cibc 14th annual whistler institutional investor conference · cibc 14th annual whistler...
Post on 21-Aug-2020
6 Views
Preview:
TRANSCRIPT
CIBC 14th Annual Whistler Institutional Investor ConferenceJanuary 20, 2011
Brett GellnerChief Financial Officer
This presentation may contain forward-looking statements, including statements regarding the business and anticipated financial performance of TransAlta Corporation. All forward-looking statements are based on our beliefs and assumptions based on information available at the time the assumption was made. These statements are not guarantees of our future performance and are subject to a number of risks and uncertainties that may cause actual results to differ materially from those contemplated by the forward-looking statements. Some of the factors that could cause such differences include cost of fuels to produce electricity, legislative or regulatory developments, competition, global capital markets activity, changes in prevailing interest rates, currency exchange rates, inflation levels, unanticipated accounting or audit issues with respect to our financial statements or our internal control over financial reporting, plant availability, and general economic conditions in geographic areas where TransAlta Corporation operates. Given these uncertainties, the reader should not place undue reliance on this forward-looking information, which is given as of this date. The material assumptions in making these forward-looking statements are disclosed in our 2009 Annual Report to shareholders and other disclosure documents filed with securities regulators.
Unless otherwise specified, all dollar amounts are expressed in Canadian dollars.
Forward looking statements
2
Value proposition and strategy
Near and longer-term upside potential
Financial strength and capital allocation
3
Outline
AUSTRALIA
UNITED STATES
CANADA
18 MWHydro under development286 MW
Generation Facilities:
Coal-fired under construction
Coal-fired plants
Gas-fired plants
Hydro plants
Wind-powered plants
Geothermal
4,688 MW
1,843 MW
893 MW
1,064 MW
164 MW
Biomass 25 MW
Net generation in operation 8,677 MW
Canada’s largest publically traded wholesale power generator & marketer
Value proposition and strategy
Yield, upside potential, and steady disciplined growth
Low-to-moderate risk profile
Financial strength
Disciplined investment decisions
4
Acquired Vision Quest
Divested Mexico
Renegotiated Sarnia
Retired Wabamun
2008 2009 20102005
Constructed Genesee 3
2000
Transitioned to PRB coal
2006
Acquired CE Gen
2003
AcquiredCanadian
Hydro
2009
Acquired Centralia
2000
Constructed Keephills 3
2011
Strategy: The last 10 years
CoalGasRenewables
$20.96
$32.69
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011e
8,563 MW6,870 MW
Generation gross margin per MWh
produced
73%15%12%
54%
21%
24%
5
Diversified growth & optimization have driven a 55% increase in gross margins
Significantly increased renewable portfolio
0
500
1,000
1,500
2,000
2,500
2000 2005 2010 2011e
Hydro Wind Geothermal Biomass
Renewable Portfolio CapacityMW
Strategy: The last 10 years
6
Diversification and contracting drives growth
Funds from operations have grown despite lower market prices
7
$MM$/MWh
Funds From Operations vs.Weighted Average Price / Merchant MWh Produced
Next 10 years
Continue to drive productivity and lower costsSustain improved operational performance
