Canadian Natural Resources Limited Announces 2015 Fourth Quarter and Year End Results and 2016 Budget
(firmenpresse) - CALGARY, ALBERTA -- (Marketwired) -- 03/03/16 -- Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ)
Commenting on the fourth quarter 2015 results, Steve Laut, President of Canadian Natural stated, "2015 was a strong operational year for Canadian Natural despite the significant drop in commodity prices. In 2015, we were able to reduce original budgeted capital spending by $3.4 billion, but still delivered 8% production growth. At the same time, we significantly lowered the cost structure within all our operations, and delivered excellent reserve replacement ratios of 179% on proved developed producing reserves and 165% on total proved reserves, and exceptional finding, development and acquisition costs.
2016 is a milestone year for Canadian Natural with the start-up of Horizon Phase 2B just 7 months away. The Company''s transition to a long life, low decline asset base continues. Upon such start-up, even at US$30/bbl WTI, our cash flow in the fourth quarter of 2016 when annualized will cover, on a go forward basis, all forecast base annual capital expenditures and current annualized dividends, as Horizon expansion capital spending drops dramatically with the start of Horizon Phase 2B.
In 2017, Horizon expansion capital will drop to approximately one billion dollars and the 80,000 bbl/d of Horizon Phase 3 is targeted to start in the fourth quarter of 2017, generating significant additional unallocated cash flow. In 2018, Horizon expansion capital drops to zero with targeted production in excess of 250,000 bbl/d for the entire year. Combined with lower operating costs, the Horizon project will generate substantial cash flow, which along with the 2017 unallocated cash flow will allow the balance sheet to quickly strengthen."
Canadian Natural''s Chief Financial Officer, Corey Bieber, continued, "Canadian Natural effectively managed our balance sheet in 2015 through proactive capital spending cuts, lowering our overall operating and capital cost structure and the monetization of a significant portion of our third party royalty stream. In 2016, we are proactively managing capital spending to the current price environment and will maintain additional capital flexibility we can exercise if we choose. Horizon Phase 2B start up is 7 months away, at which time the nature of the Company''s production profile takes another step towards a long life, low decline profile. Canadian Natural currently has in place sufficient liquidity to ensure the funding of all targeted activities in 2016 and 2017. By the fourth quarter of 2016, annualized cash flow will then be in a position to cover all base annual capital and current annualized dividend requirements. As a result, Canadian Natural has maintained its investment grade ratings and believes our current dividend policy is appropriate reflecting the strength and robustness of the Company''s operations and assets."
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.
Annual Overview
- Canadian Natural demonstrated strong operational performance throughout 2015 despite significantly reducing its 2015 drilling programs for both crude oil and natural gas, as a result of sharply lower commodity pricing during the year. The Company''s 2015 drilling programs consisted of 306 net wells, an 80% decrease from its 2014 drilling programs of 1,554 net wells. Through a focused drilling program, strategic acquisitions and productivity enhancements, the Company was able to achieve record annual production volumes in 2015 of 851,901 BOE/d, representing an increase of 8% from 2014 levels.
-- Record annual crude oil and NGL production volumes in 2015 averaged 564,188 bbl/d, representing an increase of 6% from 2014 levels, and within the Company''s 2015 annual guidance range of 555,000 bbl/d to 591,000 bbl/d.
--- Horizon Oil Sands ("Horizon"), Canadian Natural''s world class oil sands mining and upgrading operations, achieved record annual production of 122,911 bbl/d of synthetic crude oil ("SCO") in 2015, representing an 11% increase from 2014 levels. Through its safe, steady and reliable operations and a strong focus on continuous improvement, the Company''s annual operating costs averaged C$28.61/bbl (US$22.37/bbl equivalent) in 2015, a 23% reduction from 2014 levels.
--- Thermal in situ oil sands ("thermal in situ") annual production volumes reached record levels of 129,835 bbl/d, representing a 20% increase from 2014 volumes. During the year, the Kirby South steam assisted gravity drainage ("SAGD") volumes advanced toward facility capacity as annual production volumes averaged 29,467 bbl/d with November 2015 volumes exceeding 41,000 bbl/d. The Company continues to enhance its focus on effective and efficient operations at its thermal in situ projects achieving annual operating costs of $10.43/bbl, a 17% reduction from 2014 levels.
--- Pelican Lake annual production improved by 1% to 50,818 bbl/d from 2014 levels and achieved strong annual operating costs of $7.24/bbl, a 15% reduction from 2014. This leading edge polymer flood continues to perform with increasing production volumes and decreasing operating costs despite no drilling activity in the project since Q3/14. Canadian Natural leverages innovation and technology to create value through strong netbacks and robust economic returns.
--- North America light crude oil and NGL annual production averaged a record level of 91,283 bbl/d in 2015, an increase of 2% from 2014 volumes. The increase in volumes result from strategic acquisitions offset by expected production declines. In 2015, 4 net wells were drilled compared to 101 net wells drilled in 2014. 2015 operating costs were reduced by 14% over 2014 levels.
--- International Exploration & Production ("E&P") annual production volumes increased to 41,295 bbl/d, representing a 39% increase from 2014 levels. North Sea improved volumes by 28% to 22,216 bbl/d while Offshore Africa''s infill drilling programs at Espoir and Baobab increased production by 54% to 19,079 bbl/d. 2015 International operating costs decreased by 19% from 2014 levels.
