The crisis is a double whammy for the US power sector: reduced economic activity means lower sales and dropping commodity (oil, gas and coal) prices mean lower wholesale power prices. You combine the two and it spells lower revenues, decreased earnings and reduced asset valuations for unregulated (i.e., merchant) assets. However, it is not just the crisis that will have an impact on the US power sector but also the new laws, polices and regulations that will be enacted under the Obama administration. In addition, states will make moves of their own, continuing a trend that started in 2005 when it became clear that the Federal government was not going to do much during the second mandate of President Bush.


As a result, we foresee serious impacts for both investor-owned utilities (IOUs) and independent power producers (IPPs). Overall, IPPs will have a much tougher time in the next 2-3 years but they are used to it since they just went through a terrible period in 2002-2005; those who survive know that they will enjoy a stronger recovery later, especially if they develop wind projects.

Demand for electricity will drop through at least 2010 and further demand growth will be kept in check by increased energy efficiency and demand management efforts. As a consequence, many generation projects will be delayed or cancelled and new plant additions – beyond what is already under way - will not be needed until past 2015 in several regions of the country.

Greenfield project development activity can be expected to drop by nearly half for fossil fuel plants. It will be a whole different story for renewable plants which will enjoy strong support but the ones that will benefit from it will not be for the most part your traditional IPP players.

In the following, we try to quantify these impacts on both utilities and IPPs over the next seven years.

The first impact is reduced electricity usage for the next 2-3 years – up to 350-400 billion kWh less in 2010 which is a 9% drop (or $30 billion in sales) compared to was what projected pre-crisis. That’s not small potatoes: the crisis could mean a sales volume loss of over 1,100 billion kWh through 2011 – that’s over $100 billion in revenues less than what IOUs were counting on when they were preparing their capital expansion plans about a year ago.

As a result, we believe that, in spite of the numerous rate increases that were approved in 2007-2008, IOUs’ revenues for 2009 will be 3-4% below 2008 levels. We also forecast that utilities’ earnings will drop by at least 5%-8% this year. In our analysis, we find that about one IOU out of three will see its 2009 earnings drop by 20% or more and almost half will see earning drops over 10%. So, we project that the amount of cash that IOUs will get from operations will drop by $12-18 billion in 2009 – that’s a 25-30% cash flow reduction right there.

Longer term, we see the potential for a more permanent reduction in electricity use if all the investments in energy efficiency and automated metering infrastructure (AMI) that are currently being considered do pay off as advertised. In addition to launching a huge weatherization effort, the government plans to invest billions of dollars in retrofitting existing public facilities and has signed up with 16 energy-saving companies to execute up to $80 billion of energy efficiency upgrades. Likewise, the talk about smart grids has reached hype conditions. Nonetheless, even after trimming by half the announcements that have been made, it is not unreasonable to see the penetration of AMI jump to 40-50 million meters by 2015. How that would translate into peak demand shedding and actual kWh savings remains to be seen but, even after haircuts, it may mean 30-40 GW of additional demand-side management and 4- 5% savings in electric usage. In that case, demand growth is then much more in the 1.1%/year range rather than the 1.4-1.6% range we got used to recently. Over time, this adds up.

While there will be higher-than-average peak growth in 2011-2012, as the recovery takes off, peak growth can be expected to stabilize around 1.4%-1.5% in 2014-15. Compared to what IOUs were forecasting before the crisis, we see a system peak drop of 30 GW in 2011and we anticipate that drop to persist through 2015 when it may still be around 25 GW.


Decreased oil, gas and coal commodity prices will result in lower wholesale power prices in all organized power pool markets. Given the correlation that exists between natural gas prices and power (energy) prices in most regions of the United States, near-term pressure on gas prices will also affect profits from coal and/or nuclear merchant plants. In addition, a slowing economy and energy efficiency also threaten to reduce power demand growth below levels we might have previously looked for.