Unit specific maintenance plans for pending 45 year proposalMaintain options around coal sitesFinalize Centralia transition planParticipate in CCS technology development
Information technology & strategic suppliers drive productivityPrepare transition from PPAs
Implement capital stock transition“Green Coal”
Drive the Base
Drive the Base
Reposition Coal
Reposition Coal
8
Near Term2011 - 2014
Long Term2014 - 2020
Green & DiversifyOur Portfolio
Green & DiversifyOur Portfolio
Deliver on 304 MW of announced growthMaintain development pipeline of over 1,405 MWContinue to target 200 – 300 MW growth / yr
Continue to build multiple options for the futureGas & hydro baseloadSecure natural gas supplyStrong acquisition potential
5%
10%
15%
20%
25%
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
$30
$40
$50
$60
$70
$80
$90
$100
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Actual Forecast
Reserve Margins1
1% load growth
2% load growth
3% load growth
Alberta market
Positives
Alberta Economics: GDP growth to range from 2.1% - 5.5% annually for 2010 – 2020
Oil sands recovery driving load growth
2.5% demand growth per year for the next three years
Challenges
Over 800 MW of new supply in 2011
Weak natural gas prices expected to continue throughout 2011
1 Figures as of January 11, 2011
Alberta Power Prices1$/MWh
Actuals Current Market
+$1 / GJ = ~$8 - $10 / MWh
Forward prices remain soft due to low natural gas prices and capacity additions, long-term fundamentals remain strong, driven by oil sands recovery
9
2 Includes transmission; does not include assumptions around announced facilities, only facilities under construction
20%25%30%35%40%45%50%55%60%
2007 2008 2009 2010 2011 2012 2013 2014
$0
$10
$20
$30
$40
$50
$60
$70
2006 2007 2008 2009 2010 2011 2012 2013 2014
PacNW market
Positives
Demand destruction slowing down; -1.8% for 2010 versus -3.2% last year
1.9% demand growth per year for the next three years due to expectations of a modest economic recovery
Challenges
Economic recovery losing momentum in recent months
Weak natural gas prices expected to continue throughout 2011
Continued growth in renewables expected over the next few years
+$1 / MMBtu = ~$7 - $9 / MWh
1 Figures as of January 11, 2011
10
Improvements in demand; forward price recovery driven by natural gas
Reserve Margins1
PacNW Power Prices1US$/MWh
Actuals Current Market
Actual Forecast1% load growth
2% load growth
3% load growth
0
500
1,000
1,500
2,000
2,500
3,000
3,500
2010 2011 2012 2013
Contracted To be contracted Open
0
500
1,000
1,500
2,000
2,500
3,000
3,500
2010 2011 2012 2013
Contracted To be contracted Open
$0
$50
$100
$150
$200
$250
1 2 3 4 5
Merchant Portfolio Contractedness Avg. Incremental EBITDA From Higher Prices (2011 – 2014)2
$MM
1Based on a 10% ROCE, $1,500 – $3,000 per KW and a 30 year depreciation2 Relative to a base of $50/MWh in Alberta and $35/MWh in the PacNW
$75$60
$70$55
$65$50
$60$45
$55$40
AlbertaPacNW
Significant upside to price plus growth in the medium-term
11
Merchant MWs
Hedging strategy provides leverage to power price recovery
Alberta1: $60 - $65 $65 - $70 $65 - $70 $60 - $65PacNW1: $50 - $55 $55 - $60 $55 - $60 $45 - $50
20102011
2012 2013
90% target Capacity adjustments
Contracted To be contracted Open
At a 10% ROCE, 200 MW growth can add another
$40 - $80 million in additional EBITDA1
Merchant MWs
Significant upside potential
$-
$250
$500
$750
$1,000
$1,250
$1,500