-- The Company achieved record annual natural gas volumes of 1,726 MMcf/d, an increase of 11% from 2014 levels primarily as a result of opportunistic acquisitions and a focused liquids-rich natural gas drilling program. 2015 operating costs were reduced by 9% from 2014 levels.
- During 2015, Canadian Natural continued to advance its Horizon expansion project, the major component of its transition to a longer life, low decline asset base. At December 31, 2015, physical progress of Horizon Phase 2B and 3 were 79% and 74% complete, respectively. Total Horizon expansion project capital costs continue to trend below budget estimate.
- The start-up of Horizon Phase 2B is targeted in 7 months and will add 45,000 bbl/d of production capacity. Project capital in 2016 is targeted to be approximately $2 billion, the majority of which will be spent over the first nine months of 2016. In 2017, Horizon project capital costs are targeted to decline to approximately $1 billion for Phase 3 completion, which will add incremental production volumes of 80,000 bbl/d. At expansion completion, targeted for Q4/17, Canadian Natural targets total Horizon production volumes to average 250,000 bbl/d of SCO with operating costs trending below C$25.00/bbl (less than US$18.00/bbl equivalent).
- The Company initially announced its original 2015 capital budget in November 2014 at $8.6 billion. As a result of steeply declining commodity prices, the Company responded quickly and revised the budget in January 2015 to $6.2 billion. Due to the significant capital flexibility within the Company''s program, three subsequent instances of cost cutting measures were implemented during the rest of 2015, ultimately reducing the gross capital program by approximately $3.4 billion to approximately $5.2 billion. As a result of an effective acquisitions and dispositions program in 2015, the largest transaction being the royalty land disposition to PrairieSky, the Company''s 2015 net expenditure program ended up totaling approximately $3.9 billion.
- Despite the significant reduction in the Company''s 2015 original capital budget by $3.4 billion, 2015 total corporate production volumes increased to 851,901 BOE/d, representing an increase of 8% over 2014 levels.
- In 2015, Canadian Natural continued to focus on effective and efficient operations reducing operating and capital costs throughout its business. As a result, the Company achieved over $1.1 billion in operating cost savings year-over-year based on 2014 unit rates versus 2015 unit rates, which is demonstrated by the product comparison in the table below.
(1) Horizon operating costs adjusted to reflect the impact of maintenance turnarounds.
- From 2014 to 2015, Canadian Natural attained drilling, completions, and facility cost reductions of a capital natural from 20% to 25% throughout its North America E&P operations. These reductions contributed to the Company''s ability to decrease its 2015 capital expenditure program by approximately $3.4 billion since November 2014. For 2016, the Company targets to achieve additional drilling and completions cost reductions from 5% to 10% and from 10% to 20% in facility cost reductions.
- In December 2015, Canadian Natural completed the sale of a substantial portion of its royalty assets to PrairieSky for an aggregate price of $1.66 billion, consisting of $673 million in cash and the issuance of approximately 44.4 million PrairieSky common shares valued at $22.16 per common share.
-- From its royalty assets, the Company divested a portion of its production volumes and added to its royalty portfolio through certain opportunistic acquisitions executed through 2015. The Company''s estimate of current production volumes attributed to its royalty portfolio is approximately 2,100 BOE/d, of which 1,100 BOE/d are Canadian Natural royalty volumes.
-- Canadian Natural has agreed with PrairieSky to distribute, by no later than December 31, 2016, by way of a dividend, return of capital or otherwise (subject to regulatory approval and securities and tax regulations) sufficient PrairieSky Common Shares so that Canadian Natural, after such distribution, owns, directly or indirectly, less than 10% of the issued and outstanding shares of PrairieSky (the "Share Distribution"). Canadian Natural''s current intention is to distribute to its shareholders the majority of the Share Consideration on or after its next Annual and Special Meeting of Shareholders in May 2016, providing Canadian Natural shareholders with the opportunity to participate directly and indirectly in the combined royalty business of PrairieSky. Prior to the Share Distribution, Canadian Natural has agreed not to sell or otherwise dispose, or agree to sell or otherwise dispose, of the PrairieSky Common Shares comprising the Share Consideration, subject to certain exceptions.
- Canadian Natural realized cash flow from operations in 2015 of approximately $5.8 billion. The decrease in 2015 from 2014 primarily reflects lower benchmark pricing partially offset by reduced operating costs and increased natural gas and crude oil sales volumes.
- For 2015, the Company had a net loss of $637 million compared to net earnings of $3.9 billion in 2014. Adjusted net earnings from operations were $263 million in 2015 compared to $3.8 billion in 2014. Changes in adjusted net earnings primarily reflect the changes in cash flow from operations.
- Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit facilities. As at December 31, 2015, the Company had in place bank credit facilities of $7,481 million, of which $3,495 million was available.
-- During the first two quarters of 2015, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018 and extended its two existing revolving syndicated term credit facilities to mature in June 2019 and June 2020. The result of the extension of the two revolving $2,425 million facilities netted an additional $350 million of liquidity. The Company''s credit facilities provide that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 65%.
