At $52.40 per share, Allegheny Energy, Inc. (AYE) is trading at 60% of the replacement value of its generating assets (about $20 billion) and 6.5 times earnings circa 2012.  The table above outlines five sources of earnings growth. Our earnings estimates are based on current market prices e.g., forward electricity prices in AYE’s region. We will endeavor to provide evidence which indicates that these market prices are reasonable estimates and may prove to be conservative. There are two risks to achieving these earnings:

 

1) The potential for legislative changes in Pennsylvania or Maryland to re-regulate electricity prices;

 

2) The introduction of a very high (above $75/ton) carbon tax. 

 

Regarding the potential for legislative changes, note that AYE’s earnings are likely to be $5.89 in 2012 without the additional earnings from deregulated electricity prices in PA and MD. In the unlikely event this were to happen, one is purchasing an excellent company for about 8.5x 2012 earnings and 50% of replacement costs (when one includes their T+D assets). Regarding carbon taxes, a tax that would be high enough to have a significant impact on AYE’s economics would likely be politically unfeasible.

 

 

AYE is an investor-owned electric utility operating in two business segments:

 

1)     Delivery and Services: consists primarily of three regulated transmission and distribution companies. Two additional transmission companies (PATH and TrAIL) have recently been formed and are included in this segment but do not contribute to earnings as of this writing.  AYE’s Delivery and Services segment historically have contributed about $0.70/year in earnings; PATH and TrAIL are likely to increase segment earnings to $1.50 (see transmission projects below).

 

2)     Generation and Marketing: owns 9,705 MW of electrical generating capacity; AYE will be able to sell 6,899 MW of this capacity (71%) at market prices by 2011; they refer to this as their “unregulated capacity”.   Three quarters of AYE’s unregulated capacity consists of supercritical coal-fired power stations, hydro electric power stations and pumped storage, i.e., low cost generating facilities.  Historically, all of AYE’s electricity was sold at regulated prices.  Currently, AYE is in the midst of a transition, prescribed by law and regulation, in which it will be able to sell its unregulated capacity at market prices. The transition began several years ago and, barring any legislative or regulatory changes, will be complete by 2011. During 2007, Generation and Marketing earned $1.72. AYE management thinks they can increase Generation and Marketing’s earnings by $0.30 over the next year or so by increasing plant availability.  In addition, the impact of selling their unregulated capacity and electricity at market clearing prices is likely to increase this segment’s earnings by an additional $4.30.

 

AYE is likely to increase annual earnings by at least $0.30 over the next two years via improved availability of their ten supercritical coal-fired generating units. (Supercritical coal fired boilers operate at higher pressure than subcritical boilers, typically more than 3,200 PSI. At 705 degrees F (which corresponds to a saturated steam pressure of 3208 PSIA) water no longer forms bubbles as it transitions from water to steam – hence 3208 PSIA is called the “critical point” of water (take our word for it, don’t try this in your kitchen). This smoother transition from water to steam translates into higher efficiency, i.e., less coal is required to heat the steam – this also has the benefit of reducing emissions per watt of electricity generated). AYE management has spent a number of years upgrading the supercritical units so that they can achieve higher availability.  Annual plant availability is defined as the ratio of the time a plant is available to produce electricity divided by the hours in a year  (8,760).

 

AYE management estimates that each 1% improvement in availability increases pre-tax earnings by more than $10 million.  Recent availability performance is summarized as follows:

 

AYE Supercritical Plant Availability

 

2002 82%

2003 78%

2004 76%

2005 83%

2006 84%

2007 83%

 

 

If we take management at their word, the after-tax earnings we can expect from their availability initiative is outlined in the following table.

 

 

To reality check their goal of reaching 91% availability, note that achieving 89% simply gets them into the top quartile of performance – by definition this is achievable, i.e., 25% of their peers have achieved it.  Secondly, note that the percentage of unplanned outages shown in the following table for their supercritical units has remained under 9.5% for the last three years.   

 

 

AYE Unplanned Outages @ Supercritical plants

 

2002   12.5%

2003   12.8%

2004   14.1%

2005   9.4%

2006   7.2%

2007   8.5%

 

 

The inference we make from this data is that it has been planned outages that have kept them from achieving greater than 91% availability for the last three years.  AYE management is in a position to know what their planned outages are likely to be over the coming years – so they are in a position to know with a high degree of certainty that they can achieve the 91% availability goal they have set for themselves.

