Reactors in the red: financial health of the US nuclear fleet

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1 Contents 1. ROUND-UP OF RECENT REACTOR RETIREMENT ANNOUNCEMENTS METHODOLOGY: MEASURING NUCLEAR PROFITABILITY MARKET IMPLICATIONS CASE STUDIES: FOUR REACTORS AT RISK. 11 Reactors in the red: financial health of the US nuclear fleet Five reactors announced premature retirement plans in H Many more could soon follow, short of a dramatic rebound in power, capacity or supplementary revenue streams. A close look at the US plant stack reveals 55GW of nuclear capacity facing sustained, long-run operating losses under current forward curves. With so much at stake, and potential knock-on effects for the entire US grid, this analysis explores the economics of the remaining nuclear fleet and predicts how many closures could still be on the way. 55% of the 1GW US nuclear fleet looks unprofitable over the period. The majority (29GW) of these underwater units are in deregulated regions, with the most impaired units commonly facing levelized shortfalls of $5-15/MWh. US nuclear power s unprofitability is largely a revenue problem. Dramatic decreases in hublevel power futures and the node-level effects of transmission congestion (partially due to new wind and gas build) have suppressed locational marginal prices (LMPs) to levels that cannot support nuclear power. This has reactors leaning increasingly heavily on standby capacity payments and lobbying hard for supplementary clean energy policy support. Figure 1: Profitability of US nuclear fleet, according to BNEF projections, (GW) Figure 2: Capacity, gas burn and emissions impact of US nukes by profitability status 3 Gas burn (Bcfd) Emissions (MtCO 2) GW GW 2 3 Positive GW 1 Unknown GW Negative Plan to Unknown Negative Positive Plan to Unknown Negative 4 retire retire 2 5 Deregulated regions Regulated regions 8GW - Source: Bloomberg New Energy Finance. Notes: Profitability is defined throughout Source: Assumes equivalent generation from CCGT of heat as pre-tax earnings, based on our estimates of historical and forward power and rate 7MMBtu/MWh, carbon intensity.426tco2/mwh. Heat capacity prices, and long-run costs of operating each plant. rates and emissions actually vary by region. Nine lame duck reactors remain in operation today, but have announced plans for early retirement. (Five such announcements came in 216). With much more of the US fleet still in the red, we investigate Byron, Davis Besse, Three Mile Island, and Palisades as the plants that could be next to announce closure. Illinois and New York power markets may be hit hardest by retirements - each will lose three plants if regulators do not intervene. Only generators in New England look financially healthy due to the region s high power and capacity prices. Nicholas Steckler By the numbers Our average projection for nodal power prices at reactors in PJM is only $28.5/MWh in 217. For comparison, the US industry average cost of nuclear power generation was $35.5/MWh in 215. With a range subject to whether our four identified at-risk plants retire alongside the plants that have already announced, the US can expect to lose between 6 and 9TWh of annual nuclear power generation by 22. This will boost gas burn and carbon emissions by 1-2 Bcfd and MtCO 2/yr, spread across multiple regions of the US. Disclaimer notice on page 16 applies throughout. Page 1 of 16