-- Subsequent to December 31, 2015, the Company prepaid $250 million of the borrowings from the $1,000 million non-revolving term credit facility and extended the facility to February 2019 from January 2017. In addition the Company entered into a new $125 million non-revolving term credit facility maturing February 2019, which was fully drawn. Borrowings under this facility may be made by way of pricing referenced to Canadian dollar bankers'' acceptances or Canadian prime loans.
- Canadian Natural maintained a strong balance sheet with debt to book capitalization of 38% at December 31, 2015.
- Subsequent to December 31, 2015, Standard & Poor''s Rating Services maintained the Company''s investment grade unsecured long-term and short-term credit ratings and DBRS Limited maintained the Company''s investment grade unsecured long-term credit rating. Additionally, Moody''s Investors Service, Inc. adjusted the Company''s credit ratings within the investment grade debt rating scale.
- Canadian Natural declared a quarterly cash dividend on its common shares of C$0.23 per share payable on April 1, 2016. On an annualized basis, the dividend of C$0.92 per share remains unchanged from the previous annual dividend rate and reflects the Board of Director''s confidence in the Company''s cash flow.
- Canadian Natural''s crude oil, SCO, bitumen, natural gas and NGL reserves were evaluated and reviewed by Independent Qualified Reserves Evaluators. The following highlights are based on the Company''s reserves using forecast prices and costs as at December 31, 2015 (all reserve values are Company Gross unless stated otherwise).
-- Proved crude oil, SCO, bitumen and NGL reserves increased 4% to 4.70 billion barrels. Proved natural gas reserves increased 2% to 6.11 Tcf. Total proved reserves increased 4% to 5.71 billion BOE.
-- Proved developed producing reserve additions and revisions, including acquisitions and dispositions, were 468 million barrels of crude oil, SCO, bitumen and NGL and 527 billion cubic feet of natural gas. The total proved developed producing reserves replacement ratio was 179%.
-- Proved reserve additions and revisions, including acquisitions and dispositions, were 390 million barrels of crude oil, SCO, bitumen and NGL and 735 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio was 165%. The total proved BOE reserve life index is 21.5 years.
-- Proved plus probable crude oil, SCO, bitumen and NGL reserves increased 1% to 7.62 billion barrels. Proved plus probable natural gas reserves increased 5% to 8.51 Tcf. Total proved plus probable reserves increased 2% to 9.04 billion BOE.
-- Proved plus probable reserve additions and revisions, including acquisitions and dispositions, were 294 million barrels of crude oil, bitumen, SCO and NGL and 1.0 trillion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 148%. The total proved plus probable BOE reserve life index is 34.0 years.
-- Corporate finding, development and acquisition (FD&A) costs, excluding changes in future development capital (FDC) and excluding proceeds from the royalty asset disposition, were strong at $9.96/BOE on a proved basis and $11.08/BOE on a proved plus probable basis.
-- Corporate FD&A costs including changes in future development capital cannot be calculated since the decrease in FDC exceeds 2015 capital expenditures. However, North America FD&A costs including FDC, excluding Horizon, were $1.69/BOE on a proved basis and $0.27/BOE on a proved plus probable basis.
-- The corporate net present values, at a 10% discount rate, of the future net revenue, before income taxes, was $65.2 billion on a proved basis which is a 5% decrease from the year end 2014 evaluation. On a proved plus probable basis, the net present value was $89.0 billion, a 5% decrease from year end 2014.
Fourth Quarter Overview
- Canadian Natural continued to demonstrate solid operational performance during the fourth quarter of 2015. Total crude oil and NGL production was 572,000 bbl/d for Q4/15, which was comparable to Q4/14 and Q3/15 levels. Highlights of the Company''s quarterly operational performance include:
-- Horizon quarterly production volumes averaged 129,050 bbl/d of SCO, 1% higher than Q4/14 levels and 2% lower than Q3/15 levels. Excellent operating costs of $28.56/bbl (US$21.39/bbl equivalent) were achieved at Horizon in Q4/15, a 17% decrease from Q4/14 levels.
-- Thermal in situ quarterly production volumes were 135,135 bbl/d and Kirby South production increased to 33,746 bbl/d with November 2015 volumes at Kirby South exceeding 41,000 bbl/d. Q4/15 thermal in situ volumes increased by 14% and 1% from Q4/14 and Q3/15 levels respectively.
-- International E&P Q4/15 production volumes improved to 47,942 bbl/d, an increase of 41% and 10% from Q4/14 and Q3/15 volumes respectively. North Sea volumes were 5% and 3% higher than Q4/14 and Q3/15 levels respectively, while Offshore Africa production improved 106% and 18% from Q4/14 and Q3/15 levels respectively.
- Total natural gas production was 1,703 MMcf/d in Q4/15, a decrease of 2% from Q4/14 levels and an increase of 3% from Q3/15 levels. The decrease in production levels from the same quarter in the previous year reflect third party transmission pipeline restrictions in Northwest Alberta, as well as shut-ins of production volumes due to low natural gas pricing, which was largely driven by pipeline restrictions and partially offset by an increase in International quarterly natural gas production volumes.
