Allegheny Energy AYE
April 13, 2008 - 12:39pm EST by
chris815
2008 2009
Price: 52.40 EPS
Shares Out. (in M): 0 P/E
Market Cap (in $M): 9,000 P/FCF
Net Debt (in $M): 0 EBIT 0 0
TEV ($): 0 TEV/EBIT

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Description

Thesis
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.
 
 
 
 
Earnings / share
Cumulative
Earnings, 2007
2.25
 
Sources of incremental earnings, circa 2012
 
 
 
Plant availability
0.30
2.55
 
Transmission businesses (PATH, TrAIL)
0.82
3.37
 
Capacity sales
2.52
5.89
 
Electricity sales @ market prices in MD (beginning 1/1/09)
0.24
6.13
 
Electricity sales @ market prices in PA (beginning 1/1/11)
1.55
7.68
Earnings, circa 2012
7.68
 
 
  
Background
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.
 
 
Plant availability
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.
 
After-Tax Earnings from the Super Critical Plant Availability Initiative
Year
Availability
Earnings  boost ('07 is base)
Tax rate
After-tax earnings boost ('07 is base)
per share
2007 A
83%
 
35%
 
 
2008 G
89%
60,000
35%
39,000
0.23
2009 G
91%
80,000
35%
52,000
0.30
 
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.
 
 
Contribution Calculation: 1% increase in Supercritical Availability
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.
  
Transmission
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.
 
 
Earnings and Cash Flow from Transmission Projects
 
 
Project
Project cost
AYE's equity contribution
In service date
ROE
After-tax earnings
Depreciation
After-tax cash flow
Black Oak Substation
48,000
24,000
Dec. 2007
12.7%
3,048
 1,371
 4,419
TrAIL
820,000
410,000
2011
12.7%
52,070
 18,222
 70,292
PATH
1,800,000
600,000
2012
14.3%
85,800
 26,667
 112,467
 
 
 
 
 
140,918
 
 187,178
 
 
 
 
per share
0.82
 
 1.10
 
 
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.
 
Capacity payments
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 Payment Earnings
Year
Capacity available for sale (000, MW)
$ / MW day
$/MW year
Extended capacity. Revenue
Tax rate
After-tax earnings
Incremental after-tax earnings per share
2007-08
1.1
41
14,965
16,462
35%
10,700
 
2008-09
1.1
112
40,880
44,968
35%
29,229
0.11
2009-10
2.4
147
53,473
128,334
35%
83,417
0.43
2010-11
2.4
174
63,510
152,424
35%
99,076
0.52
2011-12
6.4
291
106,135
679,262
35%
441,520
2.52
 
 
 










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. 
 
Costs of building Generating Assets: 2008 vs. 2006
$ /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.
 
AYE Capacity Payment Earnings
 
AYE avail. cap. (000, MW)
$/MW day
$ / MW year
AYE ext. cap. rev.
Tax rate
After-tax earnings
AYE incremental  earnings / share
 
6.4
100
36,500
233,600
35%
151,840
0.83
 
6.4
125
45,625
292,000
35%
189,800
1.05
 
6.4
150
54,750
350,400
35%
227,760
1.27
 
6.4
175
63,875
408,800
35%
265,720
1.49
 
6.4
200
73,000
467,200
35%
303,680
1.71
 
6.4
225
82,125
525,600
35%
341,640
1.94
 
6.4
250
91,250
584,000
35%
379,600
2.16
 
6.4
275
100,375
642,400
35%
417,560
2.38
 
6.4
300
109,500
700,800
35%
455,520
2.60
 
6.4
325
118,625
759,200
35%
493,480
2.82
 
6.4
350
127,750
817,600
35%
531,440
3.05
 
6.4
375
136,875
876,000
35%
569,400
3.27
 
6.4
400
146,000
934,400
35%
607,360
3.49
 
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.
 
Electricity sales
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.
 
