public serviceenterprise group MLPres

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public serviceenterprise group MLPres

  1. 1. Public Service Enterprise Group Merrill Lynch 2008 Power & Gas Leaders Conference New York City September 23, 2008
  2. 2. Forward-Looking Statement Readers are cautioned that statements contained in this presentation about our and our subsidiaries' future performance, including future revenues, earnings, strategies, prospects and all other statements that are not purely historical, are forward-looking statements for purposes of the safe harbor provisions under The Private Securities Litigation Reform Act of 1995. Although we believe that our expectations are based on reasonable assumptions, we can give no assurance they will be achieved. The results or events predicted in these statements may differ materially from actual results or events. Factors which could cause results or events to differ from current expectations include, but are not limited to: • Adverse changes in energy industry, policies and regulation, including market rules that may adversely affect our operating results. • Any inability of our energy transmission and distribution businesses to obtain adequate and timely rate relief and/or regulatory approvals from federal and/or state regulators. • Changes in federal and/or state environmental regulations that could increase our costs or limit operations of our generating units. • Changes in nuclear regulation and/or developments in the nuclear power industry generally, that could limit operations of our nuclear generating units. • Actions or activities at one of our nuclear units that might adversely affect our ability to continue to operate that unit or other units at the same site. • Any inability to balance successfully our energy obligations, available supply and trading risks. • Any deterioration in our credit quality. • Any inability to realize anticipated tax benefits or retain tax credits. • Increases in the cost of or interruption in the supply of fuel and other commodities necessary to the operation of our generating units. • Delays or cost escalations in our construction and development activities. • Adverse capital market performance of our decommissioning and defined benefit plan trust funds. • Changes in technology and/or increased customer conservation. For further information, please refer to our Annual Report on Form 10-K, including Item 1A. Risk Factors, and subsequent reports on Form 10-Q and Form 8-K filed with the Securities and Exchange Commission. These documents address in further detail our business, industry issues and other factors that could cause actual results to differ materially from those indicated in this presentation. In addition, any forward-looking statements included herein represent our estimates only as of today and should not be relied upon as representing our estimates as of any subsequent date. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if our estimates change, unless otherwise required by applicable securities laws. 2
  3. 3. GAAP Disclaimer PSEG presents Operating Earnings in addition to its Net Income reported in accordance with accounting principles generally accepted in the United States (GAAP). Operating Earnings is a non-GAAP financial measure that differs from Net Income because it excludes the impact of the sale of certain non-core domestic and international assets, costs stemming from the terminated merger agreement with Exelon Corporation and material impairments and lease-transaction-related charges. PSEG presents Operating Earnings because management believes that it is appropriate for investors to consider results excluding these items in addition to the results reported in accordance with GAAP. PSEG believes that the non- GAAP financial measure of Operating Earnings provides a consistent and comparable measure of performance of its businesses to help shareholders understand performance trends. This information is not intended to be viewed as an alternative to GAAP information. The last slide in this presentation includes a list of items excluded from Net Income to reconcile to Operating Earnings, with a reference to that slide included on each of the slides where the non-GAAP information appears. 3