 

But how does increased availability of the supercritical fleet translate into higher earnings?  The answer is additional power sales into PJM at market prices.  The following table shows the approximate economics of an increase of 1% supercritical availability assuming a 10,000 heat rate, ( AYE’s super critical plants have heat rates between 9,600 and 10,100, AYE slide deck, 9/1/06 p.17.) $45 coal, $54.88 electricity(The annual average LMP zone day-ahead price of electricity during 2007 in AYE’s region was  54.88, 2007 State of the Market Report, PJM, p. 66.) and a 75% capacity factor.

 

 

AYE unregulated supercritical capacity, MW	4,480
Hours / year	8,760
AYE unregulated supercritical annual capacity, gross ( MWH)	39,244,800
Capacity factor (2006 & 2007 average)	75%
AYE unregulated supercritical annual capacity, net ( MWH)	29,433,600
1% of AYE unregulated supercritical annual net capacity (MWH)	294,336
Assumed electricity sales price (2007 PJM average)	54.88
Coal cost / MWH, assuming $45 / ton @10,000 heat rate	20.45
Contribution / MWH	34.43
Contribution / 1% increase in supercritical availability	10,133,988

Two of the assumptions, AYE’s supercritical capacity factor and electricity prices, are likely to increase over the coming years; this will increase the contribution of each 1% increase in availability. AYE’s supercritical generating facilities will be dispatched more often as electricity demand grows and, as gas is likely to set the price of electricity in AYE’s region more often in the future, the sales price is likely to increase.

  

AYE’s Delivery and Services segment has traditionally earned about $0.70/share. AYE is currently augmenting its transmission infrastructure with two major transmission lines which are likely to increase its Delivery and Services earnings by $0.80, i.e., to $1.50 per year. These upgrades result from legislation passed in the wake of the August 2003 blackout which, among other things, provided for enhanced returns on transmission projects and directed the Secretary of Energy to study electrical congestion in the nation’s transmission network. The resulting study ( National Electric Transmission Congestion Study, U.S. Department of Energy, August 8 2006 p. 10.)  identified two critically congested areas, one of which, the Mid-Atlantic National Corridor, includes AYE’s service territory. The following table shows the economics of the transmission upgrade projects AYE is currently implementing.

 

 

 

 

Note that the after-tax cash flow of these projects is likely to be substantially higher than the earnings. This is because AYE is to allowed recover its investment as well as earn a return on equity.  Also note that the FERC has approved a 14.3% return on equity for PATH and, as part of the return incentives, ROE may be earned during construction.  AYE management thinks that the equity portion of these projects will be funded from cash flow (e.g., 2008 capital budget is $1.3 billion and is expected to be funded by cash flow), so shareholders are not likely to be diluted.  Finally, it should be noted that the transmission business is a very good business and the earnings are of very high quality, e.g., transmission projects feature guaranteed ROE, little chance of regulatory mischief and low operating and maintenance costs.  ITC Holdings, a publicly held electrical transmission company, currently trades for 20x forward earnings.  Using this multiple we can infer that AYE’s new transmission businesses are worth about $16.40.

The economics of generating electricity feature both high fixed costs (capital equipment) and, with the exception of nuclear plants, high variable costs (fuel). Capacity payments establish a market-based incentive for generators to build capacity, i.e., commit to the fixed costs of building and maintaining a plant to meet future demand. Historically, generating capacity was added under the supervision of regulators who specified regulated returns based on the cost of the facilities. At the retail level, capacity costs were bundled with energy costs.  Failures in the regulated approach have led to the deregulation of generating assets in several parts of the U.S., including large parts of AYE’s service area.

 

Capacity payments provided about $10 million to AYE’s pretax earnings ($0.06/share pretax) during 2007 and are likely to become an important source of earnings for AYE in the near future.  For example, there is evidence that capacity payments are likely to provide $1.50 of additional after-tax earnings by 2012 and possibility much more, e.g., $2.50 of additional earnings is possible.  There are two reasons for the increased earnings from capacity payments:

 

1)     An increase in the price of capacity, as demonstrated by capacity auctions held in 2007 and early 2008.  These auctions priced capacity during fiscal 2007-08 year at $41 per MW day, rising to $174 per MW day in fiscal 2010-11 year. (PJM Interconnection LLC is the regional electrical transmission organization that manages electricity transmission in AYE’s territory.  Among other things, PJM conducts the capacity market auctions and defines the capacity fiscal year as June 1 through May 31).

 

2)     AYE’s capacity available to sell into the capacity market will rise from 1,100 MW during 2007-08 to 6,400 MW during 2010-11.