 
 
Incremental Earnings from sales of Electricity in Maryland
at various prices (beginning 2009)
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
 
 
 
 
 
Incremental Earnings from sales of Electricity in Pennsylvania
 at various prices (beginning 2011)
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.
  
Fuel cost to Generate Electricity: Coal vs. Natural Gas
Coal
 
Gas
 heat rate
 10,000
 
 
heat rate
 7,300
 
Coal, $ / short ton
$ / million BTU
$ / MWH
 
Gas, $/ 1000 cu ft
$ / million BTU
$ / MWH
$30.00
$1.36
$13.64
 
$5.00
$4.85
$35.40
$32.50
$1.48
$14.77
 
$5.25
$5.09
$37.17
$35.00
$1.59
$15.91
 
$5.50
$5.33
$38.94
$37.50
$1.70
$17.05
 
$5.75
$5.58
$40.71
$40.00
$1.82
$18.18
 
$6.00
$5.82
$42.48
$42.50
$1.93
$19.32
 
$6.25
$6.06
$44.25
$45.00
$2.05
$20.45
 
$6.50
$6.30
$46.02
$47.50
$2.16
$21.59
 
$6.75
$6.55
$47.79
$50.00
$2.27
$22.73
 
$7.00
$6.79
$49.56
$52.50
$2.39
$23.86
 
$7.25
$7.03
$51.33
$55.00
$2.50
$25.00
 
$7.50
$7.27
$53.10
$57.50
$2.61
$26.14
 
$7.75
$7.52
$54.87
$60.00
$2.73
$27.27
 
$8.00
$7.76
$56.64
$62.50
$2.84
$28.41
 
$8.25
$8.00
$58.41
$65.00
$2.95
$29.55
 
$8.50
$8.24
$60.18
$67.50
$3.07
$30.68
 
$8.75
$8.49
$61.95
$70.00
$3.18
$31.82
 
$9.00
$8.73
$63.72
$72.50
$3.30
$32.95
 
$9.25
$8.97
$65.49
$75.00
$3.41
$34.09
 
$9.50
$9.21
$67.26
$77.50
$3.52
$35.23
 
$9.75
$9.46
$69.03
$80.00
$3.64
$36.36
 
$10.00
$9.70
$70.81
$82.50
$3.75
$37.50
 
$10.25
$9.94
$72.58
$85.00
$3.86
$38.64
 
$10.50
$10.18
$74.35
$87.50
$3.98
$39.77
 
$10.75
$10.43
$76.12
$90.00
$4.09
$40.91
 
$11.00
$10.67
$77.89
$92.50
$4.20
$42.05
 
$11.25
$10.91
$79.66
 
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.
 
Replacement costs
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.
 
Replacement Cost of AYE’s Generating Assets
 
Stations
Location
Capacity MW
Repacement cost / MW (000)
Extended replacement cost (000)
Coal-fired steam turbine, super critical
 
 
 
 
Harrison
Haywood, WV
 1,983
 2,625
 5,205,375
 
Hatfield's Ferry
Masontown, PA
 1,710
 2,625
 4,488,750
 
Pleasants
Willow Island, WV
 1,300
 2,625
 3,412,500
 
Fort Martin
Maidsville, WV
 1,107
 2,625
 2,905,875
 
 
sub-total
 6,100
 
 16,012,500
Pumped Storage & Hydro
 
 
 
 
 
Bath County (pumped storage)
Warm Springs, VA
 1,059
 1,000
 1,059,000
 
Lake Lynn (hydro)
Lake Lynn, PA
 52
 1,000
 52,000
 
Green Valley Hydro (hydro)
multiple locations
 6
 1,000
 6,000
 
 
sub-total
 1,117
 
 1,117,000
 
 
 
 
 
 
Coal-fired steam turbine, sub critical
 
 
 