$1,750
$60 $70 $80 $90 $100 $110 $120
Est.EBIT $MM
Estimated Incremental EBITDA in 2021$750 - $1,250 M 2
$750$1,000
$1,250
Alberta Power Prices 2021 ($/MWh)
2 Includes Sundance units 3 – 6, Keephills, Sheerness, and Alberta Hydro facilities
12
End of PPAs will provide significant EBITDA upside as production reverts back to TransAlta
1 Minimum power prices required for new NGCC facility
1
1 Excludes upside from incremental growth, replacement opportunities and higher prices between 2010 and 20212 Based on 45 year coal-life; and includes Sundance units 2 – 6, Keephills, Sheerness, and Alberta Hydro
Excellent long-term potential from PPA facilities
13
$-
$2,500
2010 20212010 2021
TA Base1
Value
Post PPA Value
$MM Potential EBITDA
Price
($/MWh)$60
$120
Upside
$2.1 B
$8.5 B
Cumulative Potential Upside from PPA Expiry(2018 – 2029)1,2
Investment Opportunities (TransAlta Fleet Only)
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
2011 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031
TransAlta coal Replacement opportunity TA AB Portfolio growth
TransAlta AB Portfolio Growth
Replacement Opportunity*
TransAlta Coal
MW
Opportunity
1 Based on 45 year coal-life and $1,800 - $2,800 per KW
5,400 MW at Market Prices
$10 - $15 BInvestment Opportunity1
14
Canada’s 45 year plan provides significant future investment opportunities in Alberta alone
Captures the benefit of our significant tax pools and attractive tax treatment of renewablesAdds back non-cash accounting charges (e.g. dep`n) which can vary between companiesLong-term cash flow analysis captures the significant value from PPA expiry and reinvestment opportunities
$-$100$200$300$400$500$600$700$800$900
2005 2006 2007 2008 2009 2010e*
Net Earnings FFO
FFO Significantly Higher Than Earnings
$MM
1 Based on analyst consensus estimate for net earnings
Cash flow / funds from operations
2010e1
15
Cash flow accounts for tax pool benefits, adds back non-cash accounting charges, and captures future value of PPA expiry
0.0
0.5
1.0
1.5
2.0
2.5
3.0
2006 2007 2008 2009 2010e$0
$100$200$300$400$500$600$700$800$900
$1,000
2006 2007 2008 2009 2010e
Strong near-term cash flows
Expecting $800 - $900 M in funds from operations for 2011
Dividend Coverage2.0 – 2.5x$MM
Funds from Operations
Sustaining capex Free cash flow Dividends
$800 - $900 M FFO range
16
Capital allocation plan
We remain disciplined in how we manage our balance sheet and allocate capital
2011 - 2013
Funds from operationsSustaining capexDividendsDRASPNCITotal
Balance sheet enhancement Growth
17
$ 2.8$ (1.3)$ (0.8)$ 0.2$ (0.2)$ 0.7
($B)
Appendix
18
Performance goals
Annual Metrics
4.6X
21.2%
56.7%
Annual Metric
$230 MM
$0.17
$7.51/MWh
Annual Metric
91.0%
Q3 2010
Annual Metrics
5.8X
23.6%
50.1%
Annual Metric
$194 MM
$0.34
$7.78/MWh
Annual Metric
83.9%
Q3 2009
Decreased due to low pricing in core markets, lower Energy Trading gross margins, slightly higher OM&A costs in the quarter
>10%/yrComparable EPS Grow Earnings and Cash Flow
TBD$295 - $340Sustaining CapexMake Sustaining Capex Predictable
Maintained strong balance sheet, financial ratios and ample liquidity
4 - 5X
20 - 25%
55 - 60%
Cash Flow to InterestCash Flow to DebtDebt to Invested Capital
Maintain InvestmentGrade Ratings
TBD
>10%/yr>10%/yr>10%/yr
Comparable ROCETSRIRR
Deliver Long-termShareowner Value
Higher operating cash flow due to favorable changes in working capital
