Canadian Natural Resources Limited Announces 2015 Second Quarter Results
Commenting on second quarter results, Steve Laut, President of Canadian Natural stated, “Canadian Natural is in a strong position. Our strong, diverse and well balanced asset base, and the effectiveness of our strategies, combined with our ability to execute these strategies, allows us to react quickly in this challenging commodity price environment.
In the second quarter, we delivered operationally, achieving record gas production at 1.779 Bcf/d, which exceeded production guidance and increased 9% over the same quarter in 2014. Oil production was strong, and we expect to deliver annual oil production at the midpoint of guidance despite the forest fire impact on second quarter oil production.
Canadian Natural’s operations continue to be effective and efficient. We have been able to achieve significant cost savings through better effectiveness, efficiency and innovation. Both operating and capital costs were down significantly from the second quarter in 2014 to the second quarter of this year.”
Canadian Natural’s Chief Financial Officer, Corey Bieber, continued, “The Company has proactively reduced its development programs in the context of lower commodity prices and lower cash flow. Liquidity remains strong at
$3.3 billion. During the second quarter, absent the impact of the $579 million charge due to the 20% increase in Alberta corporate income tax rates, our earnings would have been $174 million. This charge effectively translates into lower future cash flows and therefore, lowers reinvestment in the business. Based upon third party research, this lower future capital reinvestment likely equates to about 4,100 fewer person years of direct, indirect and induced employment, with follow-on impact of higher income taxes on future income streams.”
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’s 2015 second quarter crude oil and NGL production volumes averaged 509,047 bbl/d, and natural gas volumes reached record quarterly levels of 1,779 MMcf/d.
– Operations during Q2/15 were solid as the Company’s large, balanced and diverse asset base continues to support the transition to a longer life and lower decline asset base. Q2/15 operational highlights include:
— Pelican Lake production volumes increased in the second quarter to record levels of 52,015 bbl/d, 5% higher than Q2/14 levels and 2% higher than Q1/15 levels. This leading edge polymer flood continues to perform with increasing production volumes and decreasing operating costs despite no drilling activity since Q3/14. Canadian Natural leverages innovation and technology to create value through strong netbacks and robust economic returns.
— 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 approximately $0.18/Mcfe in Q2/15.
— Total Offshore Africa quarterly crude oil production in Q2/15 averaged 17,070 bbl/d, an increase of 30% over Q2/14 levels and an increase of 29% over Q1/15 levels. The infill drilling programs at the Espoir and Baobab fields in Cote d’Ivoire continue to be successfully executed with results exceeding expectations.
— To date, 3 gross wells have been drilled at Espoir, adding net production of approximately 4,500 bbl/d. Espoir is targeted to add overall net production volumes of 5,900 bbl/d through a 10 gross well
program which includes 4 water injection wells (5.9 net well program) and is currently tracking below sanctioned costs.
— To date, Canadian Natural drilled 1 gross well at Baobab, adding net production volumes of approximately 2,000 bbl/d. Production from the second gross well is targeted to come on stream in the third quarter of 2015. Baobab is targeted to add overall net production volumes of 11,000 bbl/d through a 6 gross well program (3.4 net well program), which is currently tracking below sanctioned costs.
— Thermal operations were temporarily interrupted from late May to early June as a result of Northeastern Alberta forest fires. Employees were safely evacuated and only minor facility damage occurred. Total quarterly production volumes were reduced as a result of the related shut-down at Primrose and production curtailment at Kirby South.
— 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 exceeding expectations, and due to the cyclic nature of operations at Primrose East Area 2, current production volumes are ranging from 15,000 bbl/d to 20,000 bbl/d.
— At Horizon Oil Sands (“Horizon”), the full maintenance turnaround originally scheduled in Q3/15 was deferred to 2016 to capture opportunities for production optimization of Phase 2B. During Q2/15, the Company planned a 10 day turnaround focusing on critical activities. The turnaround was extended from 10 days to 15 days to address necessary found work and the start-up of operations was slightly slower than expected. As a result, production volumes were lower than the Q2/15 guidance range. The Company targets strong production volumes going forward with Q3/15 production volumes targeted to range from 124,000 bbl/d to 131,000 bbl/d. 2015 annual production guidance remains unchanged from 121,000 bbl/d to 131,000 bbl/d.