2 Table 1: US nuclear plant levelized, pre-tax earnings estimates and projections, ($/MWh, real215) Plant Name Owner Region Capacity (MW) Diablo Canyon PG&E Calif ornia 2, Com anche Peak Energy Future Holdings ERCOT 2, S TX STP Nuclear Operating Co ERCOT 2, Callaw ay Ameren MISO 1, Ferm i DTE MISO 1, AR Nuclear Entergy MISO 1, Palisades Entergy MISO Clinton Exelon MISO 1, Duane Arnold NextEra MISO Pt Beach NextEra MISO 1, Monticello Xcel MISO Prairie Island Xcel MISO 1, Millstone Dominon New England 2, Pilgrim Entergy New England Seabrook NextEra New England 1, Nine Mile Pt Exelon New York 1, Fitzpatrick Entergy New York Indian Pt 2 Entergy New York 2, Indian Pt 3 Entergy New York 2, Ginna Exelon New York Cook AEP PJM 2, N Anna Dominion PJM 1, Surry Dominion PJM 1, Calvert Cliffs EDF PJM 1, Mil Island Exelon PJM Braidw ood Exelon PJM 2, Byron Exelon PJM 2, Dresden Exelon PJM 1, LaSalle Exelon PJM 2, Lim erick Exelon PJM 2, Oyster Creek Exelon PJM Peach Bottom Exelon PJM 2, Quad Cities Exelon PJM 1, Beaver Valley FirstEnergy PJM 1, Davis Besse FirstEnergy PJM Perry FirstEnergy PJM 1, Susquehanna PPL PJM 2, Hope Creek PSEG PJM 1, Salem PSEG PJM 2, Cataw ba Duke Southeast 2, Grand Gulf Entergy Southeast 1, Robinson Duke Southeast Rvr Bend Entergy Southeast Sequoyah Tennessee Valley Authority Southeast 2, Waterford Entergy Southeast 1, Watts Bar Tennessee Valley Authority Southeast 1, Palo Verde Pinnacle West Capital Southw est 3, Cooper Nebraska Public Pow er District SPP Fort Calhoun Omaha Public Pow er District SPP Wolf Creek Wolf Creek Nuclear Optg Corp SPP 1, Source: Bloomberg New Energy Finance estimates, Illinois Commerce Commission Notes: List includes all reactors in deregulated regions plus reactors in regulated regions that have pricing information for potential sales into deregulated regions. For example, some Southeastern plants may sell into PJM or MISO markets. One plant may have multiple reactors. Profitability estimate does not represent actual revenues. See Excel Data Download for a full table of assumptions and full reactor list. Disclaimer notice on page 16 applies throughout. Page 2 of 16

3 1. ROUND-UP OF RECENT REACTOR RETIREMENT ANNOUNCEMENTS Wholesale power prices have fallen rapidly throughout the US. Merchant nuclear power plants are among the hardest hit especially in deregulated parts of the Midwest and Northeast. Nuclear plant owners have warned regulators of poor economics for at least three years now, blaming cheap natural gas and renewable energy penetration for the depression of prices. When gas and power prices hit record lows in the first half of 216, plant owners responded by furthering their agendas to close reactors in the MISO, NYISO, PJM, ISO-NE and SPP power regions. The number of reactors on the list of announcements set to retire prematurely has doubled since 215 there are now 8,954MW slated for early retirement. Table 2: Nuclear reactors with announced intent to retire Reactor Size (MW) Region State Owner Age (yr) Retirement date Gas burn equivalent (Bcfd) Clinton 1,65 MISO IL Exelon 29 June Quad Cities 1,819 PJM IL Exelon 44 June Oyster Creek 68 PJM PA Exelon Nine Mile Point New York NY Exelon 47 March Ginna 582 New York NY Exelon Fitzpatrick 847 New York NY Entergy 4 January Pilgrim 677 New England MA Entergy 44 June Diablo Canyon 2,24 California CA PG&E Fort Calhoun 479 SPP NE Omaha Public Power District 43 December Total 8, Source: Bloomberg New Energy Finance Notes: Plants may have multiple reactors. Average reactor age shown. Gas burn assumes 7MMBtu/MWh Our assessment of the financial health of retiring reactors The generators in Table 2 claim to be unprofitable, with the current outlook for power (and capacity) prices allegedly more grim than any factor on the cost side. Except a few plants citing high costs (Oyster Creek and Fort Calhoun), power prices are purportedly the most pressing factor on nuclear economics. With forward electricity prices looking fairly flat (ie. not promising the uptick necessary to cover long-run operating costs), generators simply announced intentions to retire struggling units, with closure dates often coinciding with the next fuelling cycle or the roll-off date of their powerpurchase agreements (PPAs). Short of a stark and unexpected rebound in natural gas prices, we see the fate of these particular plants as largely a policy issue of whether or not states will decide to offer subsidies to bring them to breakeven. See US nuclear takes one step forward eight steps back for more commentary on these policy details. In Figure 3 below, we estimate the profitability of plants that have announced intent to retire. 1 The estimate includes our projections for forward LMPs, capacity prices, and costs, as detailed in Section 2. Our analysis corroborates the owner s claims that each of these retiring units look to be in the red, apart from Pilgrim. 2 1 Profitability = realized energy price + capacity price generation cost estimate. 2 Despite the seemingly high power + capacity prices, Entergy has still made the decision to retire its Pilgrim reactor in Massachusetts citing policy dissonance and increasing operation costs. Disclaimer notice on page 16 applies throughout. Page 3 of 16