- During the fourth quarter, the Company continued to realize operating cost reductions. Operating costs achieved in Q4/15 were lower than 2015 average annual operating costs illustrating the Company''s ability to maintain its focus on enhancing the effectiveness and efficiency of its operating cost structures.
(1) Horizon operating costs adjusted to reflect the impact of maintenance turnarounds.
- Capital expenditures, compared to budget, decreased by another $193 million in Q4/15 reflecting the Company''s ability to attain further drilling and completions cost reductions and further facility cost decreases throughout its North America E&P operations.
- Canadian Natural generated cash flow from operations of approximately $1.4 billion in Q4/15 compared to approximately $2.4 billion in Q4/14 and $1.5 billion in Q3/15. The decrease in Q4/15 from Q4/14 primarily reflects lower benchmark pricing volumes partially offset by reduced operating costs.
- Net earnings from operations for Q4/15 were $131 million, compared to net earnings of $1,198 million in Q4/14 and a net loss of $111 million in Q3/15. In Q4/15, adjusted net loss from operations was $49 million, compared to adjusted net earnings of $756 million in Q4/14 and $113 million in Q3/15. Changes in adjusted net earnings primarily reflect the changes in cash flow.
HIGHLIGHTS OF THE 2016 BUDGET
- Canadian Natural develops its capital budgets to be flexible and nimble allowing the Company to proactively adapt to changing market conditions. Commensurate to this, the Company continues to progress its transition to a longer life, low decline asset base and maintain the strength of its balance sheet. For 2016, Canadian Natural targets its capital program to range from $3.5 billion to $3.9 billion, with overall 2016 production volumes targeted to be 2% less than 2015 annual production volumes, at the midpoint of guidance. The majority of the Company''s expenditure program, approximately $2 billion, is allocated to advancing the completion of Phases 2B and 3 of the Horizon expansion project.
- Overall production in 2016 is targeted to be between 809,000 BOE/d and 868,000 BOE/d, with a product mix of approximately 64% crude oil and NGLs and 36% natural gas.
- Overall crude oil and NGLs production for 2016 is targeted to range from 514,000 bbl/d to 563,000 bbl/d.
- Canadian Natural''s total natural gas production for 2016 is targeted to range from 1,770 MMcf/d to 1,830 MMcf/d.
- For 2016, the Company is committed to further enhancing its effective and efficient operations and is targeting to deliver further operating cost reductions in North America natural gas of approximately 6% and in its crude oil and NGL operating areas of approximately 8%, based on unit rates compared to 2015 levels.
- As reflected by the Company''s 2016 capital budget, Canadian Natural is committed to advancing the completion of the Horizon expansion project, the major component of its transition to longer life, low decline asset base. The start-up of Horizon Phase 2B is targeted in 7 months and will add 45,000 bbl/d of production capacity. Project capital in 2016 is targeted to be approximately $2 billion, the majority of which will be spent over the first nine months of 2016. In 2017, Horizon project capital costs are targeted to decline in 2017 to approximately $1 billion for Phase 3 completion, which will add incremental production volumes of 80,000 bbl/d. At expansion completion, targeted for Q4/17, Canadian Natural targets total Horizon production volumes to average 250,000 bbl/d of SCO with operating costs trending below C$25.00/bbl (less than US$18.00/bbl equivalent).
- Due to Canadian Natural''s large, high quality, and diversified asset base, the Company is able to achieve a strong overall 2016 corporate base production decline rate of approximately 15%, which assumes no development activity.
- Details of Canadian Natural''s Q1/16 production guidance and 2016 annual production and capital guidance can be found on the Company''s website at
CORPORATE UPDATE
Douglas A. Proll, Executive Vice-President, announced his decision to retire from Canadian Natural effective February 1, 2016. Doug joined Canadian Natural in 2001 as Vice-President, Finance. He was appointed Chief Financial Officer and Senior Vice-President, Finance in May 2005. In March 2013, he assumed an Executive Vice-President role. During his tenure at Canadian Natural, Doug made a significant contribution to the growth of the Company. Canadian Natural and the Board would like to thank Doug for his dedicated service and loyalty throughout the years.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate effective and efficient operations, Canadian Natural focuses its activities in core regions where the Company owns a substantial land base and associated infrastructure. Land inventories are maintained to enable continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning and operating associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Furthermore, the Company maintains large project inventories and production diversification among each of the commodities it produces; light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein collectively referred to as "crude oil"), natural gas and NGLs. A large diversified project portfolio enables the effective allocation of capital to higher return opportunities.
Drilling Activity
- As a direct result of the decrease in crude oil and natural gas pricing and other external events, the Company proactively reduced its 2015 drilling programs. Drilling activity, excluding strat/service wells, in Q4/15 consisted of 6 net wells compared to 349 net wells in Q4/14. The Company''s 2015 annual drilling program, excluding strat/service wells, consisted of 140 net wells, an 87% decrease from its 2014 drilling program of 1,117 net wells.
North America Exploration and Production
Crude oil and NGLs - excluding Thermal In Situ Oil Sands
- Annual production volumes of North America crude oil and NGLs averaged 270,147 bbl/d in 2015, a decrease of 5% from 2014 levels. The year over year production decline reflects an 89% reduction in drilling activity from 1,021 net wells in 2014 to 112 net wells in 2015.