— Due to Canadian Natural’s enhanced focus on operating efficiencies, the 2015 annual operating cost guidance range for Horizon has been further reduced from $31.00/bbl to $34.00/bbl to $30.00/bbl to $33.00/bbl.
– 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 consisted of just 13 net wells in Q2/15 compared to 191 net wells in Q2/14, a 93% reduction year over year.
– Canadian Natural remains committed to its effective and efficient operations, with an enhanced focus on cost optimization. During the second quarter, the Company achieved strong operating cost reductions in the following areas:
(1) Horizon Q2/15 operating costs adjusted to reflect impact of the June 2015 maintenance turnaround.
– 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 13%.
– In addition to the operating cost efficiencies achieved during the quarter, Canadian Natural continues to attain capital cost savings and has lowered its capital spending program by an additional $245 million from $5,745 million to $5,500 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.
– Canadian Natural generated cash flow from operations of approximately $1.5 billion in Q2/15 compared to approximately $2.6 billion in Q2/14 and $1.4 billion in Q1/15. The decrease in Q2/15 from Q2/14 primarily reflects lower benchmark pricing partially offset by reduced operating costs.
– The Company incurred a net loss in Q2/15 of $405 million, compared to net earnings of $1,070 million in Q2/14 and a net loss of $252 million in Q1/15. The net loss in Q2/15 was primarily a result of the 20% increase in the Alberta provincial corporate income tax rate from 10% to 12%, increasing Canadian Natural’s deferred income tax liability by $579 million. Adjusted net earnings from operations for Q2/15 were $178 million, compared to adjusted net earnings of $1,150 million in Q2/14 and $21 million in Q1/15. Changes in adjusted net earnings largely reflect the changes in cash flow.
– During Q2/15, Canadian Natural’s $1,500 million revolving syndicated credit facility was increased to $2,425 million and the maturity date was extended to June 2019 from June 2016. The Company’s $3,000 million revolving syndicated credit facility was reduced to $2,425 million and the maturity date was extended to June 2020 from June 2017. As a result, the Company’s available liquidity increased by $350 million, ending the quarter at approximately $3.3 billion.
– Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on
October 1, 2015.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its activities in core regions where the Company owns a substantial land base and associated infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning and operating associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Furthermore, the Company maintains large project inventories and production diversification among each of the commodities it produces; light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein collectively referred to as “crude oil”), natural gas and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
Drilling Activity
– As a direct result of the decrease in crude oil and natural gas pricing and other external events, the Company has proactively reduced its 2015 drilling programs. Drilling activity in Q2/15 consisted of 13 net wells compared to 191 net wells in Q2/14.
North America Exploration and Production
– Quarterly production volumes of North America crude oil and NGLs were 270,021 bbl/d in Q2/15, a decrease of 6% from both Q2/14 and Q1/15 levels respectively.
– As expected, North America light crude oil and NGL quarterly production averaged 89,226 bbl/d in Q2/15. Production volumes decreased 4% and 9% from Q2/14 levels and Q1/15 levels respectively, largely as a result of expected production declines offset by the modest light crude oil drilling program in place. North America light crude oil drilling activity consisted of 4 wells in the first half of 2015 compared to 52 net wells in the first half of 2014, a 92% reduction.
– Despite the reduction in production volumes, North America light crude oil and NGL quarterly operating costs decreased to $15.29/bbl in Q2/15, 13% lower than Q2/14 levels of $17.56/bbl and 6% lower than Q1/15 levels of $16.23/bbl.
– Pelican Lake operations achieved record quarterly heavy crude oil production volumes of 52,015 bbl/d, a 5% increase from Q2/14 levels and a 2% increase from Q1/15 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake.
– Operational efficiencies continue to be a focus at Pelican Lake. Industry leading quarterly operating costs decreased to $6.98/bbl, 22% lower than Q2/14 and 19% lower than Q1/15.