  4. 4. What’s new since early September 2008 . . . Additional / Updated Data: • Slides 6, 9, 24, 26, 28 - PSEG Power capacity figures updated for recent uprates at Hope Creek (150MW) and Salem 2 (23MW) • Slide 15 – Pictorial view of historical and forecasted Spark and Dark Spreads • Slide 18 – Open EBITDA: incremental data on earnings sensitivities • Slide 19 – PSEG commentary on growth • Slide 20 – PSEG Liquidity • Slide 21 – PSEG Valuation • Slide 50 – PSEG Resources Earnings Profile 4
  5. 5. PSEG Strategic Overview Ralph Izzo Chairman, President and Chief Executive Officer
  6. 6. Our platform … Stable electric and gas Redeployment of capital Major electric generation distribution and through the sale of company with 13,487 transmission company international assets. MW* of base-load, rated top quartile for Focused on managing intermediate and load reliability, providing lease portfolio and following capability service in mature potential investment in operating in attractive service territory in New renewables. markets in the Northeast Jersey. with operating control of additional 2,000 MW of capacity in Texas. 2007 Operating $949M** $376M** $115M** Earnings: 2008 Guidance: $1,040M - $1,140M $350M – $370M $45M – $60M … provides earnings stability, multiple growth opportunities and substantial cash flow. 6 * Includes recent uprates at Hope Creek (150MW) and Salem 2 (23MW) ** See page 61 for Items excluded from Net Income to reconcile to Operating Earnings
  7. 7. Our focus is to maximize benefits from existing assets … Regulatory and Operational Growth with Market Environment Excellence Manageable Risk Support Maintain Produce and competitive Meet strong deliver safe, market shareholder balance reliable, structures objectives for sheet to economic through growth with support and clean strong reasonable investment energy. regulatory risk. goals. relationships. … and build a substantial platform for ongoing growth. 7
  8. 8. Major influences on business environment remain: Infrastructure Climate Change Capacity Needs Requirements • PSEG Power’s base-load • Significant new nuclear assets well transmission capital • New peaking capacity in situated in carbon program to improve CT constrained environment reliability • Potential to leverage • PSE&G pursuing • Capital investment in existing brownfield investments in energy coal fleet to meet sites; potential for new efficiency and environmental nuclear renewables requirements maintains critical infrastructure and • Compressed Air Energy expands capability Storage (CAES) PSEG’s assets are well positioned to meet the needs of customers and shareholders in a challenging environment. 8
  9. 9. Right set of assets in right markets … Fuel Diversity – 2008 • Low-cost portfolio Total MW: 13,487* • Strong cash generator Oil Nuclear 8% • Regional focus in competitive, 27 % Pumped liquid markets Storage 18% 1% 46 % • Assets favorably located Coal Gas – Many units east of PJM constraints – Southern NEPOOL/ Connecticut Energy Produced - 2007 – Near customers/load centers Total GWh: 53,200 • 80% of fossil capacity has dual fuel Nuclear capabilities 54% Pumped • Integrated generation and portfolio Storage 1% 19% management optimizes asset- Gas 25% based revenues Oil 1% Coal … with numerous competitive advantages over the long-term. 9 * Includes recent uprates at Hope Creek (150MW) and Salem 2 (23MW)
  10. 10. Power’s assets along the dispatch curve … Nuclear National Park Coal Sewaren 6 Dispatch Cost ($/MWh) Mercer 3 Kearny 10-11 Combined Cycle Burlington 8-9-11 Steam Edison 1-2-3 GT Peaking Essex 10-11-12 New Haven Linden 5-8 / Essex 9 Bergen 1 Burlington 12 / Kearny 12 Linden 1,2 Yards Keystone Sewaren 1-4 Creek Conemaugh Hudson 1 Peach BEC Hudson 2 Bridgeport Bottom Hope Bergen 2 Salem Creek Mercer1, 2 Illustrative Baseload units Load following units Peaking units Energy Revenue X X X Capacity Revenue X X X Ancillary Revenue X X Dual Fuel X X Nuclear CF 90% to 92% Coal CF 85% to 90% 50% to 70% Combined Cycle CF 30% to 50% Peaking CF 2% to 10% … position the company to serve full requirement load contracts. 10
  11. 11. Power’s fleet diversity and location ... Market Perspective – BGS Auction Results Increase in Full Requirements Component Due to: Increased Congestion (East/West Basis) Full Requirements $111.50 Increase in Capacity Markets/RPM $102.51 $98.88 • Ancillary services Volatility in Market Increases Risk Premium • Capacity • Congestion ~ $43 • Load shape ~ $32 ~ $41 $65.41 • RECs • Transmission $55.59 $55.05 • Risk premium ~ $21 ~ $18 ~ $21 Round the Clock $68 - $71 $58-$60 $67 - $70 PJM West $44 - $46 $36 - $37 $33 - $34 Forward Energy Price 2003 2004 2005 2006 2007 2008 … has enabled successful participation in each BGS auction and cushioned customer impacts. 11 * BGS prices reflect PSE&G Zone