Decreased year-over-year due to less major maintenance activities in 2010 and increased capacity
TBD
Increased availability due to lower planned and unplanned outages at our Sundance plant, lower planned outages at our Mississauga and Windsor facilities, and lower unplanned outages at Centralia
2010 Goals
$850 – 950* MMOperating Cash Flow
90%AvailabilityAchieve top decile operations
1.0 by 2015Injury Frequency RateImprove Safety
Offset InflationOM&A/installed MWhEnhanceProductivity
Measures ReviewFinancial ratios
*Estimate revised to $800 - $900 million
Performance Goals
19
$(196)$74$12$107Free cash flow (deficiency)
$1.69$2.28$0.98$1.05Cash flow from operating activities per share
$595$664$241$233EBITDA
$463$558$178$184Funds from operations
12,742
91.0
$0.29
$230
$0.17
$0.17
$38
$38
$98
$380
$700
Q3 2010
11,610
83.9
$0.29
$194
$0.34
$0.34
$66
$66
$120
$380
$666
Q3 2009
33,439
84.4
$0.87
$334
$0.52
$0.49
$102
$97
$219
$1,107
$2,007
YTD2009
35,857
88.1
$0.87
$502
$0.71
$0.57
$156
$126
$287
$1,137
$2,008
YTD2010
Availability (%)
Comparable earnings per share
Basic and diluted earnings per share
Comparable earnings
Operating income
Production (GWh)
Cash dividends declared per share
Cash flow from operating activities
Net earnings
Gross margin
Revenue
Results ($M)
Q3 2010 - Highlights
20
(6)---Settlement of commercial issue, net of tax
$0.34
198
$66
-
-
$66
Q3 2009
$0.17
220
$38
-
-
$38
Q3 2010
1-Change in life of Centralia parts, net of tax
$0.49
198
$97
-
$102
YTD2009
220Weighted average common shares outstanding in the period
$0.57
$126
(30)
$156
YTD2010
Earnings on a comparable basis
Earnings on a comparable basis per share
Income tax recovery related to the resolution of certain outstanding tax matters
Net earnings
Results ($M)
Comparable earnings
Q3 2010
21
Net earnings
$38
(2)
12
(5)
(13)
(15)
(5)
(4)
4
$66
Q3 2010
$156Net earnings, 2010
(12)Other
15Decrease in income tax expense / increase in income tax recovery
7(Increase) decrease in non-controlling interest
(28)
(2)
44
(20)
50
$102
YTD 2010
Decrease in Energy Trading gross margins
(Increase) decrease in OM&A costs
Increase in depreciation expense
Increase in net interest expense
Increase in Generation gross margins
Net earnings, 2009
Q3 2010
22
$12
-
(1)
(7)
(58)
(116)
$194
Q32009
$74
-
(13)
(44)
(169)
(202)
$502
YTD2010
$(196)
(8)
(19)
(40)
(169)
(294)
$334
YTD2009
$107Free cash flow (deficiency)
-Other income
-Non-recourse debt repayments
(15)Distribution to subsidiaries’ non-controlling interests
(49)Cash dividends paid on common shares
(59)Sustaining capital expenditures
Add (Deduct):
$230Cash flow from operating activities
Q32010($M)
Free cash flow
23
$0
$200
$400
$600
$800
$1,000
2010 2011 2012 2013 2014 2015 2016 2017 2018 ThereafterCDN MTN's US MTN's
(CDN $M)
1 Based on Sept. 30, 2010 FX rate of $1.03 CAD/US
Minimal debt refinancing over the short-term provides ample financial flexibility
Debt profile
24
1
$0.0
$0.5
$1.0
$1.5
$2.0
$2.5
Credit Lines Utilized Credit Lines Available
35%
40%
45%
50%
55%
60%
2006 2007 2008 2009 Q32010
0%5%
10%15%20%25%30%35%
2006 2007 2008 2009 Q32010
012345678
2006 2007 2008 2009 Q32010
Execute our plan while maintaining long-term financial strength and stability
Range:4 - 5x
Cash flow to interest
Range:55 - 60%
Debt to capital
Range:20 - 25%
Cash flow to debt
Committed credit lines
Sept. 30, 2009 Sept. 30, 2010
$B
Maintaining investment grade ratios
25
Other
$30 - 50$20 - 30