– In Q2/15, primary heavy crude oil production averaged 128,780 bbl/d, a decrease of 10% and 6% from Q2/14 and Q1/15 levels respectively. The decrease in production volumes reflects a significantly reduced drilling program of 4 net wells in Q2/15 compared to 122 net wells in Q2/14, as well as the Company’s prudent decision to shut-in approximately 4,000 bbl/d of primary heavy crude oil production as a result of unfavorable economic conditions.
– The strength of Canadian Natural’s primary heavy crude oil asset base is its strong operating free cash flow established by achieving low operating costs. As demonstrated, primary heavy crude oil quarterly operating costs decreased in Q2/15 to $14.92/bbl compared to $17.61/bbl in Q2/14 and $17.21/bbl in Q1/15, cost reductions of 15% and 13% respectively.
– In Q2/15, thermal in situ production volumes averaged 105,019 bbl/d, a decrease of 8% and 28% from Q2/14 and Q1/15 production volume levels respectively. The decrease in Q2/15 from Q1/15 production volumes primarily reflects reduced production volumes impacted by the cyclic nature of Primrose operations, and the Northeastern Alberta forest fires from late May to early June that caused thermal operations at Primrose to temporarily shut down and as well as production curtailments at Kirby South.
– At Kirby South, Q2/15 production volumes were curtailed as a result of the shut-down of the Cold Lake sales pipeline due to the forest fires. Despite the impact of the forest fires, production volumes increased to 26,193 bbl/d as operations continue to ramp up to the targeted 40,000 bbl/d of design capacity. The reservoir continues to perform as expected with very good thermal efficiencies. For wells on Steam Assisted Gravity Drainage (“SAGD”), the steam to oil ratio (“SOR”) in Q2/15 was 2.6. For July 2015, Kirby South’s production volumes averaged approximately 32,000 bbl/d.
– 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 exceeding expectations, and due to the cyclic nature of operations at Primrose East Area 2, current production volumes are ranging from 15,000 bbl/d to 20,000 bbl/d.
– North America natural gas production reached record quarterly levels averaging 1,716 MMcf/d for Q2/15, an increase of 7% from Q2/14 levels and comparable to Q1/15 levels. The increase from Q2/14 levels resulted from additional production volumes acquired in 2014, complemented by a focused liquids-rich natural gas drilling program.
– 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 approximately $0.18/Mcfe in Q2/15.
– North America natural gas production volumes during Q2/15 were impacted by 46 MMcf/d as a result of transportation restrictions on the NOVA pipeline system. Restricted pipeline take away capacity anticipated in Northwest Alberta during Q3/15 is currently expected to lower the Company’s North America natural gas production volumes by approximately 80 MMcf/d. Canadian Natural’s Q3/15 total natural gas production guidance reflects these impacts and is targeted to range from 1,670 MMcf/d to 1,690 MMcf/d.
– North America natural gas quarterly operating costs were $1.28/Mcf in Q2/15, a 14% decrease from Q2/14 levels of $1.48/Mcf, and a 7% decrease from Q1/15 levels of $1.38/Mcf, reflecting a continued focus on cost optimization.
International Exploration and Production
– International crude oil production averaged 37,400 bbl/d during Q2/15, an increase of 45% from Q2/14 levels and a 3% increase from Q1/15 levels. The increase in production over Q2/14 levels primarily reflected the reinstatement of production from both the Banff FPSO and the Tiffany platform during 2014. The increase in production from Q1/15 was primarily due to bringing new wells onstream at the Baobab and Espoir fields during Q2/15, offset by a planned turnaround performed at Ninian that commenced in late June 2015 and was completed in July 2015.
– The infill drilling programs at the Espoir and Baobab fields in Cote d’Ivoire continue to be successfully executed with results exceeding expectations.
— To date, 3 gross wells have been drilled at Espoir, adding net production of approximately 4,500 bbl/d. Espoir is targeted to add overall net production volumes of 5,900 bbl/d through a 10 gross well program which includes 4 water injection wells (5.9 net well program) and is currently tracking below sanctioned costs.