  12. 12. Power’s hedging program provides near-term stability from market volatility … Contracted Energy 100% $80 Power has contracted for a nuclear output % of coal and % sold Price 75% $70 considerable (left (right scale) $/MWh scale) percentage of its % 50% $60 sold output over the (left next three years scale) 25% $50 at increasing prices. 0% $40 Estimated EPS 2008 2009 2010 2011 impact of $10/MWh PJM West around the $0.01 - $0.02 $0.05 - $0.15 $0.15 - $0.45 $0.30 - $0.70 clock price change* Contracted Capacity Contracted Capacity 100% The pricing for $150 most of Power’s % of capacity 75% $/MW-day Price capacity has been Price (right $100 (right fixed through May % 50% scale) scale) sold % sold 2012, with the (left (left $50 completion of scale) 25% scale) auctions in PJM Estimated EPS and NE. 0% $0 impact of $30/MW- 2008 2009 2010 2011 day capacity price $0.00 - $0.01 $0.00 - $0.01 $0.00 - $0.01 $0.05 - $0.15 change* … while remaining open to long-term market forces. 12 * As of July 2008; Assuming normal market commodity correlations
  13. 13. Digesting power market volatility • PJM market - slight tightening in reserve margins forecast over next 5 years; FERC remains supportive of RPM. • Financial market volatility has affected liquidity in commodity markets, particularly in out years. • Power prices not responding to change in price of coal. – Divergence in price of coal and power not sustainable over long term. • Recent vacating of CAIR has depressed forward power prices, but a replacement rule has been proposed. • PSEG Power, in conjunction with PSEG Energy Resources and Trade, carefully screening credit capability of trading partners. 13
  14. 14. Coal and natural gas, despite recent decline in prices ... Central Appalachian Coal ($/Ton) Natural Gas Henry Hub ($/MMbtu) $130 $12.0 $11.5 $120 $11.0 $110 $10.5 $100 $10.0 $90 $9.5 $80 $9.0 $70 $8.5 $60 $8.0 $50 $7.5 $7.0 $40 7 8 8 7 07 7 08 07 08 7 8 7 8 7 7 8 8 07 08 7 07 08 l-0 l-0 -0 -0 -0 -0 -0 -0 -0 -0 -0 l-0 -0 l-0 p- p- n- n- ov ar ar ay ay p- p- Ju Ju n- n- ay ay ar ov ar Se Se Ja Ja Ju Ju M M N M M Se Se Ja Ja M M M M N 2009 2010 2011 2009 2010 2011 On Peak Heat Rate Expansion (MWh/MMBTU) Electric PJM Western Hub RTC Price ($/MWh) $95 10.5 $90 $85 10.0 $80 $75 9.5 $70 $65 9.0 $60 $55 8.5 7 8 7 8 8 8 7 7 7 7 8 8 07 08 7 7 07 08 07 08 7 8 -0 -0 -0 -0 -0 -0 l-0 -0 l-0 -0 -0 l-0 -0 l-0 -0 -0 p- p- n- n- n- n- ay ay ar ar ov ay ay ar ar v p p Ju Ju Ju Ju Se Se Ja Ja No Ja Ja Se Se M M M M M M N M M 2009 2010 2011 2009 2010 2011 … are trading in line with prices at the start of 2008. 14 Forward prices as of 9/04/08
  15. 15. Natural gas spark spreads are trading in line with historical averages. Western Hub Spark Spread (On-Peak - Henry Hub * 7.5 Heat Rate) $50.0 Western Hub Spark Spread $40.0 $30.0 $20.0 $10.0 $0.0 ($10.0) 2005 2006 2007 2008 20 9 10 11 0 20 20 Western Hub Dark Spread (RTC - Central Appalachian Coal * 10 Heat Rate) $60 Western Hub Dark Spread $50 $40 $30 $20 $10 20 9 10 11 2005 2006 2007 2008 0 20 20 Annual Average Historical Monthly Data Forecast Dark spreads are low and not supportive of fundamental operations. 15
  16. 16. Looking to the future, Power’s fleet has a low carbon profile … … which is well positioned for virtually any form of carbon restrictions. 16 Sources: Preliminary 2007 EIA 906920 (generation & emission); eGRID 2006 (PJM Interconnection Data); EIA 2006 (ownership)
  17. 17. The implementation of carbon legislation is one means of addressing the critical issue of global warming … By Fuel Type Coal CTs CC Carbon tons/MWh 1.0 0.6 0.4 PSEG Power Generation by Fuel Price ($/MWh) 2007 Total GWh: 53,200* @$10/ton $10.0 $6.0 $4.0 Nuclear @$20/ton $20.0 $12.0 $8.0 @$30/ton $30.0 $18.0 $12.0 54% Pumped Dispatch curve implication @ $20/ton** Storage On margin $/MWh Impact 1% 19% (Illustrative) 25% ($/MWh) Gas Coal 50% $20.0 $10.0 Coal CTs 10% $12.0 $1.2 Oil 1% Gas CC 40% $8.0 $3.2 Nuclear 0% $0.0 $0.0 Total 100% $14.4 … and will put additional upward pressure on energy prices. * Excludes 2,000MW of combined cycle generation in Texas under PSEG Power’s operating control. 17 ** For illustrative purposes – potential impact of CO2 on power prices with current dispatch; $20/ton improves EBITDA by $400 million/year; relationship of carbon price and EBITDA is not linear.
