PJM Capacity Auction Results: PEG, EXC & CPN Win Temporarily, But IPPs Still Lose Going Forward – Downgrading CPN and Cautious on DYN

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Eric Selmon Hugh Wynne

Office: +1-646-843-7200 Office: +1-917-999-8556

Email: eselmon@ssrllc.com Email: hwynne@ssrllc.com



May 24, 2017

PJM Capacity Auction Results: PEG, EXC & CPN Win Temporarily, But IPPs Still Lose Going Forward – Downgrading CPN and Cautious on DYN

We calculate that the results of PJM’s 2020/2021 capacity auction will be positive for PEG, EXC and CPN, but slightly negative for DYN and NRG. We see the 2020/21 auction results adding $0.15 to PEG’s EPS over the 2020/2021 energy year (June 1, 2020 through May 31, 2021), equivalent to 5% of 2020 consensus; $0.10 to EXC’s EPS in 2020/2021, or 3% of 2020 consensus; and $110 million to CPN’s EBITDA, or ~6% of 2017 EBITDA. Most of DYN’s capacity in the Duke Energy Ohio and Kentucky zone did not clear, and we estimate that DYN will see a decline in 2020/2021 EBITDA of almost $60 million, or ~5% of 2017 EBITDA. NRG should suffer a $40 million loss in revenues, assuming its restructuring of GenOn is completed. We are adding CPN to our list of least preferred names and highlighting our concerns on DYN, although in light of the potential for acquisition by Vistra Energy (VST) we are not downgrading the stock.

Portfolio Manager’s Summary

  • Yesterday, PJM released the results of the Reliability Pricing Model (RPM) Base Residual Auction (BRA), its capacity market, for 2020/21. Prices spiked higher in Eastern MAAC (EMAAC), a zone covering New Jersey, Delaware, Eastern Maryland and Southeastern Pennsylvania, and in Duke Energy’s Ohio and Kentucky zone (DEOK). Prices fell materially in MAAC and the Rest of RTO region, and slightly in ComEd. (See Exhibits 1 and 2.)