- Record North America light crude oil and NGL annual production averaged 91,283 bbl/d in 2015, an increase of 2% from 2014 volumes. The increase in volumes result from strategic acquisitions offset by expected production declines. In 2015, 4 net wells were drilled compared to 101 net wells drilled in 2014. Operating costs were reduced by 14% from 2014 levels.
- Pelican Lake operations averaged 50,818 bbl/d of annual heavy crude oil production, a 1% increase from 2014 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake.
- Primary heavy crude oil annual production averaged 128,046 bbl/d, a decrease of 11%, as expected, from 2014 levels. This production decline reflects the Company''s proactive decision to reduce its primary heavy crude oil drilling program by 88% year over year, and the Company''s prudent decision to shut-in approximately 4,300 bbl/d of primary heavy crude oil production volumes during 2015 as a result of unfavorable economic conditions. In 2015, 108 net wells were drilled compared to 896 net wells in 2014.
Thermal In Situ Oil Sands
- In 2015, thermal in situ annual production achieved record volumes of 129,835 bbl/d, an increase of 20% from 2014 production volume levels. The increase in 2015 production reflects an 8% increase in production volumes from Primrose operations and an increase in Kirby South SAGD production volumes of 94%.
- At Kirby South, production volumes averaged 29,467 bbl/d in 2015 as operations continued its ramp-up to the targeted 40,000 bbl/d of design capacity. In November 2015, production exceeded 41,000 bbl/d which contributed to quarterly volumes of 33,746 bbl/d. The reservoir continues to perform as expected with very good thermal efficiencies.
Natural Gas
- North America natural gas annual production volumes averaged 1,663 MMcf/d for 2015, an increase of 9% from 2014 levels. The increase from 2014 to 2015 levels reflects strategic acquisitions partially offset by third party transportation restrictions in Alberta.
- Operations at Septimus, Canadian Natural''s liquids-rich Montney natural gas play in British Columbia, continue to perform above expectations, with industry leading annual operating costs of $0.20/Mcfe in 2015.
- Canadian Natural''s North America natural gas production volumes continued to be negatively impacted by transportation restrictions on the NOVA pipeline system in Q4/15 by 48 MMcf/d. In addition, the Company shut-in 50 MMcf/d of natural gas volumes related to low natural gas prices, driven largely by third party transmission pipeline restrictions in Northwest Alberta.
- Volumes will continue to be negatively affected in 2016 as a result of TransCanada''s third party maintenance program on the NOVA pipeline system. Minor restrictions on the NOVA pipeline system are expected in Q1/16 and are reflected in Canadian Natural''s Q1/16 total natural gas production guidance.
- North America natural gas annual operating costs were $1.27/Mcf in 2015, an 11% decrease from 2014 levels of $1.42/Mcf, reflecting a continued focus on cost optimization.
International Exploration and Production
- International crude oil production averaged 41,295 bbl/d during 2015, an increase of 39% from 2014 levels. The increase in 2015 production volumes over 2014 levels was primarily due to completion and tie-in of new wells at the Baobab and Espoir fields during the second half of 2015 and the reinstatement of production from both the Banff FPSO and the Tiffany platforms.
- During 2015, at the Espoir field, Cote d''Ivoire, the Company drilled 5 gross producing wells and 1 injector well, adding net production volumes of approximately 6,900 bbl/d to date. In 2016, upon completion of the sixth gross producing well, no additional wells will be drilled in the program. The infill drilling program is currently tracking to below its original sanction costs, and above original sanction production.
- During 2015, at the Baobab field, Cote d''Ivoire, the Company drilled 5 gross wells, adding net production volumes of approximately 13,400 bbl/d to date. In late December, the Baobab field was temporarily shut-in due to a riser failure, delaying first oil on the fifth gross well. After inspection of the riser system, production was reinstated in late January 2016. The drilling program is currently tracking to below its original sanction costs, and above original sanction production.
North America Oil Sands Mining and Upgrading - Horizon
(1) The Company produces diesel for internal use at Horizon. Fourth quarter 2015 SCO production before royalties excludes 2,337 bbl/d of SCO consumed internally as diesel (third quarter 2015 - 2,058 bbl/d; fourth quarter 2014 - 1,288 bbl/d; year ended December 31, 2015 - 2,122 bbl/d; year ended December 31, 2014 - 545 bbl/d).
- Horizon''s strong performance during 2015 resulted in record production volumes of 122,911 bbl/d of SCO, an increase of 11% from 2014 levels. The increase in production volumes reflect safe, steady and reliable operations performed throughout the year offset by the 15 day planned maintenance turnaround completed in Q2/15.
- The Company achieved record annual operating costs at Horizon of $28.61/bbl (US$22.37/bbl equivalent) as a result of safe, steady and reliable operations and a focus on continuous improvement throughout 2015. In Q4/15, Horizon operating costs were $28.56/bbl (US$21.39/bbl equivalent), a 17% reduction from Q4/14 levels.
- 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 original schedule and below budget sanction. Canadian Natural has committed to approximately 85% of the Engineering, Procurement and Construction contracts with over 83% of the construction contracts awarded to date.