 
Armstrong
Adrian, PA
 356
 1,500
 534,000
 
Albright
Albright, WV
 292
 1,500
 438,000
 
Mitchell
Courtney, PA
 288
 1,500
 432,000
 
Ohio Valley Electric Corp.
Chelsea, OH, Madison, IN
 78
 1,500
 117,000
 
Willow Island
Willow Island, WV
 243
 1,500
 364,500
 
Rivesville
Rivesville, WV
 142
 1,500
 213,000
 
R. Paul Smith
Williamsport, MD
 116
 1,500
 174,000
 
 
sub-total
 1,515
 
 2,272,500
Gas-fired turbine
 
 
 
 
 
AE 3,4,5
Springdale, PA (combined cycle)
 540
 960
 518,400
 
AE 1,2
Springdale, PA (simple cycle)
 88
 650
 57,200
 
AE 8,9
Gans, PA (simple cycle)
 88
 650
 57,200
 
AE 12, 13
Chambersburg, PA (simple cycle)
 88
 650
 57,200
 
Buchanan
Oakwood, VA (simple cycle)
 43
 650
 27,950
 
Hunlock CT
Hunlock Creek, PA (simple cycle)
 44
 650
 28,600
 
 
sub-total
 891
 
 746,550
Oil-fired steam turbine
 
 
 
 
 
Mitchell
Courtney, PA
 82
 -  
 -  
 
 
totals
 9,705
 
 20,148,550
 
 
 
 
 
 
 
 
 
Risks
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:
 
  • Sixty-six percent of AYE’s deregulated low-cost generating capacity (3,400 MW) is located outside of the states of PA and MD.  These assets are owned by AYE’s deregulated subsidiary, AE Supply.  If push came to shove, AYE could abandon its distribution businesses in either PA or MD (collectively, these earn less than $0.60 per year) and sell power from their deregulated generating assets at market prices into PJM.
 
  • Re-regulating electricity prices will not necessarily hold prices down. As outlined above, AYE’s region is currently short on generating capacity, a situation that is expected to worsen during the next five years. Building generating assets is expensive; combined cycle gas plants cost about $1 million per MW while coal, nuclear, and renewable plants are much more expensive. Adding regulatory uncertainty will make the capital needed to add generating capacity more expensive.
 
  • If the rules do change and by some quirk, AYE is not able to maneuver around the politicians, AYE is still modestly valued.  Assuming AYE can sell power at its current prices in PA and MD, the company is likely to make $5.89 in 2012, so it is trading at less than 10x forward earnings (without the additional earnings from deregulated electricity prices in PA and MD).
 
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.
  
$12/ ton CO2 tax:  AYE’s coal vs. Natural Gas
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.

Catalyst

1. Roll-off of electricity price caps in Maryland and Pennsylvania.
2. Resolution of carbon tax issue.
3. Further capacity auctions in PJM.
    sort by    

    Description

    Thesis
    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.
     
     
     
     
    Earnings / share
    Cumulative
    Earnings, 2007
    2.25
     
    Sources of incremental earnings, circa 2012
     
     
     
    Plant availability
    0.30
    2.55
     
    Transmission businesses (PATH, TrAIL)
    0.82
    3.37
     
    Capacity sales
    2.52
    5.89
     
    Electricity sales @ market prices in MD (beginning 1/1/09)
    0.24
    6.13
     
    Electricity sales @ market prices in PA (beginning 1/1/11)
    1.55
    7.68
    Earnings, circa 2012
    7.68
     
     
      
    Background
    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.
     
     
    Plant availability
    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.
     
    After-Tax Earnings from the Super Critical Plant Availability Initiative
    Year
    Availability
    Earnings  boost ('07 is base)
    Tax rate
    After-tax earnings boost ('07 is base)
    per share
    2007 A
    83%
     
    35%
     
     
    2008 G
    89%
    60,000
    35%
    39,000
    0.23
    2009 G
    91%
    80,000
    35%
    52,000
    0.30
     
    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.
     
     
    Contribution Calculation: 1% increase in Supercritical Availability
    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.
      
    Transmission
    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.
     