  18. 18. Power’s open EBITDA is approximately $2.6 - $2.8 billion … $3.0 EBITDA Assumption Sensitivity Impact $2.5 Capacity ~ $64 - $68/KW-yr $10/KW-yr ~ $120M ~ $74 - $78/MWh Energy ~ $40M $1/MWh (PJM-West) Fuel Gas ~$9.50 to $10.00/MB $1 spark ~ $12M $2.0 Coal ~ $4.50 to $5.50/MB $1 dark ~ $15M* $ Billions O&M ~ $1.0B – $1.05B $1.5 2008 Forecasted EBITDA $2.05B - $2.25B $1.0 … which will vary depending upon market drivers. 18 * PSEG Power consumes 150 MMBtu of coal annually; $0.25/MMBtu = $25MM Net Income Note: Open EBITDA reflects unhedged results of Power at market prices shown above. Energy EBITDA impact is based on coal and nuclear generation.
  19. 19. Markets, assets and use of cash flow support earnings growth through 2010. + 8 - 9% $3.05 - $3.35 $2.80 - $3.05 $2.71 $1.73 2008 2009 2006 Operating 2007 Operating 2010E Guidance Guidance Earnings* Earnings* The recent decline in market pricing – if sustained over the long-term – would put PSEG’s growth rate at the low end of its forecast range. 19 * See page 61 for Items excluded from Net Income to reconcile to Operating Earnings
  20. 20. PSEG Liquidity as of September 15, 2008 Expiration Total Primary Usage at Available Company Facility Date Facility Purpose 9/15/2008 9/15/2008 1 CP Support/Funding/LCs 5-year Credit Facility Dec-12 $1,047 $0 $1,047 PSEG CP Support/Funding Bilateral Credit Facility Jun-09 $100 $0 $100 Funding Uncommitted Bilateral Agreement N/A N/A 0 N/A 2 CP Support/Funding/LCs 5-year Credit Facility Jun-12 628 75 553 PSE&G Funding Uncommitted Bilateral Agreement N/A N/A 0 N/A Funding/LCs 5-year Credit Facility Jun-10 150 21 129 Energy Holdings 3 Funding/LCs 5-Year Credit Facility Dec-12 1,675 220 1,455 Power Funding/LCs Bilateral Credit Facility Jun-09 100 0 100 Funding/LCs Bilateral Credit Facility Mar-09 150 52 98 Funding/LCs Bilateral Credit Facility Mar-10 100 28 72 Total $3,950 $300 $3,554 PSE&G ST Investment $27 PSEG ST Investment $171 Total Liquidity Available $3,752 Total non-PSE&G Liquidity $3,172 1 PSEG Facility reduced by $47 million in 2012 2 PSE&G Facility reduced by $28 million in 2012 3 Pow er Facility reduced by $75 million in 2012 20
  21. 21. PSEG’s current stock price… PSE&G Energy Holdings 2008 Earnings Guidance $350M - $370M Book Equity Value/Share(1) $1.96 Indicative 2008 P/E Multiple 12.5x – 13.5x Resulting Value/Share $8.60 - $9.80/Share PSEG Power Stock Price as of 9/19/08 (per share) $36.00 Less Indicative Value of PSE&G, Energy Holdings $10.56 - $11.76 Implied PSEG Power Value (per share) $24.24 - $25.44 Implied Power Enterprise Value $15.2B - $15.8B Implied EV as a Multiple of: 2008 EBITDA 6.8x – 7.7x Open EBITDA 5.4x – 6.1x Plus $10 Carbon 5.1x – 5.6x Plus $20 Carbon 4.8x – 5.3x (1) Reflects 2Q 2008 charge ($0.96 per share) for potential tax liability at Resources; excludes incremental value of Texas generating assets (2,000 MW of combined cycle capacity) … implies a low valuation for PSEG Power. 21
  22. 22. APPENDIX
  23. 23. PSEG Power
  24. 24. Our five unit nuclear fleet with recent uprates … Hope Creek • Operated by PSEG Nuclear Salem Units 1 and 2 • PSEG Ownership: 100% • Operated by PSEG Nuclear • Technology: Boiling Water Reactor • Ownership: PSEG - 57%, Exelon – 43% Peach Bottom Units 2 and 3 • Total Capacity: ~1,211MW • Technology: • Owned Capacity: ~1,211MW* Pressurized Water Reactor • Operated by Exelon • License Expiration: 2026 • Total Capacity: ~2,345MW • PSEG Ownership: 50% • Owned Capacity: ~1,346MW* • Technology: • License Expiration: 2016 and 2020 Boiling Water Reactor • Total Capacity: ~2,224MW • Owned Capacity: ~1,112MW • License Expiration: 2033 and 2034 … is a critical element of Power’s success. 24 * Includes recent uprates at Hope Creek (150MW) and Salem 2 (23MW)
