Spot market recap
Summer weather and associated electricity demand came in mostly lower than 2016, driving wholesale electricity prices and spark spreads lower. The West Coast was the exception, with higher summer load contributing to higher electricity prices. Weather was the primary driver of power prices, as natural gas prices were similar to the year-ago summer, continuing a period of relative market stability. Coal prices were similarly stable, with natural gas increasingly acting as a cap on price movement for domestic coal. With little movement in fuel costs, lower power prices served to depress generator spark spreads compared to the third quarter of 2016.
While the third quarter of 2016 trended consistently above normal, only July came close to matching cooling-degree-days, or CDD, on a year-over-year basis. August of this year came in close to normal nationally but significantly below August of 2016. The Northeast and Midwest led all decliners, with CDD lower than the third quarter of 2016 by more than 30%. Correspondingly, demand was much lower in the Northeast, with PJM down 7.6%, NYISO down 8.2% and ISO-NE down 8.3% compared to the same period in 2016. MISO was down a more modest 4.2%. Moving further west, ERCOT came in similar to 2016, with CDD down on 0.9%, and CAISO higher by 1.9% on warmer weather.
With some regional exceptions, fuel prices were mostly unchanged. Setting aside wintertime volatility to end 2016, natural gas prices have held steady since the summer of 2016, with Henry Hub mostly trading between $2.90/ MMBtu and $3.15/MMBtu. These price levels persisted even as storage levels worked back to normal following the large surpluses of 2016. Broadly speaking, reduced gas volumes to the generation sector due to competition from coal has offset production cutbacks from shale regions to produce a modest net effect on natural gas prices through the third quarter of 2017.
Many regions, therefore, saw lower spark spreads on lower demand. NYISO led all decliners (spark spread down 32%) with a combination of substantially higher natural gas prices, bucking the national trend, and lower loads year over year for third quarter 2017. Mass Hub saw on-peak power prices and spark spreads fall 25%, as lower loads more than offset lower natural gas prices. The West fared better on stronger demand, with SP15 power prices increasing by over 23% and spark spreads growing by over 75%. Spark spread estimates reference a heat rate of 7,000 Btu/kWh.
The Midwest saw lower power prices and correspondingly lower spark spreads, with PJM Western Hub on-peak electricity prices down 8% and spark spreads down by nearly 18%; PJM NI Hub electricity prices were down nearly 7% with spark spreads falling by over 16%. Indiana Hub was the exception to the general trends, with on-peak prices over 6% higher year over year for the quarter and spark spreads up over 10% despite lower demand and stable fuel prices. This region — Indiana, Ohio, and Kentucky — has experienced more retirements than additions recently, and higher pricing may reflect transmission constraints.
Higher loads in the West resulted in sustainable spark spreads across the board, with SP15 leading all gainers as noted above. Mid-Columbia year-over-year power prices grew by nearly 18% in the third quarter, with spark spreads increasing by over 40%, while Palo Verde prices increased by over 25% and spark spreads grew by 58%. With retirements expected to outpace capacity additions outside California over the next few years, stronger spark spreads may persist if loads firm up.
After a strong second quarter of 2017, ERCOT's summer came in similar to 2016, with only modest movements in power pricing and spark spreads.
Movements in market forwards
Summer demand during the third quarter provided the main driver for forward power prices, with calendar on-peak strips moving lower in the East and generally higher in the West.
In eastern markets, quarter-over-quarter movement in forward power prices followed mostly lower spot power prices. Northeast hubs fell the most, with Mass Hub and NYISO Hudson Valley declining 2.5-6.0% for Calendar 2018-2019. PJM had modest gains, with Western Hub and N Illinois Hub Calendar 2018-2019 up 1.6-2.0%. Indiana Hub forwards were mostly unchanged.
The boost in Western spot markets over the summer was reflected in forwards, with a 7.6% increase in the Calendar 2018 on-peak forward at SP15 and modestly higher forwards at Palo Verde. Mid-Columbia forwards were down modestly. ERCOT forwards weakened substantially as another summer passed without meaningful scarcity contributions as Houston Zone Calendar 2018 fell by over 8%.