     
    Earnings and Cash Flow from Transmission Projects
     
     
    Project
    Project cost
    AYE's equity contribution
    In service date
    ROE
    After-tax earnings
    Depreciation
    After-tax cash flow
    Black Oak Substation
    48,000
    24,000
    Dec. 2007
    12.7%
    3,048
     1,371
     4,419
    TrAIL
    820,000
    410,000
    2011
    12.7%
    52,070
     18,222
     70,292
    PATH
    1,800,000
    600,000
    2012
    14.3%
    85,800
     26,667
     112,467
     
     
     
     
     
    140,918
     
     187,178
     
     
     
     
    per share
    0.82
     
     1.10
     
     
    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.
     
    Capacity payments
    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 Payment Earnings
    Year
    Capacity available for sale (000, MW)
    $ / MW day
    $/MW year
    Extended capacity. Revenue
    Tax rate
    After-tax earnings
    Incremental after-tax earnings per share
    2007-08
    1.1
    41
    14,965
    16,462
    35%
    10,700
     
    2008-09
    1.1
    112
    40,880
    44,968
    35%
    29,229
    0.11
    2009-10
    2.4
    147
    53,473
    128,334
    35%
    83,417
    0.43
    2010-11
    2.4
    174
    63,510
    152,424
    35%
    99,076
    0.52
    2011-12
    6.4
    291
    106,135
    679,262
    35%
    441,520
    2.52
     
     
     










    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. 
     
    Costs of building Generating Assets: 2008 vs. 2006
    $ /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.
     
    AYE Capacity Payment Earnings
     
    AYE avail. cap. (000, MW)
    $/MW day
    $ / MW year
    AYE ext. cap. rev.
    Tax rate
    After-tax earnings
    AYE incremental  earnings / share
     
    6.4
    100
    36,500
    233,600
    35%
    151,840
    0.83
     
    6.4
    125
    45,625
    292,000
    35%
    189,800
    1.05
     
    6.4
    150
    54,750
    350,400
    35%
    227,760
    1.27
     
    6.4
    175
    63,875
    408,800
    35%
    265,720
    1.49
     
    6.4
    200
    73,000
    467,200
    35%
    303,680
    1.71
     
    6.4
    225
    82,125
    525,600
    35%
    341,640
    1.94
     
    6.4
    250
    91,250
    584,000
    35%
    379,600
    2.16
     
    6.4
    275
    100,375
    642,400
    35%
    417,560
    2.38
     
    6.4
    300
    109,500
    700,800
    35%
    455,520
    2.60
     
    6.4
    325
    118,625
    759,200
    35%
    493,480
    2.82
     
    6.4
    350
    127,750
    817,600
    35%
    531,440
    3.05
     
    6.4
    375
    136,875
    876,000
    35%
    569,400
    3.27
     
    6.4
    400
    146,000
    934,400
    35%
    607,360
    3.49
     
    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.
     
    Electricity sales
    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.
     
     
     
    Incremental Earnings from sales of Electricity in Maryland
    at various prices (beginning 2009)
    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
     
     
     
     
     
    Incremental Earnings from sales of Electricity in Pennsylvania
     at various prices (beginning 2011)
    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.
      
    Fuel cost to Generate Electricity: Coal vs. Natural Gas
    Coal
     
    Gas
     heat rate
     10,000
     
     
    heat rate
     7,300
     
    Coal, $ / short ton
    $ / million BTU
    $ / MWH
     
    Gas, $/ 1000 cu ft
    $ / million BTU
    $ / MWH
    $30.00
    $1.36
    $13.64
     