4 Figure 3: Pre-tax earnings estimates and projections for reactors that have recently announced retirement (based on LMP, capacity payment and cost estimates) ($/MWh real 215USD) 3 2 Pilgrim Ginna 1-1 Clinton Nine Mile Pt Oyster Creek Quad Cities Fitzpatrick Source: Bloomberg Terminal functions ISO<GO> and NRCR<GO>, Illinois Commerce Commission, PJM, Bloomberg New Energy Finance estimates. Notes: Nodal futures were constructed using hub futures and the historic spread of node against the hub. Does not represent actual profits. See Data Download for full profitability estimate Ominous signs for remaining reactors For the most part, the impaired reactors listed in Table 2 are not special cases amongst the US nuclear fleet; rather, their retirement announcements are symptomatic and foretelling of broader, US-wide economics that affect nearly all reactors exposed to wholesale prices. Unless we see a dramatic uptick in wholesale power prices, capacity prices or clean energy incentives (inclusive of nuclear), we expect more retirement announcements in the coming months and years. The list of plants in Table 1 that look to be in the money through 22 is very short. Only the Indian Point, Millstone and Seabrook reactors are undoubtedly profitable under current forward curves. What makes these plants special is exceptionally strong power and capacity prices in their respective regions. For example, the outlook for LMPs in New England in 218 is estimated to average above $38/MWh, with levelized capacity payments weighing in around $23/MWh. These are some of the highest power and capacity prices in the country, leading to estimated levelized earnings before tax in the $9-15/MWh range. In contrast, the estimate for most other US plants has dropped steeply from being positive in 214 to between $5/MWh and $15/MWh short of breaking even in 217. Plants like Ginna, Fitzpatrick, and Nine Mile Point One are still hanging on to the possibility of a bailout from New York state regulators, who will certainly be estimating these revenues shortfalls, in order to compare with the subsidies paid out to renewable energy in RPS programs. For comparison, the final solicitation of the NY RPS program paid a weighted average $25/MWh for Main Tier resources such as wind and solar power. Disclaimer notice on page 16 applies throughout. Page 4 of 16

5 2. METHODOLOGY: MEASURING NUCLEAR PROFITABILITY In a fleet-wide analysis of locational marginal electricity prices (LMPs) and capacity payments, we developed a view on the financial health of the all of the nuclear reactors in deregulated regions of the US (Table 1). Additionally, our list include some reactors in regulated regions, where wholesale pricing information is available. 3 Over half of the 1GW US nuclear fleet is facing negative earnings over the time period, according to the current outlook for power prices (Figure 1). Units appearing negative (in the red) are in locations where LMPs and capacity revenues are not strong enough to cover estimated longrun operating costs. The only units that will remain profitable in the next several years are those in New England as well as the New York Indian Point reactor outside New York City. New England in particular has some of the highest LMPs and capacity prices in the country. The next healthiest region is PJM, where some plants may break even by a narrow margin, thanks to high- to mid-range capacity revenues, but hindered by low LMPs. Plants in MISO and ERCOT look to be in the worst conditions as they face both low LMPs and low capacity prices. Figure 4 below compares the ranges and averages of nuclear plant profitability across the deregulated US power regions. Figure 4: Range of average profitability of reactors by region over period ($/MWh, real215) Average New England New York California PJM ERCOT MISO SPP Source: Bloomberg New Energy Finance 3 The distinction is important because regulated power plants can generally remain operable by rate-basing costs even while running at an economic loss; plants in deregulated regions are more exposed to wholesale prices, and are generally more at risk of retirement than their regulated counterparts. Disclaimer notice on page 16 applies throughout. Page 5 of 16