 

The following table shows the implied earnings AYE is likely to achieve based on the results of recent capacity auctions and, in the case of 2011-12, PJM’s estimated cost of new entry (CONE) for a simple cycle combustion turbine to be built in 2010 for use in 2011. (PJM RPM Proposed Combustion Turbine Cost of New Entry update, published 12/13/07

 

 

 

 

Capacity payments are money paid to owners of generating assets by electricity consumers.  The cost of earning these payments consist of the expenses incurred to build and maintain generating assets. In the case of AYE, they have incurred these costs already, so the capacity payments translate directly into additional earnings. 

 

We know what capacity payments AYE will receive through 2011 because the auctions have already occurred, but how can we arrive at an estimate of what future capacity payments may be? There are three factors to consider when answering this question:

 

1)     Is there a need for additional capacity in PJM? (Yes)

2)     What is the cost to add capacity? (>$650 k / MW)

3)     What capacity payment would be needed to motivate generators to spend the money needed to add capacity? (>$240 / MW day)

 

Regarding capacity requirements, AYE’s generating assets are located in the Reliability First Corporation’s (RFC) region as defined by the North American Reliability Council (NERC). (The North American Reliability Corporation is a non-profit organization which develops (and has legal authority to enforce) electricity reliability standards in the U.S.).

 

According to data published in NERC’s 2007 Long-Term Reliability Assessment, October 2007, p. 175. the summer capacity margin in RFC is projected to fall to 11% by 2012. PJM’s target capacity margin is 16% and NERC considers a 15% capacity margin necessary to maintain reliable power. In fact, NERC says that RFC will require additional generating capacity in the next five years.

 

Generating assets are expensive and costs are rising. The following table summarizes recent data on costs for building generating assets published by Lehman Brothers and Citigroup. 

 

$ /MW	2008 cost	2008 cost		2006 cost
Nuclear	5,000,000	3,625,000
Coal	2,750,000	2,625,000		$1,370,000
Base load gas (combined cycle)	1,050,000	960,000		$596,000
Peaker gas (simple cycle)	650,000	690,000		$465,000

 

Let us use the lowest current number in the above table, $650,000 / MW, as an estimate of the cost of new capacity.  What one gets for this is a generating plant designed to meet only peak demand for electricity due to the high fuel costs associated with running such a plant. The investor considering building the plant would be wise to count primarily, maybe even exclusively, on capacity payments as the source of income for this plant.  This being the case, what would an investor be willing to take in the way of capacity payments to pay for this investment?  Assuming a 15-year useful life and a 10% return on assets, no taxes, no insurance and no maintenance, one could make the case that a $108,000 annual capacity payment ($300/ MW day) may motivate one to build the plant ($65,000 return on assets, $43,000 return of capital).  Of course, in real life, property taxes must be paid and equipment must be insured and maintained.  On the other hand, the investor would have higher returns if he had the opportunity to run the turbine, so he may be willing to take less in the way of capacity payments.  Below are AYE’s implied capacity earnings based on capacity payments ranging from $100 to $400 / MW day.

 

 

PJM’s most recent estimate of the cost of new entry, published in December 2007 concludes that the current cost of new entry is $246 per day escalating to $291 per day in 2010. We conclude that capacity payments will provide significant earnings growth for AYE within the next few years.

 

In addition to capacity sales described above, AYE is increasingly able to sell electricity at market prices in Maryland and Pennsylvania.  As of this writing, AYE will be able to sell 3.5 million MWH annually in Maryland at market prices beginning January 1, 2009 and 20.5 million MWH annually in Pennsylvania at market prices beginning January 1, 2011.  The Maryland electricity is currently sold for about $37/MWH while the Pennsylvania electricity was sold for about $35 / MWH during 2007. The data in the next two tables shows the implied incremental earnings from electricity sales in Maryland and Pennsylvania at various market prices.

 

Sales price / MWH	Inferred gas price	Incremental pre-tax earnings	tax rate	Incremental after-tax earnings	Incremental after-tax earnings per share
45	6.16	28,000	35%	18,200	0.11
50	6.85	45,500	35%	29,575	0.17
55	7.53	63,000	35%	40,950	0.24
60	8.22	80,500	35%	52,325	0.31
65	8.90	98,000	35%	63,700	0.37
70	9.59	115,500	35%	75,075	0.44
75	10.27	133,000	35%	86,450	0.51
80	10.96	150,500	35%	97,825	0.57
85	11.64	168,000	35%	109,200	0.64
90	12.33	185,500	35%	120,575	0.71
95	13.01	203,000	35%	131,950	0.77

 

 

 

 

 