    $5.00
    $4.85
    $35.40
    $32.50
    $1.48
    $14.77
     
    $5.25
    $5.09
    $37.17
    $35.00
    $1.59
    $15.91
     
    $5.50
    $5.33
    $38.94
    $37.50
    $1.70
    $17.05
     
    $5.75
    $5.58
    $40.71
    $40.00
    $1.82
    $18.18
     
    $6.00
    $5.82
    $42.48
    $42.50
    $1.93
    $19.32
     
    $6.25
    $6.06
    $44.25
    $45.00
    $2.05
    $20.45
     
    $6.50
    $6.30
    $46.02
    $47.50
    $2.16
    $21.59
     
    $6.75
    $6.55
    $47.79
    $50.00
    $2.27
    $22.73
     
    $7.00
    $6.79
    $49.56
    $52.50
    $2.39
    $23.86
     
    $7.25
    $7.03
    $51.33
    $55.00
    $2.50
    $25.00
     
    $7.50
    $7.27
    $53.10
    $57.50
    $2.61
    $26.14
     
    $7.75
    $7.52
    $54.87
    $60.00
    $2.73
    $27.27
     
    $8.00
    $7.76
    $56.64
    $62.50
    $2.84
    $28.41
     
    $8.25
    $8.00
    $58.41
    $65.00
    $2.95
    $29.55
     
    $8.50
    $8.24
    $60.18
    $67.50
    $3.07
    $30.68
     
    $8.75
    $8.49
    $61.95
    $70.00
    $3.18
    $31.82
     
    $9.00
    $8.73
    $63.72
    $72.50
    $3.30
    $32.95
     
    $9.25
    $8.97
    $65.49
    $75.00
    $3.41
    $34.09
     
    $9.50
    $9.21
    $67.26
    $77.50
    $3.52
    $35.23
     
    $9.75
    $9.46
    $69.03
    $80.00
    $3.64
    $36.36
     
    $10.00
    $9.70
    $70.81
    $82.50
    $3.75
    $37.50
     
    $10.25
    $9.94
    $72.58
    $85.00
    $3.86
    $38.64
     
    $10.50
    $10.18
    $74.35
    $87.50
    $3.98
    $39.77
     
    $10.75
    $10.43
    $76.12
    $90.00
    $4.09
    $40.91
     
    $11.00
    $10.67
    $77.89
    $92.50
    $4.20
    $42.05
     
    $11.25
    $10.91
    $79.66
     
    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.
     
    Replacement costs
    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.
     
    Replacement Cost of AYE’s Generating Assets
     
    Stations
    Location
    Capacity MW
    Repacement cost / MW (000)
    Extended replacement cost (000)
    Coal-fired steam turbine, super critical
     
     
     
     
    Harrison
    Haywood, WV
     1,983
     2,625
     5,205,375
     
    Hatfield's Ferry
    Masontown, PA
     1,710
     2,625
     4,488,750
     
    Pleasants
    Willow Island, WV
     1,300
     2,625
     3,412,500
     
    Fort Martin
    Maidsville, WV
     1,107
     2,625
     2,905,875
     
     
    sub-total
     6,100
     
     16,012,500
    Pumped Storage & Hydro
     
     
     
     
     
    Bath County (pumped storage)
    Warm Springs, VA
     1,059
     1,000
     1,059,000
     
    Lake Lynn (hydro)
    Lake Lynn, PA
     52
     1,000
     52,000
     
    Green Valley Hydro (hydro)
    multiple locations
     6
     1,000
     6,000
     
     
    sub-total
     1,117
     
     1,117,000
     
     
     
     
     
     
    Coal-fired steam turbine, sub critical
     
     
     
     
    Armstrong
    Adrian, PA
     356
     1,500
     534,000
     
    Albright
    Albright, WV
     292
     1,500
     438,000
     
    Mitchell
    Courtney, PA
     288
     1,500
     432,000
     
    Ohio Valley Electric Corp.
    Chelsea, OH, Madison, IN
     78
     1,500
     117,000
     
    Willow Island
    Willow Island, WV
     243
     1,500
     364,500
     
    Rivesville
    Rivesville, WV
     142
     1,500
     213,000
     
    R. Paul Smith
    Williamsport, MD
     116
     1,500
     174,000
     
     
    sub-total
     1,515
     
     2,272,500
    Gas-fired turbine
     
     
     
     
     