6 2.1. Power prices Historical power prices Since 214, regional power prices have fallen across the US. (The plunge owes mostly to falling natural gas prices, but other structural, price-suppressing factors are afoot, as discussed in our April 216 Research Note: A eulogy for US wholesale power prices.) Whereas much attention is paid to falling benchmark hub prices, this note digs more granularly into the nodal prices realized by individual plants. Often nodal prices differ materially from the nearest benchmark hub price; this level of specificity (using nodal rather than hub-level prices) affords us a more precise understanding of the financial health of individual reactors. For example, reactors such as Clinton and Quad Cities have historically experienced severe transmission congestion, resulting in nodal LMP s that are on average $6-8/MWh lower than prices at the nearby Northern Illinois hub price. Figure 5 and Figure 6 below show the historical prices in the form of monthly averages of dayahead and real-time LMPs at the exact locations of the nuclear reactors that have announced plans to retire. 4 Figure 5: Historic and projected monthly average LMPs at retiring reactors, PJM and MISO Figure 6: Historic and projected monthly average LMPs at retiring reactors, NYISO and ISO-NE ($/MWh real 215USD) 14 ($/MWh real 215USD) Oyster Creek 1 Quad Cities 1 Clinton Pilgrim 1 Nine Mile Pt 1 Ginna 1 Fitzpatrick Source: Bloomberg Terminal functions ISO<GO> and NRCR<GO>, Illinois Commerce Commission, Bloomberg New Energy Finance estimates Note Quad Cities and Oyster Creek are day-ahead, Clinton is real-time. Nodal futures were constructed using hub futures and the historic spread of node against the hub. Ginna LMP is day-ahead, the others are real-time. Nine Mile price curve is virtually identical to that of Fitzpatrick, as the reactors are physically side-by-side. 4 Locational Marginal Price (LMP) = energy price + congestion charge + losses. LMP is synonymous with nodal price. Disclaimer notice on page 16 applies throughout. Page 6 of 16

7 Power price projections Future power prices used in this analysis are rooted in Bloomberg Terminal Fair Value Curves 5, which capture market-traded sentiment about where power prices are heading. Spot prices were in steep decline in early 216, but long-dated power futures have shown some recent signs of recovery, with Calendar Year 217 contracts rising with the improving outlook for natural gas. Nuclear generators across the US hope that gas (and power) prices will continue their rally, but our Fair Value Curves anticipating flat-lining prices beyond 217. One quick methodological note: whereas our Fair Value Curves describe hub-level futures prices, this analysis was done at the nodal level. To bridge this data gap we assumed a static future spread between nodal and hub-level prices. Power purchase agreements (PPAs) Some nuclear plants operate on a merchant basis, in which case we can measure their profits precisely by tracking nodal LMPs; many other plants have hedged their power price exposure through a series of PPAs that may be above or below wholesale market value at any given time. Ultimately, this report fails to capture the earnings impacts of reactors price hedges, though we think this is a non-issue over the long term. The reasons are (i) power price hedges are intended to reflect the futures curve at the time of signing, so the spread in some cases is minimal; and (ii) nuclear PPAs are typically fairly short in duration (1-3 years), so even those reactors with PPAs will be exposed to incumbent market realities by the end of the decade. In fact, Exelon stated in its Q1 216 SEC filings 6 that across its entire US generation fleet (all technologies), the percentage of future generation that is hedged will drop from above 95% to below 4% by 218, greatly increasing the company s exposure to these lower market prices. At the point that these plants become unhedged, they are very likely to enter another PPA that will reflect market prices, continuing the cycle of rolling on and off of hedge contracts. Power and gas prices are currently on their way up from record lows in early 216. Futures prices for calendar year 218 have risen $1-3/MWh in PJM and MISO and $6/MWh in ERCOT since hitting record lows in March. Importantly for nuclear power generators, the slight rebound is an upside for revenues through better power market or PPA prices, although, that rebound might not be strong enough for plants that are rolling off PPA s that were signed at and accustomed to prices Capacity prices Capacity prices are standby payments meant to reward generators for their contribution to grid reliability. Their importance varies by region. In New England, capacity payments represent almost 25% of nuclear reactors future revenues; meanwhile in ERCOT s energy-only market capacity prices are non-existent. For this analysis, we mapped each reactor to its corresponding capacity zone, granted its capacity payments equal to the current forward prices (unless otherwise noted 7 ), and assumed that future capacity payments would match the most recent capacity auction value, where applicable. See Data Download for full capacity payment assumptions for each plant. 5 For more details on Bloomberg Fair Value Curves, see BNEF Data Viewer 6 Exelon May 216 Company Filing Q1 216 Earnings Release Slides pg Plants Three Mile Island, Byron, Oyster Creek and Quad Cities are assumed to have failed to clear at least one forward year of capacity auctions. Disclaimer notice on page 16 applies throughout. Page 7 of 16