Compared to their 2008 levels, expected prices for 2009 will drop by 15-40% depending on the type of power, baseload, around the clock (ATC) or peaking. On average, the drop is about 25-20%.

Longer term, wholesale power prices will recover over a 2-3 year period as commodity prices increase again and power demand recovers. Prices for 2010 may recover somewhat (say, by 5%) but it will not be until 2011 that prices will get back to their 2007 level and they may not recover their 2008 level until 2013 at best. So, for the next 5 years, the industry will basically experience deflated prices; the average price through 2013 is estimated at 85% of 2008 prices. Past 2013, prices will be impacted by Federal carbon policy if a new GHG bill has been passed.

These wholesale price trends imply lower merchant asset values with a drop on average of 35-40% over last year (mid-2008). Coal plants using Eastern coal may show the worst drop, followed by load-following gas-fired units and then nuclear and wind. These fuel-specific asset changes will impact over half of the IPP asset base, including the larger players, even those with hedged and relatively well diversified asset portfolios. This has been reflected in the recent stock price drops of several publicly- owned IPPs. Many IPPs will have to deleverage and sell assets; some of the top 10-15 IPPs may actually be bought out. This will result in some industry consolidation and possibly as much as 30-40 GW of secondary market transactions in the next two years.

When we factor all these efforts, we see delays of two years or more in the need for new plants. In many regions, the need year (i.e., when new plants are needed to maintain the proper reserve margin in that area) has been pushed back to 2015-2017. Given the amount of current backlog that is still expected to proceed (some with delays) in spite of the crisis, only a few regions really need plant additions by 2014. This means that IPPs will not have much project development work to carry out for a while.

We estimate plant additions to drop by 35 GW between 2009 and 2015, compared to what was planned in the summer of 2008 before the crisis hit. The biggest impact is on fossil plant additions: 12 GW less for new coal capacity and 26 GW less in new gas plants for a total of $55 billion in reduced capital commitments over the next seven years. The only bright spot is that renewable plant additions will do better thanks to the new tax incentives and monies provided under the Obama administration.

We now project total capacity additions in the US power sector of roughly 80- 85 GW through 2015 – including 18 GW (21%) of coal; 28 GW (33%) of gas; and 38 GW (46%) of wind. About 30-35 GW remains in development play, mostly in wind projects.

Our forecast shows a national system’s gross capacity margin well over 20% through 2015. However, after adjusting for the fact that there is a growing amount of wind capacity that is typically not rated at full value compared to other types of fossil or nuclear capacity, the (truer) capacity margin peaks at 23% in 2011 and drops to 19% by 2015.

We expect IPPs to remain active even if they have to cut down their fossil project development activity by half. We still project 47 GW of new IPP capacity through 2015, that is slightly over half of all power plant additions in the next seven years, but over 60% of that will involve wind farms. IPPs may more or less complete their current construction plans through 2011 but then, many will trim their spending for new fossil IPP plants by as much as 45%. Some IPPs will invest in renewable plants but that will not make up the gap. Overall, IPPs will invest about 25% less in generation than they were planning just a year ago pre-crisis.

Furthermore, the bulk of new IPP additions being in wind, much of the new IPP development activity will involve a new crowd of players. This will be a big change for traditional IPPs that mostly focused on gas or, for some brave ones, coal plant development. Many IPPs – including the largest publicly-owned IPPs - will put on ice most of their greenfield opportunities or focus on “backyard project development” by expanding or repowering their own plants or focusing on a few regions rather than trying to expand nationwide.

Renewable energy – including wind, biomass and solar – will do better. IOUs and IPPs are chasing all three and there are already over 80 GW of projects under consideration. In the following, we focus on wind.

About 8.4 GW of new wind plants came on line in 2008; this brought the total amount of wind capacity in operation at the end of 2008 at 25 GW. Wind provided 35% of power plant additions in both 2007 and 2008 so it has become a major energy source.