    AE 3,4,5
    Springdale, PA (combined cycle)
     540
     960
     518,400
     
    AE 1,2
    Springdale, PA (simple cycle)
     88
     650
     57,200
     
    AE 8,9
    Gans, PA (simple cycle)
     88
     650
     57,200
     
    AE 12, 13
    Chambersburg, PA (simple cycle)
     88
     650
     57,200
     
    Buchanan
    Oakwood, VA (simple cycle)
     43
     650
     27,950
     
    Hunlock CT
    Hunlock Creek, PA (simple cycle)
     44
     650
     28,600
     
     
    sub-total
     891
     
     746,550
    Oil-fired steam turbine
     
     
     
     
     
    Mitchell
    Courtney, PA
     82
     -  
     -  
     
     
    totals
     9,705
     
     20,148,550
     
     
     
     
     
     
     
     
     
    Risks
    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:
     
    • Sixty-six percent of AYE’s deregulated low-cost generating capacity (3,400 MW) is located outside of the states of PA and MD.  These assets are owned by AYE’s deregulated subsidiary, AE Supply.  If push came to shove, AYE could abandon its distribution businesses in either PA or MD (collectively, these earn less than $0.60 per year) and sell power from their deregulated generating assets at market prices into PJM.
     
    • Re-regulating electricity prices will not necessarily hold prices down. As outlined above, AYE’s region is currently short on generating capacity, a situation that is expected to worsen during the next five years. Building generating assets is expensive; combined cycle gas plants cost about $1 million per MW while coal, nuclear, and renewable plants are much more expensive. Adding regulatory uncertainty will make the capital needed to add generating capacity more expensive.
     
    • If the rules do change and by some quirk, AYE is not able to maneuver around the politicians, AYE is still modestly valued.  Assuming AYE can sell power at its current prices in PA and MD, the company is likely to make $5.89 in 2012, so it is trading at less than 10x forward earnings (without the additional earnings from deregulated electricity prices in PA and MD).
     
    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.
      
    $12/ ton CO2 tax:  AYE’s coal vs. Natural Gas
    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.

    Catalyst

    1. Roll-off of electricity price caps in Maryland and Pennsylvania.
    2. Resolution of carbon tax issue.
    3. Further capacity auctions in PJM.

    Messages


    Subjectrisk of reregulation in pa
    Entry04/16/2008 04:31 PM
    Membergearl1818
    can you talk about how great this risk is?

    Subjectcarbon tax
    Entry04/17/2008 11:26 AM
    Memberdkepesh935
    chris, to the extent a carbon tax did in fact occur at the $50-75/ton level, why do you assume that the entire burden would fall to the electrical generators? would some fall to the other players in the supply chain (e.g. coal miners, railroads, etc.)

    in other words, if the Federal Government made coal a less attractive feedstock relative to gas/nuke/hydro, wouldn't coal prices likely fall, blunting the blow for the generators?


    SubjectCoal Costs
    Entry05/23/2008 01:29 PM
    Memberhumkae848
    Hey Chris, what kind of coal price assumptions are baked into your projections? I understand that 60% of their coal is contracted at low rates for 2009-2011, but the 40% that is open could get kind of ugly. I'm hearing north of $100 for NAPP coal. If I use $100 for the open position, that leaves a 2011 wtd avg coal cost/ton of $67. Assuming they burn 20 mm tons per year, that is an incremental cost of over $500 mm compared to 2007. I guess this is one reason why power prices should go higher but we're clearly taking dark spread risk and if nat gas sets the price more often in the future, can't we get in trouble if nat gas prices don't go up as much as coal costs do? Just curious to see if my logic is right and how you're thinking about this risk. Thanks.

    Subjecti spoke to the company
    Entry07/09/2008 11:48 AM
    Membergearl1818
    apparently...rising coal is good for aye b/c in 70% of their operating areas, coal sets the price...given that they are somewhat hedged, it works to their benefit b/c dark spreads rise which means they make more for their power and a portion of their costs are fixed...in the other 30% of their operating areas, nat gas sets price...since natg has roughly tracked coal...spreads should be good....people are confusing hi coal prices for these guys w/ lower margins....