  25. 25. Fossil operations contribute to earnings … Total Fossil Output A Diverse 9,818 MW Fleet (MW) (GWh) Coal 2,348 30,000 Combined Cycle 3,156 Steam / Peaking 4,314 25,000 Right Assets – Right Location 20,000 • Fuel diversity • Technical diversity 15,000 ` • Near load centers 10,000 Operation of 2,000 MW Texas Portfolio 5,000 • Shared best practices • Leverage scale 0 2004 2005 2006 2007 … through a low-cost portfolio in which the majority of the output is from coal facilities. 25
  26. 26. Through our ongoing focus on operational excellence … Total Power Output (GWh) 60,000 A Diverse 13,487 MW Fleet* 50,000 Nuclear 3,669 40,000 Coal 2,348 GWh Combined Cycle 3,156 30,000 Peaking / Steam 4,314 20,000 10,000 Strong Performance 0 • Continued growth in output 2004 2005 2006 2007 • Improved fleet performance Year Nuclear Coal CC Peaking/Steam … we are expanding the output of our existing fleet. 26 * Includes recent uprates at Hope Creek (150MW) and Salem 2 (23MW)
  27. 27. Power’s eastern coal plants are in the right areas … System Interface Coal Units Capacity (MW) Bridgeport Harbor 3 3 Bridgeport Harbor Hudson 2 558 Mercer 1&2 648 Hudson 2 Hudson 2 Bridgeport 372 Mercer1 & 2 Mercer 1&2 Total 1,578 Power’s New Jersey coal units are Power is also making considerable mid-merit, with capacity factors investments beyond the pollution averaging 50% to 60%. control facilities for its coal assets. … and after capital investments, anticipate increased capacity factors. 27
  28. 28. Through the new capacity constructs, and repricing at market prices … Power’s capacity is located in three Northeast markets. NE NY Total Capacity 13,487MW* (~ 1,000 - 1,500 MW under RMR) PJM The RPM Auction to date has provided strong price signals in PJM. Delivery Year ($MW/Day) 2009 2010 / 2011 2007 / 2008 2008 / 2009 2009 / 2010 2010 2011 / 2012 Zones $49-51/KW-yr $56-60/KW-yr Eastern MAAC** $197.67 $148.80 $191.32 $174.29 $110.00 $191.32 (a) MAAC --- --- $174.29 $110.00 Rest of Pool $40.80 $111.92 $102.04 $174.29 $110.00 ** Majority of Power’s assets (a) – includes APS … Power expects to maintain strong margins. 28 * Includes recent uprates at Hope Creek (150MW) and Salem 2 (23MW)
  29. 29. While nuclear fuel has recently been volatile… Historical and Contracted Nuclear Fuel Cost $10 $8 $6 $/MWh $4 $2 $0 2004 2005 2006 2007 2008 2009 2010 2011 Contracted … Power’s hedging strategy has mitigated market price increases, with 100% contracted through 2011. 29
  30. 30. Power has contracts for supply of its coal … Coal Output 18,000 12,000 Total Output GWH Hedged 6,000 Coal 0 2008 2009 2010 2011 85-95% 75-85% 55-65% 20-30% … and after installation of pollution control equipment, Power anticipates increasing flexibility in fuel choices. 30 Percent coal hedged as of 8/15/08
  31. 31. The Regional Greenhouse Gas Initiative (RGGI) … • Cooperative effort by Northeast states to design a regional cap-and-trade program to reduce carbon dioxide (CO2) emissions RGGI – Full participants – CT, MA, MD, ME, NH, VT, NY, NJ, RI, and DE States ME – Observers – PA, DC, eastern Canadian Provinces and New Brunswick VT NH • Timeline NY – April 2003 process proposed by Governor Pataki MA – 2003 – 2006 – Stakeholder process CT PA RI – December 20, 2005 Final 7 state MOU NJ – March 23, 2006 – Draft Model Rule MD – August 15, 2006 – Final Model Rule & amended Participating MOU DE – 2007-2008 – State level adoption Observer – First RGGI allowance auction September 2008 – January 1, 2009 – Implementation … has the potential to increase market prices. 31