Sales price / MWH	Inferred gas price	Incremental pre-tax earnings	tax rate	Incremental after-tax earnings	Incremental after-tax earnings per share
45	6.16	202,950	35%	131,918	0.77
50	6.85	305,450	35%	198,543	1.16
55	7.53	407,950	35%	265,168	1.55
60	8.22	510,450	35%	331,793	1.94
65	8.90	612,950	35%	398,418	2.33
70	9.59	715,450	35%	465,043	2.72
75	10.27	817,950	35%	531,668	3.11
80	10.96	920,450	35%	598,293	3.50
85	11.64	1,022,950	35%	664,918	3.89
90	12.33	1,125,450	35%	731,543	4.28
95	13.01	1,227,950	35%	798,168	4.67

 

We highlighted $55/MWH because that was the average sales price for electricity in AYE’s region during 2007. (The annual average LMP zone day-ahead price of electricity during 2007 in AYE’s region was $54.88, 2007 State of the Market Report, PJM, p. 66).  There is evidence that electricity in AYE’s region will sell for more than $55 in the future, maybe considerably more.  For instance $80 is the forward peak price of electricity in PJM at the end of 2009. (Fremont, Paul, Jefferies’ Spark-It-Watch Monthly, Jefferies & Company, 12/21/07, p.13). 

 

But how can we get comfortable with what the market price for electricity is likely to be in the future? The price of electricity in AYE’s region is increasingly set by generators using natural gas as a fuel.  Over the last three years, natural gas set the marginal price for electricity 25% of the time in PJM. (2007 State of the Market Report, PJM, p. 33.).

 AYE management estimates that electricity prices will be set by natural gas about 50% of the time in the next three or four years.  In 2012, gas and oil together are expected to represent 33% of the region’s installed capacity. The RFC region’s current summer capacity margin is about 16% and winter is 30%.  It does not take a heroic assumption to see that gas (and oil, which is a higher cost fuel on a BTU basis than gas) will increasingly set electricity prices in AYE’s region. The significance of the need to run gas turbines to meet electricity demand becomes clear when comparing the economics of generating electricity using coal vs. natural gas.  Consider the data presented in the following table.

  

 

We highlighted $9.70 gas because that is a recent price (delivered to the East Coast); the following table shows AYE’s coal costs through 2012.

 

  AYE’s Contracted Coal Costs (AYE slide deck, 2/27/08, p. 36).

Year	Delivered coal cost ($/ton)
2007	40
2008	44
2009	43
2010	43
2011	45
2012	47

 

The tables show that the implied fuel cost of electricity using $9.70 natural and a combined cycle gas turbine is $71/MWH  - a very large premium to the fuel cost of generating electricity using $47 coal ($22/MWH). Since we know AYE’s contract coal prices through 2012, all we are left with is the need to estimate gas prices.  The following table shows the current NYMEX futures prices of natural gas through November 2012.

 

Note that the forward gas price through 2012 varies between $8 and $10; this suggests electricity generated using natural gas (assuming zero spark spread and a gas turbine located at the Henry Hub) will be priced between $58-$73/MWH.  Of course, it costs money to move the gas from Louisiana to PJM and the spark spread is likely to be positive, so $58 -$73 electricity is probably conservative.

 

To reality check the forward gas prices, consider the following data, courtesy of Department of Energy. 

U.S. Natural Gas Supply & Demand, trillion cubic feet (U.S. Department of Energy Annual Energy Outlook 2008, table 13, plus my analysis)

		Imports
Year	Dry Gas Production	Pipeline	LNG	Projected  supply		Projected demand	Delta
2008	19.24	2.95	0.90	23.09		23.12	(0.03)
2009	19.35	2.95	0.99	23.29		23.31	(0.02)
2010	19.36	2.64	1.20	23.20		23.25	(0.05)
2011	19.32	2.56	1.44	23.33		23.37	(0.05)
2012	19.47	2.41	1.61	23.49		23.54	(0.05)
2013	19.47	2.22	1.61	23.30		23.35	(0.05)
2014	19.46	2.07	1.85	23.38		23.42	(0.05)
2015	19.58	1.91	2.12	23.61		23.66	(0.05)
2016	19.70	1.80	2.28	23.79		23.83	(0.05)
2017	19.69	1.67	2.37	23.73		23.78	(0.05)
2018	19.60	1.56	2.41	23.57		23.61	(0.04)
2019	19.47	1.45	2.45	23.37		23.42	(0.05)

 

Note that projected demand for natural gas consistently outstrips supply – a condition which suggests that gas prices are likely to remain high or go higher.  Also note that pipeline imports are projected to fall while LNG (liquid natural gas) imports are projected to increase.  This too suggests higher prices for two reasons:

 

1)     producing and moving LNG is considerably more expensive than moving gas via pipeline;

 

2)     the U.S. will be bidding against other countries for this LNG, e.g., Japan, Korea, Spain, India and China, which is likely to drive the cost up, especially considering our proximity disadvantage to most sources of LNG and the likelihood of having a weak currency. 