Three markets showed meaningful declines in forward implied spark spreads, with demand weakness weighing in particular on Mass Hub and Hudson Valley. In these markets, forward spark spreads have fallen close to single-digit levels, a sign of an unsustainable wholesale market. ERCOT has moved from sustainable forward spark spreads to weak levels, also on perceived demand weakness. On the positive side of the spark spread ledger, SP15 forwards showed the biggest gains but remained unsustainably low. Palo Verde, long mired in single digit forward spark spreads, has improved above the $10/MWh mark.
SNL Energy on-peak price forecast
With only modest changes in the natural gas forward strip and normalized projections of electricity demand, changes in the near-term power price forecast were relatively modest quarter-over-quarter. This results in the third-quarter power forecasts trending higher than comparably-dated forwards, with some exceptions.
PJM Western Hub pricing is projected higher in 2018 (2.01%) relative to the prior quarter, with only slight changes 2019-2020. On-peak energy pricing in 2018 is projected at $35.44/MWh, while 2019 on-peak average pricing is projected 0.61% higher quarter over quarter at $32.43/MWh. It is noteworthy that the trend of narrowing natural gas basis discounts highlighted previously has reversed in the near term, possibly signaling growing shale supply and downward pressure on regional power prices.
On-peak pricing at MISO's Indiana Hub is projected 1.94% higher in 2018 relative to the forecast from the second quarter of 2017. The 2018 annual average on-peak pricing is projected at $38.03/MWh. Indiana Hub 2019-2020 pricing is projected modestly downward compared to last quarter. With stable to declining natural gas prices, forecast spark spreads are growing modestly and pushing toward more sustainable levels.
Forward regional natural gas prices in ISO-NE surged for the 2017 winter, but otherwise moved only modestly for forward years, over the quarter. Correspondingly, Mass Hub's quarter-over-quarter change in the on-peak power forecast was small, decreasing by 1.93% for Calendar 2018. The Power Forecast projects Mass Hub at $45.68/MWh in 2018, with similar declines in 2019-2020 compared to the prior quarter. Forecast spark spreads for Mass Hub are somewhat higher than 2018-2020 forwards.
Forecast NYISO energy pricing at Zone G was lower in the current quarter versus the prior quarter. The Power Forecast projects the average on-peak price forecast for 2018 2.37% lower than the prior quarter at $45.45/MWh, with similar 2019-2020 price declines. As forward declines were steeper than forecast declines, forecast spark spreads are somewhat higher than comparably-dated forwards.
The on-peak price forecast in the Southern Company region gained 3.03% quarter over quarter, at $39.78/MWh for 2018. From 2019-2020, forecast on-peak calendar year prices also increased quarter-over-quarter, up 1.5% on average. Higher coal prices represent the primary driver of this change; while most coal prices have been stable, long-haul, high-rank coal has held firm due to stronger export markets.
ERCOT Houston pricing is projected down 2.00% in 2018 compared to the prior quarter, at $35.65/MWh. The forecast projects some shifting of scarcity pricing forward, from 2020 to 2019, with the 2019 on-peak forecast higher by 11.29% this quarter ($48.65/MWh), and 2020 down 1.99% ($51.19/MWh). Scarcity is projected higher in 2019 on plant retirements at J.T. Deely and Decker Creek, with new additions somewhat lagging. This forecast does not reflect recent announcements of coal plant deactivations by Vistra Energy, which occurred after the third-quarter close and are expected to be adjudicated by the ERCOT ISO during the fourth quarter. Comparably dated forwards are very similar to the forecast for 2018 but show lower expected power prices and essentially no growth in scarcity pricing in 2019-2020. Forward spark spreads are correspondingly lower than forecast spark spreads.
SPP South on-peak pricing is forecast lower quarter over quarter, down 3.94% in 2018 and down an average of 5.4% in 2019-2020. Recent updates to SPP's load forecast indicates lower expected demand and rates of demand growth, putting downward pressure on prices compared to the prior quarter.
Power Forecast projections for on-peak pricing in the Western U.S. are higher quarter over quarter in 2018, as regional retirements puts more expensive generation on the margin, California's carbon pricing exerts broader influence, and natural gas prices tick higher. At SP15, the Power Forecast projects 2018 on-peak pricing 2.14% higher than the prior quarter's forecast, while Palo Verde on-peak pricing in 2018 is forecast 1.17% higher than the prior quarter. Mid-Columbia is forecast at 1.48% higher for 2018. Similar-dated forwards are roughly $3-$7/MWh below the Power Forecast projections for 2018, driving lower implied forward spark spreads than the forecast projections.