- As at December 31, 2015, physical progress of the Horizon project is updated below.
-- Directive 74 includes technological investment and research into tailings management. This project remains on track and is 59% physically complete.
-- Phase 2B is 79% physically complete. This Phase expands the capacity of major components such as gas/oil hydrotreatment, froth treatment and the hydrogen plant. Due to continued strong construction performance on the Horizon expansion, certain components of this project will be tied-in during the mid-2016 turnaround. The start-up of Horizon Phase 2B is targeted in 7 months and will add 45,000 bbl/d of production capacity.
-- Phase 3 is currently on budget and on schedule. This Phase is 74% physically complete, and includes the addition of extraction trains and combined hydrotreater. Phase 3 is targeted to increase production capacity by 80,000 bbl/d in Q4/17 and will result in additional reliability, redundancy and significant operating cost savings for the Horizon project.
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 February 29, 2016. SCO and Condensate March pricing based on current indicative pricing as at February 29, 2016. Monthly USD/CAD exchange rates are based upon the average noon rates for each month. For March, the USD/CAD exchange rate was based upon the forward curve rate based on February 26, 2016 spot rate.
- The 2015 annual average WTI price was US$48.76/bbl as compared to US$92.92/bbl in 2014. Q4/15 WTI pricing averaged US$42.17/bbl as compared to US$73.12/bbl in Q4/14. Volatility in supply and demand factors and geopolitical events remain primary factors in the current WTI and Brent pricing environment. The Organization of the Petroleum Exporting Countries'' ("OPEC") decision not to curtail oil production to offset the excess world supply resulted in a year over year decline in benchmark pricing.
- The WCS differential to WTI averaged US$13.51/bbl or 28% in 2015 compared to US$19.41/bbl or 21% in 2014. In Q4/15, the WCS differential to WTI averaged US$14.48/bbl or 34% as compared to Q4/14 of US$14.26/bbl or 20%. February 2016 and March 2016 indications of the WCS blend differential of US$14.32/bbl or 47% and US$14.50/bbl or 43% respectively, are normal given the trending WTI price curve. Seasonal demand fluctuations, changes in transportation logistics and refinery utilization and shutdowns will continue to be reflected in WCS pricing.
- Canadian Natural contributed approximately 183,000 bbl/d of its heavy crude oil stream to the WCS blend in 2015. The Company remains the largest contributor to the WCS blend, accounting for 49% of the total blend.
- SCO pricing averaged US$48.59/bbl during 2015 compared to US$91.35/bbl in 2014, a 47% decrease. Q4/15 SCO pricing averaged US$42.77/bbl in Q4/15 as compared to US$71.01/bbl in Q4/14 and US$45.78/bbl in Q3/15. Fluctuations in SCO pricing during Q4/15 were a result of changes in WTI benchmark pricing and unplanned industry-wide upgrader outages.
- AECO natural gas pricing in 2015 averaged $2.62/GJ, a decrease of 37% from 2014. Q4/15 AECO pricing averaged $2.51/GJ in Q4/15, decreasing by 34% and 5% from $3.80/GJ and $2.65/GJ in Q4/14 and Q3/15 respectively. In Q4/15, natural gas inventories reached new seasonal record levels as a result of warmer than normal winter temperatures in North America and higher US natural gas production relative to Q3/15 levels. 2015 natural gas pricing reflects lower demand due to warmer than normal winter temperatures in North America and higher than average storage levels relative to 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: .
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 851,901 BOE/d for 2015, with approximately 97% of total production located in G8 countries.
- Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at December 31, 2015, the Company had in place bank credit facilities of $7,481 million, of which $3,495 million was available.
-- During the first two quarters of 2015, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018 and extended its two existing revolving syndicated term credit facilities to mature in June 2019 and June 2020. The result of the extension of the two revolving $2,425 million facilities netted an additional $350 million of liquidity. The Company''s credit facilities all state that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 65%.
-- Subsequent to December 31, 2015, the Company prepaid $250 million of the borrowings from the $1,000 million non-revolving term credit facility and extended the facility to February 2019 from January 2017. In addition the Company entered into a new $125 million non-revolving term credit facility maturing February 2019, which was fully drawn. Borrowings under this facility may be made by way of pricing referenced to Canadian dollar bankers'' acceptances or Canadian prime loans.
- Canadian Natural maintained a strong balance sheet with debt to book capitalization of 38% at December 31, 2015.
- Subsequent to December 31, 2015, Standard & Poor''s Rating Services maintained the Company''s investment grade unsecured long-term and short-term credit ratings and DBRS Limited maintained the Company''s investment grade unsecured long-term credit rating. Additionally, Moody''s Investors Service, Inc. adjusted the Company''s credit ratings within the investment grade debt rating scale.
- Canadian Natural declared a quarterly cash dividend on its common shares of C$0.23 per share payable on April 1, 2016. On an annualized basis, the dividend of C$0.92 per share remains unchanged from the previous annual dividend rate and reflects the Board of Director''s confidence in the Company''s cash flow.
- 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.
YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2015 the Company retained Independent Qualified Reserves Evaluators, Sproule Associates Limited, Sproule International Limited and GLJ Petroleum Consultants Ltd., to evaluate and review all of the Company''s proved and proved plus probable reserves. Sproule evaluated the Company''s North America and International crude oil, bitumen, natural gas and NGL reserves. GLJ evaluated the Company''s Horizon synthetic crude oil reserves. The Evaluators conducted the evaluation and review in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs.
The Reserves Committee of the Company''s Board of Directors has met with and carried out independent due diligence procedures with the Evaluators as to the Company''s reserves. All reserve values are Company Gross unless stated otherwise.
Corporate Total
- Proved crude oil, SCO, bitumen and NGL reserves increased 4% to 4.70 billion barrels. Proved natural gas reserves increased 2% to 6.11 Tcf. Total proved reserves increased 4% to 5.71 billion BOE.
- Proved plus probable crude oil, SCO, bitumen and NGL reserves increased 1% to 7.62 billion barrels. Proved plus probable natural gas reserves increased 5% to 8.51 Tcf. Total proved plus probable reserves increased 2% to 9.04 billion BOE.
- Proved reserve additions and revisions, including acquisitions and dispositions, were 390 million barrels of crude oil, SCO, bitumen and NGL and 735 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio was 165%. The total proved BOE reserve life index is 21.5 years.
- Proved plus probable reserve additions and revisions, including acquisitions and dispositions, were 294 million barrels of crude oil, bitumen, SCO and NGL and 1.0 trillion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 148%. The total proved plus probable BOE reserve life index is 34.0 years.
- Proved undeveloped crude oil, SCO, bitumen and NGL reserves accounted for 25% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 6% of the corporate total proved reserves.
North America Exploration and Production
- Proved crude oil, bitumen and NGL reserves decreased 1% to 2.04 billion barrels. Proved natural gas reserves increased 3% to 6.04 Tcf. Total proved BOE increased slightly from 3.03 billion barrels to 3.05 billion barrels.
- Proved plus probable crude oil, bitumen and NGL reserves increased 2% to 3.56 billion barrels. Proved plus probable natural gas reserves increased 5% to 8.34 Tcf. Total proved plus probable BOE increased 3% to 4.95 billion barrels.
- Proved reserve additions and revisions, including acquisitions and dispositions, were 132 million barrels of crude oil, bitumen and NGL and 776 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio is 106%. The total proved BOE reserve life index in 14.5 years.
- Proved plus probable reserve additions and revisions, including acquisitions and dispositions, were 225 million barrels of crude oil, bitumen and NGL and 1,019 billion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 160%. The total proved plus probable BOE reserve life index is 23.6 years.
North America Oil Sands Mining and Upgrading
- Proved SCO reserves increased 12% to 2.41 billion barrels, primarily due to a revised mine plan allowing mining to a Total Volume : Bitumen In Place ("TV:BIP") of 13 versus 12 in the original plan.
International Exploration and Production
- North Sea proved reserves decreased 24% to 165 million BOE. North Sea proved plus probable reserves decreased 8% to 300 million BOE.
- Offshore Africa proved reserves decreased 9% to 95 million BOE. Offshore Africa proved plus probable reserves decreased 7% to 154 million BOE.
Reserves Notes:
(1) Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests.
(2) Company Net reserves are working interest share after deduction of royalties and including any royalty interests.
(3) BOE values may not calculate due to rounding.
(4) Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserve estimates were provided by Sproule
Associates Limited:
A foreign exchange rate of 0.7500 US$/C$ for 2016, 0.8000 US$/C$ for 2017, 0.8300 US$/C$ for 2018 and 0.8500 US$/C$ after 2018 was used in the 2015 evaluation.
(5) Reserve additions and revisions are comprised of all categories of Company Gross reserve changes, exclusive of production.
(6) Reserve replacement ratio is the Company Gross reserve additions and revisions, for the relevant reserve category, divided by the Company Gross production in the same period.
(7) Reserve Life Index is based on the amount for the relevant reserve category divided by the 2016 proved developed producing production forecast prepared by the Independent Qualified Reserve Evaluators.
(8) Finding, Development and Acquisition (FD&A) costs are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2015 by the sum of total additions and revisions for the relevant reserve category.
(9) FD&A costs including change in Future Development Capital (FDC) are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2015 and net change in FDC from December 31, 2014 to December 31, 2015 by the sum of total additions and revisions for the relevant reserve category. FDC excludes all abandonment and reclamation costs.
(10) A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet of natural gas to one barrel 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.
MANAGEMENT''S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, operating costs, capital expenditures, income tax expenses and other guidance provided throughout this Management''s Discussion and Analysis ("MD&A"), constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the construction and future operations of the North West Redwater bitumen upgrader and refinery, and construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market also constitute forward-looking statements. This forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur.
In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and natural gas liquids ("NGLs") reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company''s products; volatility of and assumptions regarding crude oil and natural gas prices; fluctuations in currency and interest rates; assumptions on which the Company''s current guidance is based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; impact of competition; the Company''s defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its subsidiaries to complete capital programs; the Company''s and its subsidiaries'' ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of the Company''s bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in mining, extracting or upgrading the Company''s bitumen products; availability and cost of financing; the Company''s and its subsidiaries'' success of exploration and development activities and their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the adequacy of the Company''s provision for taxes; and other circumstances affecting revenues and expenses.