8 2.3. Costs Our estimates of plant profitability include cost estimates for total generation cost of existing reactors. These generation costs include expenditures on fuel, operations and maintenance, and CAPEX injections that go into the plants for repairs. For the Exelon fleet, generation cost estimates were obtained from a study performed by the state of Illinois. 8 All other plants generation costs were based on US industry average costs presented by the Nuclear Energy Institute (NEI) for UBS 9. The industry average cost of generation across the US nuclear fleet was $35.5/MWh in 215, but the NEI points out a distinct difference in the average for single-unit plants ( orphans ) versus multi-unit sites, costs of $44.52/MWh and $32.9/MWh respectively. Of the nine plants that have announced plans for retirement, six of them are single-unit plants and eight of them are in deregulated regions. This suggests that the deregulated orphans are much more likely candidates for early retirements because of their inability to rate-base their significantly higher per-mwh generation costs. 8 Potential nuclear power plant closings in Illinois Getting nuclear on nuclear costs - Disclaimer notice on page 16 applies throughout. Page 8 of 16

9 3. MARKET IMPLICATIONS 1. Policy At this point, we fully expect the announced reactors to retire if they do not receive any form of policy support from state governments. There seems to be hope left only for Ginna and Nine Mile Point 1 in New York state, where the Public Service Commission (PSC) is scrambling to expedite the creation of the new Clean Energy Standard in a way that is fair to all parties and makes sense for emissions goals. The PSC has stated that the plan will be finalized by September and will include dedicated subsidies (ZECs) for nuclear plants. With new transmission expansions in the state still several years away from completion, it is likely that the regulator will save at least one of these reactors for both sustainability and grid reliability reasons. Other states have less chance of putting something together in time before Exelon and FirstEnergy pull the plugs on their plants Illinois failed to pass pro-nuclear legislation in May and the Public Utilities Commission of Ohio was stopped by FERC when it tried to allow contractual subsidies for FirstEnergy and AEP. The fact that FirstEnergy and AEP almost got out-of-market assistance ignited a face-off between Exelon/Dynegy and FirstEnergy/AEP - the former preferring low-carbon incentives, the latter preferring out-of-market PPAs, and all of them desperate for assistance combatting low power prices in general. For more details on the policy developments in Illinois, Ohio, and New York, see US nuclear takes one step forward, eight steps back[nw1] for a deeper look into the nuclear policy discussion in these states. 2. Gas burn Any nuclear retirements executed in the next few years will lead to an uptick in gas burn for power generation. All but one of the reactors on our announced list (Section 1) state retirement dates in 219 or earlier. Losing these 6,714MW of capacity by 219 would create a significant displacement in US power generation, increasing natural gas burn by approximately 1Bcfd nationwide. 1 Because the announced reactors are spread across multiple regions, the effect of the uptick is likely to be less impactful on the gas markets. The only exception is if policy assistance fails to save the upstate New York reactors the resulting increase in gas burn from the closure of all of the upstate New York reactors would be an uptick of.5bcfd in the region by 217. We anticipate that this figure will be lower because for both emissions and reliability reasons, it seems unlikely that New York regulators would allow closure of almost all of the upstate reactors. More significant impact on gas burn is possible in the event that any of the reactors on our watchlist (see Section 4) retire as well, adding to the displacement from already announced plants. If Byron were to retire by 217, the impact of the three total plant retirements in Illinois would be an increase in gas burn of approximately.78bcfd. If Three Mile Island were to retire alongside Oyster Creek in eastern PJM, the combined gas burn uptick would be about.2bcfd. 1 Assumes CCGT heat rate 7MMBtu/MWh and a nuclear reactor capacity factor of 9% Disclaimer notice on page 16 applies throughout. Page 9 of 16