  32. 32. The RGGI cap shows headroom … • Affected Sources – Fossil-fired electric generating CO2 Emissions vs. RGGI Cap units with a capacity of 25MW and (Actuals through 2007) larger 200 RGGI Cap Actual & BAU • Targets and Timing Forecast CO2 190 – Three-year compliance periods CO2 (millions of short tons) 180 with the first running from 2009- 2011 170 With RGGI – Stabilization of CO2 emissions at 160 recent levels through 2015 (~188 million tons per year) 150 – Achieve a 10% reduction of CO2 Actual Projected 140 emissions below recent levels by 2019 130 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 – This translates into ~13% reduction below 1990 levels or ~35% reduction from BAU* levels by 2020 … when viewed in comparison to historical emissions. 32 * BAU = Business as usual
  33. 33. RGGI’s CO2 pricing projections … $10 $8 $/Ton (Nom inal) $6 $4 $2 $0 2009 2011 2013 2015 2017 2019 2021 2023 2025 RGGI - ICF Base RGGI - ICF Base (Rev. Oct-06) … reflect moderate prices, based on the headroom in the cap. 33
  34. 34. At Power, strong cash generation and declining capital expenditures … Power Sources and Uses Power Cash Flow (2008 – 2011 Forecast) Net Cash Flow Cash $2.0 Asset from Ops Sales Incremental debt $10.0 capacity while Net Dividends maintaining target Financing $1.0 to Parent credit measures $8.0 $ Billions $0.0 $6.0 $ Billions Cash from Ops $4.0 ($1.0) Investments Declining Investments $2.0 ($2.0) $0.0 2007 2008 2009 2010 2011 Sources Uses … should result in substantial discretionary cash. 34
  35. 35. PSE&G
  36. 36. PSE&G operates in an attractive market … KEY: 2nd • NJ is ranked nationally in personal COMBINED ELECTRIC & GAS TERRITORIES ELECTRIC TERRITORY income per capita GAS TERRITORY • Mid-Atlantic ReliabilityOne Award winner six years running N • Solid regulatory relationships on traditional W E S utility matters Transmission Statistics (12/31/07) Historical Annual Load Growth Projected Annual Load Growth Network Circuit Billing Peak (MW) Miles 2003-2007 2008 - 2012 1,429 10,378* 1.3% 1.4% *Billing Peak includes adjustment for Voltage Reduction Electric and Gas Distribution Statistics (12/31/07) Historical Annual Projected Annual Electric Sales and Gas Sold Load Growth Load Growth and Transported Customers 2003 - 2007 2008 - 2012 Electric 2.1 Million 44,709 GWh 1.6% 1.0% Gas 1.7 Million 3,502 M Therms (0.2%) 0.4% … and through a disciplined capital allocation process and highly skilled workforce, has become a recognized leader in delivering safe and reliable service. 36
  37. 37. PSE&G’s base investment plan … • Regulated electric transmission, electric and gas distribution system • Characteristics • FERC regulation for electric transmission (formula rates) • NJ BPU regulation for electric and gas distribution • Managing recovery lag on electric and gas distribution investments PSE&G Rate Base 2012 Base Plan 2007 Actual Rate Base = $10.2 B Rate Base = $6.4 B Gas Distribution Gas 30% Electric Distribution Transmission Electric 35% 13% Transmission 22% Electric Distribution 52% Electric Distribution 48% Equity Ratio ~ 48% … coupled with fair regulatory treatment provides a solid foundation for projected future earnings growth from 2008 – 2012 of 7 - 8%. 37
  38. 38. PSE&G’s capital program is focused on improving reliability. 2007 2008 2009 2010 2011 2012 5-year capital program: $3.0B 2006 10-K June 2007 10-Q 5-year capital program: $4.1B 5-year capital program: $5.3B 2007 10-K PSE&G Rate Base ($ millions) 2007 Actual 2012 Base Plan Transmission 830 2,240 Gas 2,240 3,060 Electric 3,330 4,900 TOTAL $6,400 $10,200 38