— To date, Canadian Natural drilled 1 gross well at Baobab, adding net production volumes of approximately 2,000 bbl/d. Production from the second gross well is targeted to come on stream in the third quarter of 2015. Baobab is targeted to add overall net production volumes of 11,000 bbl/d through a 6 gross well program (3.4 net well program), which is currently tracking below sanctioned costs.
North America Oil Sands Mining and Upgrading – Horizon
(1) The Company has commenced production of diesel for internal use at Horizon. Second quarter 2015 SCO production before royalties excludes 2,410 bbl/d of SCO consumed internally as diesel (first quarter 2015 – 1,676 bbl/d; second quarter 2014 – nil; six months ended June 30, 2015 – 2,045 bbl/d; six months ended June 30, 2014 – nil).
– Horizon quarterly production averaged 96,607 bbl/d of SCO, a decrease of 19% and 28% from Q2/14 and Q1/15 levels respectively. Q2/15 production volumes were lower than targeted volumes primarily as a result of an extension of the 2015 planned maintenance turnaround from 10 days to 15 days in June, to address necessary found work, and a slightly slower than expected start-up of operations post-turnaround. July production volumes averaged approximately 124,200 bbl/d, near the low end of the targeted utilization rate range of 92% to 96%. Q3/15 production guidance is targeted to range from 124,000 bbl/d to 131,000 bbl/d, with a targeted utilization rate of 93% at the midpoint. 2015 annual production guidance remains unchanged at 121,000 bbl/d to 131,000 bbl/d.
– 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 67% physically complete as at Q2/15:
— Reliability – Tranche 2 is 100% physically complete. Completion occurred in 2014 resulting in increased performance and overall production reliability. This contributed approximately 5% increase in production levels from Phase 1 production levels.
— Directive 74 includes technological investment and research into tailings management. This project remains on track and is 55% physically complete.
— Phase 2A is a coker expansion that was originally scheduled to be completed in mid-2015; however, due to strong construction performance and the early completion of the coker installation, the Company accelerated the tie-in to August 2014. The expanded Coker Unit is now fully operational and the project was completed on time and below budget. Horizon SCO production levels increased by approximately 12,000 bbl/d with the completion of the coker tie-in. Through the completion of Phase 2A, additional coker capacity and equipment were added, increasing the plant nameplate capacity to 133,000 bbl/d. New equipment performance combined with an optimized mining strategy have increased the stability of the extraction and upgrading processes, resulting in a further increase to plant nameplate capacity to 137,000 bbl/d.
— Phase 2B is 62% 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 Q2/16 turnaround. Production volumes after the turnaround are targeted to increase by 4,000 bbl/d in Q3/16 and 10,000 bbl/d in Q4/16, above the original planned production ramp up. Full commissioning of the Phase 2B equipment will be completed as planned in late 2016, adding 45,000 bbl/d of production capacity.
— Phase 3 is currently on budget and on schedule. This Phase is 59% physically complete, and includes the addition of extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in late 2017 and will result in additional reliability, redundancy and significant operating cost savings for the Horizon project.
ROYALTY PRODUCTION AND REVENUE
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 Q1/15:
– The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Total drilling activity for the first half of 2015 consisted of 151 wells with 146 drilled by third parties and 5 drilled by Canadian Natural. Compared to Q4/14, total Q1/15 production volumes on the royalty lands decreased by 195 BOE/d, however, crude oil and NGL production increased by 60 bbl/d.
– The Company continues to focus on lease compliance, well commitments, offset drilling obligations and compensatory royalties payable.
– Royalty production volumes highlighted below are not reported in Canadian Natural’s quarterly production volumes. Third party royalty revenues are included in reported Product Sales in the Company’s consolidated statement of earnings.
Royalty Production Volumes Comparison (1)
Royalty Production Volumes (1)
Royalty Revenue by Product (1)
Revenue by Royalty Classification (1)
Royalty Realized Pricing (1)
Royalty Acreage
(1) Based on the Company’s current estimate of revenue and volumes attributable to the noted period.