Regional supply, demand, and capacity prices
The largest announced retirement is Three Mile Island, at 827 MW, with a projected deactivation date of September 2019. This retirement is expected to have minimal to no impact on energy or capacity prices.
The major firm additional capacity additions are the 1,059 MW CPV Fairview Energy Center and the 1,059 MW Hickory Run Energy Station. Both plants continue to add to natural gas combined-cycle capacity in Pennsylvania, as the total resource base for this plant type approaches 19 GW in the state.
Forecasted near-term RTO capacity prices are expected to hover around $100/MW-day, with the COMED and EMAAC locational delivery areas remaining as breakout regions at approximately $150/MW-day and $190/MW-day, respectively.
While no finalized rule is in place regarding the Department of Energy's Grid Resiliency Pricing Rule, PJM is one of the key major markets that the rule would directly address. This could have major implications on the approximately 58-GW coal and 34-GW nuclear capacity in the RTO.
There are no major capacity additions or retirements since last quarter's update. Indian Point Units 2 and 3 are expected to retire in 2020 and 2021, respectively. The majority of this Zone G-J capacity deficit will be provided by CPV Valley and Cricket Valley combined cycle plants.
Projections on capacity prices are stable throughout the near-term with Rest-of-State remaining in the $3/kW-month range and Zone J, covering New York City, in the $9/kW-month range.
The 83 MW of new firm solar and 2.2 MW of new firm wind contributed to the bulk of the capacity additions in ISO-NE. With no final decision from Dominion or legislation passed in Connecticut, the 2.1 GW Millstone nuclear power plant continues to generate energy in the forecast.
With no major capacity changes and load projected to be flat, the capacity price forecast remains stable, ranging from $5.25/kW-month for the 2021/2022 reliability year and averaging $4.8/kW-month from 2022 to 2025.
Reserve margins in MISO Zone 7 tighten forcing 1.2 GW of natural-gas combined cycle capacity to be built by 2022. With MISO Classic zones clearing approximately $2.6/kW-month for capacity prices, MISO Zone 7 is projected to clear at nearly twice that level at $4.7/kW-month. MISO South zones continue to clear at depressed levels, hovering around $1/kW-month.
The Alvin W. Vogtle plant expansion is expected to be completed in 2021 through 2022, even with the bankruptcy of the plant's lead contractor, Toshiba's Westinghouse nuclear division. The reserve margin will remain high in the Southern Company region, with values not projected to drop below 30% before 2023.
The decision by SCANA and Santee Cooper to abandon the completion of Units 2 and 3 of the V.C. Summer nuclear plant removes 2,234 MW from the long-term capacity picture for the southeast United States. Without these units, the market begins to tighten by 2024, requiring additional capacity to be built.
The system coincident peak load forecast was revised downward on average by 3.5 GW (6.1%) through 2021. This reduction in the forecast load causes the reserve margin to increase to above 20% in the near-term and is projected to remain above 15% through 2024. The robust supply in the region causes notional capacity prices to remain at the $3/kW-month range. Almost 1 GW of natural gas peaking capacity is expected to be added through 2020.
The 2,000-MW Wind Catcher Wind Farm adds significant capacity to SPP in 2020, contributing to reserve margins above 18% through 2021.
ERCOT reserve margins remain above 20% through 2018. Robust demand growth tightens reserve margins causing notional capacity prices in ERCOT to reach $7.22/kW-month in 2019.
The proposal by Vistra to retire Monticello (1,865 MW), Big Brown (1,208 MW) and Sandow (1,200 MW) is not reflected in the third-quarter forecast. Should the ERCOT ISO approve these retirements, they would remove a cumulative 4.2 GW, which would tighten reserve margins by approximately 5%. Combined with the previously announced retirements of J.T. Deely and Decker Creek in 2019, this development could create reserve deficit conditions in ERCOT.
With increasing renewables penetration continuing to put downward pressure on wholesale power prices, over 1.4 GW of gas-fired peaking capability is economically retired through 2021.
Even with once-through-cooling and economic retirements, the reserve margin remains above 20% after 2019.