The Company''s operations have been, and in the future may be, affected by political developments and by federal, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company''s assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company''s course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management''s estimates or opinions change.
Management''s Discussion and Analysis
This MD&A of the financial condition and results of operations of the Company should be read in conjunction with the unaudited interim consolidated financial statements for the three months and year ended December 31, 2015 and the MD&A and the audited consolidated financial statements for the year ended December 31, 2014.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company''s unaudited interim consolidated financial statements for the period ended December 31, 2015 and this MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. This MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations, cash flow from operations, and adjusted cash production costs. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with IFRS, as an indication of the Company''s performance. The non-GAAP measures adjusted net earnings from operations and cash flow from operations are reconciled to net earnings, as determined in accordance with IFRS, in the "Financial Highlights" section of this MD&A. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization are included in the "Operating Highlights - Oil Sands Mining and Upgrading" section of this MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the "Liquidity and Capital Resources" section of this MD&A.
A Barrel of Oil Equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO.
Production volumes and per unit statistics are presented throughout this MD&A on a "before royalty" or "gross" basis, and realized prices are net of blending costs and exclude the effect of risk management activities. Production on an "after royalty" or "net" basis is also presented for information purposes only.
The following discussion and analysis refers primarily to the Company''s financial results for the three months and year ended December 31, 2015 in relation to the comparable periods in 2014 and the third 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 , and on EDGAR at . This MD&A is dated March 2, 2016.
FINANCIAL HIGHLIGHTS
(1) Adjusted net earnings (loss) 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 (loss) from Operations
(1) The Company''s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company''s balance sheets and periodic changes in the fair value are recognized in net earnings or are capitalized to Oil Sands Mining and Upgrading construction costs.
(2) Derivative financial instruments are recorded at fair value on the Company''s balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil, natural gas and foreign exchange.
(3) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings.
(4) During the fourth quarter of 2014, the Company repaid US$500 million of 1.45% notes and US$350 million of 4.90% notes.
(5) The Company''s investment in the 50% owned North West Redwater Partnership is accounted for using the equity method of accounting. Included in the non-cash loss from investments is the Company''s pro rata share of the North West Redwater Partnership''s accounting loss.
(6) The Company''s investment in PrairieSky Royalty Ltd. ("PrairieSky") has been accounted for at fair value through profit and loss and is remeasured each period with changes in fair value recognized in net earnings.
(7) During the fourth quarter of 2015, the Company recorded a pre-tax gain of $690 million ($627 million after-tax) related to the disposition of a number of North America royalty income assets. During the third quarter of 2015, the Company recorded a pre-tax gain of $49 million ($36 million after-tax) related to the disposition of a number of North America crude oil and natural gas properties. During the fourth quarter of 2014, the Company recorded an after-tax gain of $137 million related to the acquisition of certain producing crude oil and natural gas properties.
(8) In connection with the Company''s notice of withdrawal from Block CI-514 in Cote d''Ivoire, Offshore Africa in the fourth quarter of 2015, the Company derecognized $96 million ($70 million after-tax) of exploration and evaluation assets through depletion, depreciation and amortization expense.
(9) During the second quarter of 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. As a result of this income tax rate increase, the Company''s deferred income tax liability was increased by $579 million. During the first quarter of 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and the Petroleum Revenue Tax ("PRT"), and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company''s deferred income tax liability of $228 million.
Cash Flow from Operations
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
The net loss for the year ended December 31, 2015 was $637 million compared with net earnings of $3,929 million for the year ended December 31, 2014. Net loss for the year ended December 31, 2015 included net after-tax expenses of $900 million compared with net after-tax income of $118 million for the year ended December 31, 2014 related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of a realized foreign exchange gain on the repayment of long term debt, loss from investments, gains on disposition of properties and corporate acquisitions, derecognition of exploration and evaluation assets 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 year ended December 31, 2015 were $263 million compared with $3,811 million for the year ended December 31, 2014.
Net earnings for the fourth quarter of 2015 was $131 million compared with net earnings of $1,198 million for the fourth quarter of 2014 and net loss of $111 million for the third quarter of 2015. Net earnings for the fourth quarter of 2015 included net after-tax income of $180 million compared with net after-tax income of $442 million for the fourth quarter of 2014 and net after-tax expenses of $224 million for the third quarter of 2015 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 the repayment of long term debt, loss from investments, gains on disposition of properties and corporate acquisitions and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities. Excluding these items, the adjusted net loss from operations for the fourth quarter of 2015 was $49 million compared with adjusted net earnings of $756 million for the fourth quarter of 2014 and adjusted net earnings of $113 million for the third quarter of 2015.
The decrease in adjusted net earnings for the year ended December 31, 2015 from the comparable period in 2014 was primarily due to:
- lower crude oil and NGLs netbacks in the Exploration and Production segments;
- lower realized SCO prices;
- lower natural gas netbacks in the North America segment; and
- higher depletion, depreciation and amortization expense;
partially offset by:
- higher crude oil and NGLs, SCO and natural gas sales volumes across all segments;
- higher realized risk
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Datum: 03.03.2016 - 04:00 Uhr
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