10 3.3. Emissions Because lost nuclear power generation will likely be replaced with gas burn, the retirement of the nine plants in our announced list would increase total US power sector emissions by about 3.4MtCO2 per year. 11 Just the California Diablo Canyon closure would increase that state s emissions by over 7.38MtCO2 per year if it were to be replaced entirely by gas generation, although PG&E plans to fill the gap with energy efficiency and renewables. In Illinois, the closure of Clinton and Quad Cities will increase the state s emissions by over 1 MtCO2 per year. The effects of these closures on Clean Power Plan compliance would be significant. For an idea of scale, California and Illinois have 23 mass targets of 44MtCO2 and 6MtCO2 respectively (see BNEF EPA Clean Power Plan). Other states with nuclear reactors would feel similar impacts in trying to comply with the Plan. Figure 2 at the start of this report shows the equivalent impact on gas burn and emissions of replacing different fractions of the entire US nuclear fleet. The figure highlights the range between the Plan to Retire (in black), which will lead to an almost certain increase, as well as further burn and emissions that could come from additional retirements of plants with profitability that we ve identified to be negative (in red). 11 Assumes.426tCO 2/MWh. Carbon intensity and heat rates actually vary by state. Disclaimer notice on page 16 applies throughout. Page 1 of 16

11 4. CASE STUDIES: FOUR REACTORS AT RISK In addition to the list of reactors that have already announced intent to shutter, this section builds four case studies of plants that are in the red that have yet to announce plans for retirement.of course, as other reactors retire, there will be an impact on energy and capacity prices in a way that benefits surviving generators. Regulators may also step in and stop certain closures for reliability or sustainability reasons. This section considers these factors alongside a profitability analysis of the plants that could soon be the next to join a wave of retirements: Table 3: Four plants that could be next to announce retirement Reactor Source: Bloomberg New Energy Finance Based on our estimates of future power prices, capacity prices, and generation costs, Davis Besse, Byron and Three Mile Island all look unprofitable through 22. These are plants that are likely to be unhedged in the coming years and may see negative profitability like we ve estimated below in Figure 7. A profitability estimate for Palisades is not included in the chart because Entergy holds a hedge for the plant to 222. Figure 7: Pre-tax earnings estimates and projections for Davis Besse, Byron, and Three Mile Island, (based on LMP, capacity payment and cost estimates) ($/MWh real215usd) 2 Capacity (MW) Region State Owner Age Prediction Gas burn equivalent (Bcfd) Davis Besse 894 PJM OH FirstEnergy 39 Spring Byron 23 PJM IL Exelon 31 June Three Mile Island 85 PJM PA Exelon 42 June Palisades 86 MISO MI Entergy 44 June , Davis Besse Three Mile Island Byron Source: Bloomberg Terminal functions ISO<GO> and NRCR<GO>, Illinois Commerce Commission, PJM, Bloomberg New Energy Finance estimates. Notes: Nodal futures were constructed using hub futures and the historic spread of node against the hub. Does not represent actual revenues. See Data Download for full profitability estimate calculation. Disclaimer notice on page 16 applies throughout. Page 11 of 16

12 4.1. Byron Byron is a 2,3MW nuclear power plant owned by Exelon in Northwest Illinois. Located more than 5 miles outside of Chicago, Byron has significant transmission congestion issues plaguing its economics similar to the cases of Clinton and Quad Cities. Effects of distance from load centers compounded with proximity to new wind farms have caused average prices at Byron to come in well below the PJM Northern Illinois hub price during certain times of the year they averaged $7/MWh lower than the regional Northern Illinois hub price in 215. We have constructed a forward curve for the node that follows the hub forward traded curve but deviates during months of historical congestion (Figure 8). The negative impacts of congestion at the node compound with the alreadylow hub forecast. The closure of the other Illinois reactors, Clinton and Quad Cities, is an upside on the overall hub price, but those closures southwest of Chicago will not relieve congestion near Byron. Figure 8: Monthly average LMP at Byron, ($/MWh real215usd) Source: Bloomberg Terminal function ISO<GO> and ticker PJM84W DA LMP 24AV Index. Note: Nodal futures were constructed using hub futures and the historic spread of node against the hub. PJM Northern IL Byron 1 Figure 9: Byron profitability estimate, ($/MWh real215) 8 Capacity payment 7 Power 6 Cost Source: Bloomberg New Energy Finance Note: See Data Download for full profitability estimate calculation. Apart from earning energy revenues, Byron is in the COMED zone of the PJM capacity market, where it typically earns payments of around $5/MWh ($12/MW-day, real 216USD). Auctions are held on a three-year forward basis and Byron has failed to clear both the 217/18 and 219/2 auctions. 12 Revenue, not cost, is the root of the poor economic outlook at Bryon. The plant itself is relatively new (31 years) with reported costs of generation that line up almost exactly with the Nuclear Energy Institute s industry averages $32.9/MWh; however estimated revenues look so low that the plant s profitability through 22 looks unattractive despite maintaining average generation costs (Figure 9) Disclaimer notice on page 16 applies throughout. Page 12 of 16