  39. 39. PSE&G’s capital program • Rate base growth supported by investment in new 500kV lines to improve reliability ($900M) and upgrade of sub- transmission system ($250M). Transmission • Received FERC approval for CWIP in rate base and 125 bps adder to ROE on Susquehanna line. Base ROE increased by 50 bps for membership in RTO. • Investments focused on improving customer support, Electric and enhancing efficiency and upgrading infrastructure. Gas • Expect to file electric and gas rate case in 2009 with rates Distribution effective in 2010. • Future investment associated with meeting State energy efficiency and renewable goals dependent on receiving regulatory support before committing new capital, e.g. $485M New investment budgeted for AMI through 2012. Programs • BPU approved $105M investment in solar in April 2008; PSEG forecast includes $225M capital for solar through 2011 and $170M for energy efficiency. 39
  40. 40. By 2018, NJ’s load is expected to grow by 4,000 MW … Projects to NJ Projects to NY 2008-2018 NJ Summer Peak Annual Growth Rate = 1.8% • PSEG’s evaluation of • The Neptune HVDC project (685 MW) connecting Sayreville to the proposed backbone Long Island transmission projects: • The Linden VFT project (330 • Northern 500kV MW) connecting Linden to route into Jefferson Staten Island and Roseland • The Bergen O66 project (670 • Central 765kV route MW) connecting Bergen to into Deans ConEd's West 49th Street substation • Southern 500kV route into Salem • The Bergen Q75 project (1,200 MW) connecting Bergen to ConEd's West 49th Street substation • Linden S104 project (200 MW) connecting Linden to Goethals Total Import Total Export Capability Capability ~ 5,000 MW ~ 3,100 MW … yet the net import capability into NJ is only increasing by ~1,900 MW indicating need for additional generation, DSM or transmission imports requiring RTEP investment. 40 Sources: Imports: PSE&G Estimates; Exports: PJM 2008 Regional Transmission Expansion Plan; and Load Growth: PJM 2008 Load Forecast Report
  41. 41. Transmission opportunities will require substantial deployment of capital. Transmission Growth • PJM approval was received for the Susquehanna to Roseland line in October 2007 – Siting and permitting process underway Jefferson Roseland – FERC approved Incentive rate filing: Branchburg • 125 BPS adder to ROE • 100% CWIP in Rate Base Deans – Current cost estimate ($600-$650 million) under review I-765 Interstate • FERC approval of the MAPP projects also mandates an Smithburg Project additional $100 million of capital at Salem/Hope Creek • FERC approval of Sub Transmission to Transmission system reliability investments represents about $250 New Freedom million through 2012, post-2012 ~$60 million/year • Other approved RTEP projects ~$250 million also Hope Creek contribute meaningfully to improved reliability and Salem earnings growth MAPP • Backbone projects are in preliminary stages but present Project real opportunity to improve reliability throughout the state, with the potential investment of ~ $1.5B through 2015 When coupled with formula rate design and additional incentives, it is expected to provide current return on forecasted capital expenditures thereby improving profitability. 41
  42. 42. RGGI enabling legislation was signed into law in January 2008. • Solar Initiative – $105 million pilot program to finance installation of PV Solar approximately 40% subscribed. • AMI – Pilot acknowledged as being consistent with Energy Master Plan. – Stakeholder process developed to enroll key constituents in providing input into a final Technical Evaluation Report. – Pilot to test Mesh and BPL technologies • Section 13 of the RGGI Law permits utilities to invest and/or offer programs in renewables, conservation and energy efficiency. – Carbon Abatement Filing – June 2008 • Four-year $46 million program intended to demonstrate PSE&G capabilities – Demand Response Filing – August 2008 • Five sub-programs that ultimately represent 392 MWs and $93 million of investment by 2013 Our four programs will prove our capabilities at reducing carbon in an economic manner. 42

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