 

Interestingly, the Department of Energy looks at this same data and concludes that natural gas prices are likely to fall.  We know of no credible explanation for their position and have in fact seen (and written about, e.g. Yara, Veritas DGC) a range of other data (in addition to the forward market price) that point to higher natural gas prices e.g., well depletion rates, drilling costs.  

 

We conclude that natural gas is likely to set the price of electricity in AYE’s region much of the time within a few years and that natural gas prices are likely to remain high (above $9) for the foreseeable future.

 

The following table summarizes our analysis of the replacement value of AYE’s generating assets; we conclude that their generating assets are worth about $20 billion.  In addition AYE’s distribution companies had $4.6 billion of identifiable assets as of December 2007 and the new transmission businesses will hold about $2 billion worth of assets. AYE’s current enterprise value is $12.3 billion about half of replacement cost.

 

 

 

 

 

 

 

 

 

There are two risks to AYE’s ability to generate the earnings outlined in this report:

 

1) The potential for legislative changes in Pennsylvania or Maryland to re-regulate electricity prices.

 

2) The introduction of a very high (above $75 per ton) carbon tax. 

 

We think that it is axiomatic that selling electricity is a political business. For instance, last year, Virginia decided to abandon its plan to deregulate electricity prices, a move that has proved costly to AYE.  It is possible that Maryland and/or Pennsylvania politicians may get a notion to change their laws regarding electricity prices. The likelihood of electricity becoming much more expensive exacerbates this political risk.  But there are a three factors that mitigate this risk for AYE:

 

 

 

 

Regarding carbon taxes, by virtue of its chemistry, natural gas produces about 55% of the CO₂ as coal when burned (depending on the natural gas and the coal). The CO₂ tax is typically dicussed in units of dollars per ton of CO₂ emissions. The following table compares the effect of a $12/ton CO₂ tax on AYE’s coal costs vs. natural gas costs.

  

Assumptions
	Hypothetical carbon tax	$12.00	$/ ton of CO2 emmissions
	AYE's annual coal consumption	19,000	tons
	AYE's annual CO2 emissions	45,000	tons
	AYE's CO2 emissions	2.37	tons CO2 / ton coal burned
	AYE's CO2 emissions	4,737	lbs CO2 / ton coal burned
	AYE's coal BTU content	22	million BTUs / ton
	Natural gas CO2 emissions	117	lbs CO2/million BTUs
	Natural gas CO2 emissions	0.05854	tons CO2/million BTUs
Inferences
	AYE's CO2 emissions (coal)	215	lbs CO2/million BTUs
	AYE's CO2 emissions (coal)	0.10766	tons CO2/million BTUs
	Implied CO2 tax on AYE's coal	$1.29	per million BTUs
	Implied CO2 tax on natural gas	$0.70	per million BTUs

 

The table shows that a carbon tax of $12/ton CO₂ would increase AYE’s coal cost by $1.29 per million BTUs while gas would be taxed by $0.70 per million BTUs. Recalling the data on page 14 of this report, $45 dollar coal works out to cost $2.05/million BTUs – so its cost would increase AYE’s cost to $3.34 /million BTUs ($2.05 + $1.29 tax).  Accordingly, $9.70 gas would increase to $10.40 ($9.70 +$0.70 tax).  In this scenario, coal clearly retains most of its economic advantage.  However, as the hypothetical carbon tax increases, coal loses its advantage; a carbon tax of about $75/ton effectively neutralizes coals advantage vis-à-vis gas  assuming the gas is burned in a combined cycle turbine. 

 

While there are examples of countries with carbon taxes higher than $75/ton (Sweden is currently $150) those countries typically exempt electric utilities from these taxes, e.g., Sweden does not impose a carbon tax on fuels used to generate electricity.  There is reason to believe that U.S. utilities may also be spared very high carbon taxes because:

 

1)     Like all consumption taxes, carbon taxes are regressive;

 

2)     electricity prices are already likely to go higher driven by increased reliance on natural gas and the increasing cost of building new generating capacity.

 

Therefore, we conclude that imposing very high carbon taxes on fuels used to generate electricity is likely to prove politically difficult.