13 The exact revenues at Byron are unknown, but an unhedged version of the plant doesn t look close to breaking even anytime this decade. If Exelon kept it open, it would be because of a favourable hedge or in anticipation of better days in the early 22 s. While it is hard to imagine the political fallouts of closing yet a third reactor in Illinois, we think that based on the numbers only, it looks very likely that this plant could begin to close in June 217, when the end of its current fuel cycle coincides with the time at which it no longer has capacity market obligation Three Mile Island Three Mile Island is another Exelon plant with an economic outlook that has been heavily impacted by a weak power forward curve. The single-unit plant is located in south-central Pennsylvania, near the Marcellus Shale, where power prices have been in steep decline resulting from rapid growth in gas-fired generation. Unlike Byron, Three Mile Island does not have congestion problems on the revenue side; instead, most of the region faces a bleak power forward curve. The 42 year-old, 85MW reactor has reported generation costs of $4/MWh, which is below the industry average $44.5/MWh for single-units. In May, Exelon announced that Three Mile Island failed to clear the 219/2 PJM capacity auction, the second consecutive year that the plant has failed to clear the forward auction. This leaves the plant committed only until May 218. Without those capacity payments, it is very unlikely that Three Mile Island could make up its $4/MWh generation cost with energy market revenues alone. We do expect this plant to cease operation around June 218 when its capacity market obligation terminates. Figure 1: Average monthly LMP at Three Mile Island ($/MWh real215) 12 Figure 11: Three Mile Island profitability estimate, ($/MWh real215) 12 1 Three Mile Island PJM METED 1 Capacity payment Power 8 8 Cost Source: Bloomberg Terminal function ISO<GO> and ticker PJMH3W DA LMP 24AV Index. Note: Nodal futures were constructed using hub futures and the historic spread of node against the hub Source: Bloomberg New Energy Finance Note: See Data Download for full profitability estimate calculation. Disclaimer notice on page 16 applies throughout. Page 13 of 16

14 4.3. Davis Besse Davis Besse is a 39-year-old, single-unit, 894MW reactor in Northern Ohio. The major piece of information that makes us suspecting of a closure at Davis Besse is the FERC s rejection of the Powering Ohio s Progress plan from FirstEnergy to the Public Utilities Commission of Ohio (PUCO) for contractual offtake of its power at an uplifted rate (see BNEF note US nuclear take ones step forward, eight steps back). Although the FERC ultimately stymied the deal, the PUCO was ready to allow it this makes us believe that the economic situation is quite poor at the plant. Our estimate of profitability (Figure 13) for Davis Besse reveals that it is likely suffering badly through the period. We project Davis Besse LMPs to average well-below the average cost reported by NEI for a single-unit site ($44/MWh). Davis Besse has been one of the most accidentprone reactors in the country giving us reason to think that the costs are at least as high as the industry average. PJM capacity payments are locked-in through 22, meaning there is no potential upside in capacity revenues until post-22. In order to become profitable, Davis Besse would need an upswing in the power forward curve or a new FERC-approved contractual offtake agreement with the PUCO. The plant s operating license is already renewed to 237 meaning it could try to ride out the lower power prices, but we are hesitant to believe that it would last that long under negative profitability. We believe that Davis Besse could retire prematurely at the end of its current fuel cycle in Spring 218 if it finds a way to release its remaining capacity market commitments. Figure 12: Average monthly LMP at Davis Besse, ($/MWh real215) Davis Besse 1 PJM AEP (Dayton) Source: Source: Bloomberg Terminal function ISO<GO> and ticker PJM9P DA LMP 24AV Index. Note: Nodal futures were constructed using hub futures and the historic spread of node against the hub. Figure 13: Davis Besse profitability estimate, ($/MWh real215) 1 9 Capacity payment 8 Power 7 Cost Source: Bloomberg New Energy Finance Note: See Data Download for full profitability estimate calculation. Disclaimer notice on page 16 applies throughout. Page 14 of 16