$55 - 80$5 - 10$10 - 20
Repowering / Life ExtensionProductivity
$35 -45
$190 - 210
$115 - 130
$340 - 385
2013e
$40 - 50
$280 - 300
$115 - 130
$435 - 480
2012e
$25 - 30Mine Capital
$210 - 230Major Maintenance
$120 - 135
$355 - 395
2011e
Routine Capital
Sustaining
($M)
Sustaining capital
26
2011 - 2013 Sustaining capital plan1
1 Based on IFRS
630 - 640
$75 - 80
Natural Gas and Renewables
1,850 – 1,860
$135 - 150
Coal
2,480 – 2,500GWh lost
$210 - 230
Total
Capitalized
($M)
2011 Major maintenance plan1
Major maintenance
27
1 Based on IFRS
Tracking
Merchant
Q4 20124
15%+
$68 MM
46 MW (23 MW each)
Efficiency Uprates
Alberta
Keephills 1 and 2 Uprates
Tracking
Merchant
Q4 2012
15%+
$27 MM
15 MW
Efficiency Uprate
Alberta
Sundance 3 Uprate
10%+10%+Unlevered after tax IRR
AlbertaBritish ColumbiaLocation
Tracking
Merchant
Q2 2011
$988 MM 3
225 MW 1
Supercritical Coal
Keephills 3
Tracking
LTC
Q1 2011
$48 MM 2
18 MW
Hydro
Bone Creek
On time / On budget
Contract Status
Commercial Operations Date
Total Project Cost
Size
Type
Projects
1 450 MW gross size2 Bone Creek’s capital spend prior to the acquisition was $23 MM which does not form part of our total project cost3 Keephills 3 capital spend increased from $888 MM to $988 MM and its COD was revised from Q1 2011 to Q2 20114 Keephills unit 1 uprate has been moved to 2012
Executing on our growth strategy
28
TransAlta’s growth investments deliver long-term sustainable cash flow and earnings growth
LOCATION PROJECT CAPACITY FUEL TYPE RESOURCE & TURBINE CAPEX RANGE PPA / MW SITE CONTROL Applied Secured SECURED $ MM LTC
Quebec New Richmond** 66 Wind $180 - $210 PPA/LTCQuebec St. Valentin** 50 Wind $150 - $180 PPA/LTCSaskatchewan Mistahay Utin 175 Wind TBD $450 - $500 PPA/LTCSaskatchewan Willow Bunch** 175 Wind TBD $450 - $500 PPA/LTCCalifornia Black Rock 1-3 87* Geothermal In Progress $400 - $500 PPA/LTCAlberta Sundance 7 700 Gas-fired TBD TBD $1,000 - $1,500 MerchantAlberta Dunvegan** 100 Hydro $500 - $700 MerchantBritish Columbia Clemina Creek** 11 Hydro $30 - $40 PPA/LTCBritish Columbia Serpentine Creek** 10 Hydro $30 - $40 PPA/LTCBritish Columbia English Creek** 5 Hydro $12 - $20 PPA/LTCOntario Royal Road** 18 Wind $35 - $45 PPA/LTCOntario Yellow Falls** 8* Hydro $30 - $45 PPA/LTC
TOTAL MW : 1,405 TOTAL COST: $3.3 B - $4.3 B
TBD
TBDTBD
2012
20132013/14
TBDTBD
TBD
Projects in Advanced DevelopmentTARGET
COMMERCIALOPERATION DATE
ENVIRONMENTAL AND PERMITS
2015
2013
2012
Advanced development pipeline
* TransAlta’s ownership** Based on initial estimates of Canadian Hydro
29
$1353$105 - 11569Ardenville
$1002$80 - 8554Kent Hills 2
$353$195 - 215189
$1181$10 - 1566Summerview 2
MW 2012e Total2010 2011eCompleted
$686$20 – 30$25 - 35$5 - 1546KI & K2 uprates
$27$10 - 20$10 - 15$0 - 515Sun 3 uprate
304
225
18
MW
$484$50 - 55Bone Creek
$9885$20 - 30$225 - 245Keephills 3
$30 - 50
2012e
$1.1B
Total
$280 - 320
2010e
$55 - 80
2011e
Total
In Progress
1 Sunmmerview 2 capital spend prior to 2010 was $106 M2 Kent Hills 2 capital spend prior to 2010 was $18 M3 Ardenville capital spend prior to 2010 was $27 M4 Bone Creek capital spend prior to the acquisition was $23M which does not form part of our total project cost. Spend prior to 2010 was $4 M.5 Keephills 3 capital spend prior to 2010 was $707M6 K1 & K2 uprates spend prior to 2010 was $2 M
Growth capital outlook2011 - 2012
30
All projects tracking on time and on budget
top related