There is another 4.5 GW under construction most likely to come on line in 2009-2010 and the current wind project backlog is huge, up to 74 GW consisting of over 400 projects. This mpressive backlog is also the result of 2-3 years of very active development pursued by over 100 companies that were counting on the continuation of a strong tax incentives and significant participation from a growing number of financial investors. If we extrapolate the industry’s project development track record to date, only a third of the backlog capacity will get built – that’s still 25 GW. However, we also need to look at the market drivers and constraints that are likely to impact the wind project development activity over the next 5-7 years.

On one hand, we have a very strong policy support for wind. The 2009 Stimulus bill (ARRA) provides developers with a choice between three tax incentives for projects developed through 2012: a $21/MWh production tax credit (PTC); or a 30% investment tax credit or a cash grant in lieu of an ITC. So, wind project developers now have access to a broader range of incentives which can now be tapped for a longer period, until the end of 2012. This 3-year 3- incentive environment provides more visibility than the industry has been able to plan on in the past 5 years.

Another possible positive development for wind would be the passage of a Federal RPS standard in the next 12-18 months followed by the possible implementation of a new cap-and-trade greenhouse gas (GHG) regime that could be in place in 2013-2015 and would further foster the development of wind projects. A Federal 20%-25% RPS could create a 20 GW or so boost by 2015 in demand compared to a state-mandated-RPS only scenario. That boost would not materialize over night but would be noticeable by 2013-14 and developers may choose to anticipate it by 1-2 years. If they do, that means a resurgence of development activity by 2011. However, opposition to an RPS will be strong; furthermore, there is a growing probability that the Federal RPS be rolled into a new GHG law.

The implementation of a cap-and-trade GHG regime would further boost the demand for renewables for the post-2015 period. Carbon prices in the $15-30/ton range, quite possible for the 2015-2020 period, could in theory imply an extra $5- 10/MWh bonus for wind projects. However, once a cap-and-trade system is in place, some if not all of the tax incentives that have been made available for wind would supposedly lapse. It is difficult to estimate how this will affect prevailing wind prices in 2012-2105 when that mixed transition to Federal RPS and then to cap-and-trade is likely to take place, but it is reasonable to assume that wind prices could benefit from a $5-10/MWh boost for a while.

On the other hand, there are four market constraints that will affect future wind project development prospects:

• How efficiently can developers use
available tax incentives
• An expected softness in negotiable
wind prices for the next 2-3 years
• Delays in RPS requirements due to
crisis-induced reductions in
electricity demand
• The need for new transmission
investments to enable the
development of more wind

Given the crisis and the low level of profits that are being made, both PTCs and ITCs have limited value to project developers. Worse, these developers now cannot find many financial institutions to whom to sell these tax credits; the number of such institutions has dropped from over 20 in 2007-2008 to less than 4 in the past five months and their funding appetite has dropped from $4 billion to half that at best. This is now a one-year problem and it may take 3 years for the situation to turn around. In that context, the cash grant incentive looks the best but it is a new incentive for which DOE needs to define the rules and that may mean some delays.

Meanwhile, power prices for wind will suffer the way wholesale power prices will, so there will be further softness in the next two years. Furthermore, a weaker power demand will delay the timing and size of many utilities’ RPS requirements by possibly as much as 25 billion kWh in 2015; this in turn would reduce by 7.5 GW the amount of wind required by then – or the equivalent of roughly 1 GW/year over the next seven years.

Finally, many wind projects cannot proceed unless more transmission lines are built. This is not a new issue and many utilities have proposed new lines. However, the track record for approving new lines is iffy. In addition, there are competing demands for capital since there are over a dozen high-priority transmission expansion projects (requiring over $15 billion of investments) already under consideration under DOE’s National Transmission Corridor initiatives (NIETC) launched in 2005. How that affects the prospects for the other 30 potential transmission projects that could spur the development of another 40-50 GW of wind resources remains to be seen, especially since these wind-related projects could require over $25 billion of investments.
Together, that means $40 billion of spending for an industry that was already maxed out when it invested about $7-8 billion in transmission per year in 2007 and 2008.