    SubjectCoal Hedged Volume
    Entry07/16/2008 06:49 PM
    Memberhumkae848
    To what extent are you concerned that their hedged coal profile is at risk? As I'm sure you're aware, a 1 mm (5% of total) provider is suing AYE to get out of their supply contract, presumably because the contract is so under market and there's significant cost escalation at these mines. Given the escalating cost structure, to what extent is AYE at risk that some of these mom and pops won't be able to/refuse to supply the contracted amount of coal?
    Also, do you have any idea what kind of mix of coal AYE currently uses and what they will use once the scrubbers are put in?

    SubjectRE: Humkae
    Entry08/05/2008 10:51 PM
    Memberhumkae848
    Thanks for the response. The Q2 call addressed the coal issue fairly well and there appears to be substantial value from their coal hedges. What I tried to do is value the coal hedges separately and then figure out what earnings would be assuming they paid market for all their coal in 2011. For the coal hedges, obviously it depends on what you think market prices will do over time, but I get over $10 per share in present value. In terms of what the earnings power is assuming they pay market prices for coal, my rough calcs (using forward dark spreads) gets me to $4.50-$5.00 per share in 2011. Net-net, I think the stock is substantially undervalued at $45. Would be curious to hear your thoughts on my methodology. On a separate note, you mentioned that nat gas prices should rise faster than coal. I'm no expert with these commodities, but to me, coal and nat gas seem to have separate issues. Coal appears to be much more of a global market and it's not outrageous to assume coal prices stay elevated and nat gas comes in more. If that were the case, to what extent do you worry about nat gas plants displacing coal plants in AYE's region? Do you have a sense of the layout of all the power plants in AYE's region and to what extent nat gas plants could move up the dispatch curve if nat gas prices continue to come in?

    Subjectanybody have a clue
    Entry08/19/2008 02:12 PM
    Membergearl1818
    why aye stock has been so weak?

    SubjectRE: anybody have a clue
    Entry08/19/2008 03:46 PM
    Memberhumkae848
    I was wondering that myself... Obviously nat gas has come down considerably and coal prices remain robust, so the fear would be margin compression. But their hedged coal position, coupled w/ the fact that coal sets price most of the time in their markets, should mean that they don't get affected too much. And in 2011, their coal position should be a big advantage given that all their generation should go to market. They often used $80-$85 (incl capacity rev)as a datapoint, implied by the PPL auctions, for market rates in 2011. The way I see it, those auctions were conducted at nat gas and power price levels very similar to today. If you believe those power price levels, I get well over $6 in EPS in 2011. And according to my rough math, you would have to get to very low levels of nat gas (< $4/mmbtu) for the stock to be overvalued. Let me know if you agree or if you have any thoughts.

    Subjecti agree
    Entry08/29/2008 11:43 AM
    Membergearl1818
    but still puzzled at how weak the stock has been....

    Subjectwhat ruling...? ferc?
    Entry09/03/2008 02:33 PM
    Membergearl1818
    what was the ruling that you are referring to? was that adverse?

    Subjectreason for drop in price
    Entry09/03/2008 06:49 PM
    Membergearl1818
    in my view, the drop is more due to the drop in natgas and coal prices (to a much lesser extent than gas)...this could be foreshadowing lower spreads going forward...

    Subjectcarbon tax
    Entry10/03/2008 11:32 PM
    Memberdanarb860
    I have trouble making final calculations from your data. Assuming all other variables stay the same, what is the financial impact on AYE for each dollar of carbon tax per ton of CO2 emissions? Thanks.

    SubjectCapacity payments
    Entry10/09/2008 02:17 PM
    Membermiser861
    We're getting quite interested at current prices, but wanted to make sure we're looking at capacity payments correctly. We spoke to IR, who made the point that if we model all the POLR generation going to market prices as the agreements expire, then we would be double-counting if we also model capacity sales going from 2400 to 6400 MW. Meaning that AYE would have the entire 6400 MW capacity available to sell only if they refrain from selling POLR generation into the open market, after POLRs expire. Let me know if I misunderstood, and thanks for the writeup.
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