(2) Indicates Canadian Natural is both the Lessor and Lessee, thereby incurring intercompany royalties; in addition there are certain Canadian Natural fee title lands where the Company has production where no royalty burden has been recognized in this table.
(3) Includes sulphur revenue, bonus payments, lease rentals and compliance revenue.
(4) Includes Net Profit Interests and other royalties.
(5) Includes fee title and freehold 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.
(i) Based on current indicative pricing as at July 31, 2015. SCO and Condensate September pricing based on current indicative pricing as at August 5, 2015.
– Volatility in supply and demand factors and geopolitical events continued to affect WTI and Brent pricing. The Organization of the Petroleum Exporting Countries’ (“OPEC”) decision to maintain crude oil production quotas resulted in a year over year decline in benchmark pricing. Crude oil pricing increased in Q2/15 from Q1/15 as a result of slower US shale oil production growth, market response to reduced rig counts and lower crude oil inventories at Cushing as a result of higher refinery utilizations.
– The WCS differential to WTI averaged US$11.60/bbl or 20% in Q2/15 compared to US$20.03/bbl or 19% in Q2/14. The WCS heavy differential narrowed during Q2/15 compared to Q1/15 due to increased refinery utilization and seasonal demand. August 2015 and September 2015 indications of the WCS heavy differential are trending higher to US$13.41/bbl or 28% and US$15.95/bbl or 33%, respectively. This widening is mainly due to planned refinery turnarounds, which are typical during this time of year. Seasonal demand fluctuations, changes in transportation logistics and refinery utilization and shutdowns will continue to be reflected in WCS pricing.
– Canadian Natural contributed approximately 162,000 bbl/d of its heavy crude oil stream to the WCS blend in Q2/15. The Company remains the largest contributor to the WCS blend, accounting for 47% of the total blend.
– SCO pricing averaged US$60.61/bbl during Q2/15 compared to US$45.26/bbl in Q1/15, as a result of an increase in WTI benchmark pricing and industry-wide oil sands production interruptions caused by planned and unplanned production outages. Year over year SCO pricing has decreased resulting from an overall decline in WTI benchmark pricing.
– AECO natural gas pricing in Q2/15 averaged $2.53/GJ, a decrease of 43% and 10% from Q2/14 and Q1/15 pricing respectively. In Q2/15, US natural gas production continued to grow while natural gas inventories remained at normal industry levels, leading to downward pressure on natural gas prices. Natural gas prices were lower in Q2/15 compared to Q1/15 primarily due to seasonal demand. Warmer weather and adequate storage levels primarily resulted in lower natural gas pricing in Q2/15 compared to Q2/14, which had lower than average storage levels due to 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 approximately 805,500 BOE/d for Q2/15 with approximately 97% of production located in G8 countries.
– During the second quarter, the Company priced C$500 million principal amount of notes through the reopening of its 2.89% medium-term notes, series 2, due August 14, 2020.
– In Q2/15, the Company increased its $1,500 million revolving syndicated credit facility to $2,425 million and the maturity date was extended to June 2019. The $3,000 million revolving syndicated credit facility was reduced to $2,425 million and the maturity date was extended to June 2020. As a result, the Company’s available liquidity increased by $350 million.
– Canadian Natural has a strong balance sheet with debt to book capitalization of 37% and debt to EBITDA of 2.0x at June 30, 2015. All of the Company’s credit facilities are now subject to a revised financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 0.65 to 1.0.
– Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at June 30, 2015, the Company had in place bank credit facilities of $7,479 million, of which $3,272 million was available.
– 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
October 1, 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 562,000 and 602,000 bbl/d of crude oil and NGLs and between 1,730 and 1,770 MMcf/d of natural gas. Q3/15 production guidance before royalties is forecast to average between 559,000 and 590,000 bbl/d of crude oil and NGLs and between 1,670 and 1,690 MMcf/d of natural gas. Detailed guidance on production levels, capital allocation and operating costs can be found on the Company’s website atwww.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 six months ended June 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 June 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 six months ended June 30, 2015 in relation to the comparable periods in 2014 and the first 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 August 5, 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