15 4.4. Palisades Palisades is a 44 year old, 86MW, single-unit plant in southwest Michigan, where MISO power prices have dipped to record lows in 216. Fortunately for the owner Entergy, the plant s output was hedged with Consumers Energy through 222. Analysis by UBS suggests that despite the hedge (thought to be above $4/MWh), both Palisades and Consumers Energy could benefit from the early retirement of Palisades. If this estimate is true, Consumers Energy is locked in at a price of almost double the market value of power at MISO Michigan Hub (see Figure 14). If the current PPA could be restructured, Consumers Energy might be able to pay a lower price and Entergy could retire Palisades, replacing its generation with purchases from the spot market instead, subsequently saving on generation costs. If Entergy generation costs reflect the NEI industry average for single-unit reactors, then replacing Palisades generation with market-purchased power could cut costs of generation from about $44/MWh to well under $3/MWh (see forward curve in Figure 14). Capacity revenues would be lost with the plant s retirement, but MISO capacity payments for Palisades are likely less than $3/MWh, much less lucrative than the potential cost savings of shutting the plant. Unlike PJM s three-year forward auctions, MISO capacity commitment is done on a one-year forward basis, meaning that Palisades could shut as early as June 217. Figure 14: Average monthly real-time LMP at Palisades ($/MWh real215) MISO Michigan Hub Palisades Source: Bloomberg Terminal function ISO<GO> and ticker MIS3B7 5M LMP 24AV Index. Note: Nodal futures were constructed using hub futures and the historic spread of node against the hub. Disclaimer notice on page 16 applies throughout. Page 15 of 16

16 About Us Contact details Nicholas Steckler Chris Gadomski William Nelson Analyst, NA Power and Environmental Markets Head of Nuclear Analysis Head of Power, North America Copyright Bloomberg Finance L.P No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance L.P. Disclaimer This service is derived from selected public sources. Bloomberg Finance L.P. and its affiliates, in providing the service, believe that the information it uses comes from reliable sources, but do not guarantee the accuracy or completeness of this information, which is subject to change without notice, and nothing in this document shall be construed as such a guarantee. The statements in this service reflect the current judgment of the authors of the relevant articles or features, and do not necessarily reflect the opinion of Bloomberg Finance L.P., Bloomberg L.P. or any of their affiliates ( Bloomberg ). Bloomberg disclaims any liability arising from use of this document and/or its contents, and this service. Nothing herein shall constitute or be construed as an offering of financial instruments or as investment advice or recommendations by Bloomberg of an investment or other strategy (e.g., whether or not to buy, sell, or hold an investment). The information available through this service is not based on consideration of a subscriber s individual circumstances and should not be considered as information sufficient upon which to base an investment decision. BLOOMBERG, BLOOMBERG PROFESSIONAL, BLOOMBERG MARKETS, BLOOMBERG NEWS, BLOOMBERG ANYWHERE, BLOOMBERG TRADEBOOK, BLOOMBERG BONDTRADER, BLOOMBERG TELEVISION, BLOOMBERG RADIO, BLOOMBERG PRESS, BLOOMBERG.COM, BLOOMBERG NEW ENERGY FINANCE and NEW ENERGY FINANCE are trademarks and service marks of Bloomberg Finance L.P. or its subsidiaries. This service is provided by Bloomberg Finance L.P. and its affiliates. The data contained within this document, its contents and/or this service do not express an opinion on the future or projected value of any financial instrument and are not research recommendations (i.e., recommendations as to whether or not to buy, sell, hold, or to enter or not to enter into any other transaction involving any specific interest) or a recommendation as to an investment or other strategy. No aspect of this service is based on the consideration of a customer s individual circumstances. You should determine on your own whether you agree with the content of this document and any other data provided through this service. Employees involved in this service may hold positions in the companies covered by this service. Disclaimer notice on page 16 applies throughout. Page 16 of 16

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