Exhibit 1: Auction Results and Impacts on the Most Impacted Generators

Source: PJM RTO, SSR analysis

Exhibit 2: 2020/2021 Base Residual Auction Results

Source: PJM RTO, SSR analysis

  • In total, 165.1 GW of capacity cleared in the auction, down 2.2 GW from the year before, in line with the decline in the forecast peak demand versus the previous auction.
    • A net total of 3.3 GW of generation capacity that cleared in the prior auction appears not to have cleared this year.
    • In addition, demand response declined by 2.5 GW, reflecting the stricter capacity performance (CP) requirements imposed in this year’s auction.
    • Offsetting these declines, 2.4 GW of new generation capacity cleared in the auction, primarily combined cycle gas turbines (CCGTs), plus 0.4 GW of uprates at existing generating units, 0.2 GW of additional energy efficiency and 0.1 GW of additional imports.
  • Nevertheless, we see the higher prices in EMAAC and DEOK as likely temporary.
    • PJM results have been volatile with significant pricing differentials generally only lasting two or three years, at most.
    • EMAAC and ComEd pricing is at levels that should begin to attract new generating capacity over the next few years.
    • DEOK is a small zone in the center of a well supplied region, so small transmission improvements should eliminate the higher pricing.
    • Demand forecasts could still come down in future auctions, although the declines should be smaller than in recent years.
    • High pricing in EMAAC could also encourage NJ and MD to support storage investments by the local utilities that, while not able to count as capacity resources, would reduce peak demand, thereby lowering capacity pricing in their zones and potentially causing EMAAC to clear with the rest of PJM.
  • We expect CPN, EXC and PEG to see net increases in capacity revenues in the 2020/2021 energy year (June 1, 2020 through May 31, 2021) compared to 2019/2020
    • PEG’s pre-tax income should rise by ~$130 million in 2020/2021, or $0.17 per share, equivalent to ~6% of consensus 2020 EPS.
    • EXC should see a ~$140 million increase in pre-tax earnings in 2020/2021, or ~$0.10 per share, equivalent to ~2% of consensus 2020 EPS.
    • CPN’s EBITDA should increase by ~$110 million in 2020/2021, or the equivalent of ~6% of 2017 EBITDA, due both to the concentration of its assets in EMAAC and an increase in capacity that cleared in EMAAC.
  • We expect DYN and NRG to see net decreases in capacity revenues in 2020/2021.
    • We expect DYN’s EBITDA to fall by almost $60 million in 2020/2021 (~5% of 2017 EBITDA), reflecting a decrease in cleared generation capacity.
      • In DEOK, where prices spiked higher in this year’s auction, DYN controls three plants that comprise 2.5 GW of the 3.7 GW of generation capacity in that region. However, DYN announced after the auction that only 922 MW of this capacity cleared.
      • With less capacity clearing in the DEOK and the Rest of RTO regions, and much of the capacity that did clear located in ComEd, where prices also fell, we expect DYN’s PJM capacity revenues to be materially lower in 2020/2021.
    • NRG should suffer a ~$40 million loss in revenues, reflecting its recent agreement to restructure and exit the bulk of its PJM generation capacity.
      • Yesterday NRG announced a settlement with debtholders of its GenOn subsidiary, which should result in the elimination of GenOn’s debt in return for ~$300 million of cash and other commitments plus all of GenOn’s generating assets, which make up the bulk of NRG’s PJM generation.
        • Since GenOn was only expected to generate $150 million of EBITDA in 2017, the elimination of ~$2.5 billion of debt should be accretive to NRG’s equity value.
      • Without the GenOn restructuring, NRG would suffer an ~$100 million revenue loss.
      • We still view NRG as significantly overvalued, even in a private market transaction.
  • We are adding CPN to our list of least preferred names due to its high leverage (~6.3x Debt/ 2017 EBITDA) and valuation (8.8x EV/2017 EBITDA) and its exposure to negative trends in the power markets, particularly in California.
    • The benefit from the 2020/21 PJM capacity auction may be temporary for the reasons noted above and is mostly offset by lower pricing in the 2020/21 New England capacity auction run this past February. Even if the benefit were permanent, CPN would still be over-levered at 6.0x Debt/EBITDA and expensive at 8.3x EV/EBITDA
    • Moreover, we believe CPN to be at risk from revenue erosion over the next several years. We expect the output of existing gas fired power plants to fall in most competitive markets as new CCGTs and renewables come online and demand continues to stagnate.
    • With almost 65% of its generation capacity located in ERCOT, CAISO and ISO New England, CPN is the most vulnerable to increased renewable generation, particularly solar. The potential deployment of storage in these markets could aggravate the revenue loss to CPN by suppressing peak hour prices.
    • We also expect CPN will find it challenging to effect a sale of the company:
      • Market power concerns and leverage issues will likely prevent other IPPs from acquiring CPN’s assets; the buyer would probably have to be a private equity investor.
      • CPN’s high leverage and the potential deterioration in cash flows from lower generation output would limit the acquirer’s ability to lever up CPN further.
      • All of the available cash would have to go to paying down debt for the next several years, limiting the near term distributions and total returns to the buyer.
      • Finally, the probability of continued weakness and potential deterioration in the power markets limits the exit opportunities for the acquirer.
  • Given our expectation of persistent weakness in the competitive power markets going forward, we would also avoid DYN. We are not adding DYN to our list of least preferred names, however, due to the potential for acquisition by Vistra Energy (VST).
    • At ~8x EV/EBITDA, DYN is also expensive and its leverage at ~7x Debt/EBITDA is even higher than CPN.
    • While currently offering a free cash flow yield of ~30%, post-2018 we see cash flows and EBITDA declining at DYN due to lower generation output and capacity revenues in the key PJM and New England markets.
    • More importantly for a private buyer, due to DYN’s high leverage, all of the declining excess cash flows will need to go to paying down debt.
    • However, DYN and VST are reported to be in merger talks and we believe VST has the balance sheet capacity to make a temporarily accretive deal at a 20-30% premium to DYN’s current share price. This deal could still fall through due to limited synergies (DYN already has very lean operations) and more attractive acquisition opportunities for VST in acquiring individual generating assets.
  • The sharply lower prices in the Rest of RTO region should be negative for FirstEnergy’s (FE’s) generation subsidiary, FirstEnergy Solutions (FES) as well. However, we do not expect this over-levered and money losing subsidiary to be a part of FE by 2020.

Exhibit 3: Heat Map: Preferences Among Utilities, IPP and Clean Technology

Source: SSR analysis

©2017, SSR LLC, 225 High Ridge Road, Stamford, CT 06905. All rights reserved. The information contained in this report has been obtained from sources believed to be reliable, and its accuracy and completeness is not guaranteed. No representation or warranty, express or implied, is made as to the fairness, accuracy, completeness or correctness of the information and opinions contained herein.  The views and other information provided are subject to change without notice.  This report is issued without regard to the specific investment objectives, financial situation or particular needs of any specific recipient and is not construed as a solicitation or an offer to buy or sell any securities or related financial instruments. Past performance is not necessarily a guide to future results.

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