increased plant reliability. Third quarter 2014 production reflected the successful completion of the Horizon coker expansion tie-in and was within the Company–s previously issued guidance of 82,000 to 89,000 bbl/d.
North Sea