Whilea generalized condition of surplus and low prices persists in most powermarkets, there are broad signs this is changing, with a summertime rally innatural gas signaling an easing of fuel surpluses, and plant retirements in keyregions bringing reserve margins into greater focus. Taken together, theseelements are positive for wholesale power prices and the generation sector.
Spot market recap
Thestrong June rally in natural gas prices supported spot power prices to close thesecond quarter of 2016, but much of the quarter otherwise saw natural gasprices substantially lower than the second quarter of 2015. On-peak spot powerprices for the second quarter of 2016 were therefore mostly lower across theboard compared to the same period last year. Cooling Degree Days were also 4%lower across the continental U.S. during the second quarter of 2016 than thesame period last year, putting downward pressure on load and associated powerprices.
Thecombination of lower natural gas prices, greater hydro availability andessentially flat load caused especially low power pricing in the West. Averageon-peak power prices at the SP15 hub in CAISO fell by nearly 20% year over yearfor the second quarter, while prices dropped by roughly 42% at Mid-Columbia.CDDs for the second quarter of 2016 were down 2% in CAISO, with average load up0.9% for the quarter. Year-to-date hydro generation in the Northwest is up3.5%, and contributions from renewable generation grew by 6%. In combination,these impacts pressured 2016 second-quarter spark spreads in the West downward,with SP15/SoCal Border down 24%, Mid-Columbia/Sumas down 55% and Palo Verde/ElPaso San Juan roughly flat. Spark spreads estimates reference a heat rate of7,000 Btu/kWh.
NYISOsaw little change in year-over-year load for the second quarter of 2016,despite a 14% increase in CDDs. Lower natural gas prices supported heat rateexpansion compared to the second quarter of 2015, with upstate New York sparkspreads (Zone G/Iroquois Zone 2) essentially unchanged and New York City (ZoneJ/Transco Zone 6 NY) spark spreads 8% higher. While the Northeast saw hotterweather during the second quarter of 2016, PJM's Mid-Atlantic statesexperienced an 8% decline in CDD compared to the second quarter of 2015.Average load in PJM therefore trended 1.3% lower year over year for the secondquarter of 2016, pressuring on-peak prices down nearly 17% and spark spreads(Western Hub/TCO Pool) down more than 10%.
InERCOT, year-over-year declines in on-peak power prices for the second quarterof 2016 lagged weakening spot natural gas prices, resulting in spark spreadsfor Houston Hub/Houston Ship Channel growing a modest 6.5%. ERCOT CDDs wereessentially flat relative to the second quarter of 2015, but average load wasup 2.4% as the drilling sector experienced a modest recovery. Firmer loads inthe region helped to offset the impact of lower natural gas prices.
MISOIndiana Hub bucked the broader trend of lower power prices, with a 21% increasein CDDs year over year for the second quarter of 2016 keeping pricesessentially flat. At the same time the price of regional natural gas fell morequickly than in other regions as greater shale supplies became available beginningin the summer of 2015. MISO therefore saw the greatest spark spread growth yearover year for the second quarter of 2016, with Indiana Hub/Lebanon Hub sparkspreads increasing by more than 34%. PJM's Northern Illinois Hub/ChicagoCitygate spark spread similarly increased, by nearly 28%.
Movements in market forwards
TheJune rally in natural gas was driven by a storage surplus that steadilydeclined in April and May, combined with hotter-than-normal weather duringJune. While overall second-quarter CDDs were 4% lower than the same period of2015, June 2016 CDD came in 5% higher than June 2015. Prospects for greater gasgeneration demand helped to boost natural gas prices by nearly $1/MMBtu fromhistoric lows experienced during the April-May shoulder months. Higher spotnatural gas prices pushed the futures strip higher as well, providing anacross-the-board boost to power forward curves. Quarter-over-quarter growth inthe Calendar 2017 on-peak contract ranged from approximately 3% to 19% in theEast, with NYISO markets showing the largest gains and PJM Western Hub andISONE Mass Hub on the lower end of the range.
Westernmarkets saw higher overall gains in Calendar 2017 power forwards quarter overquarter, ranging from 13.58% at SP15 up to 20.32% at Palo Verde. The HoustonHub Calendar 2017 forward gained 16.65%.
Gainsin the NYMEX natural gas futures strip were lower in 2018-2019, which wasreflected in smaller gains in Calendar 2018-2019 forward pricing benchmarks.Western Hub, Northern Illinois Hub and Mass Hub were mostly unchanged, whileremaining eastern hubs notched gains averaging 9.87% in 2018 and 4.45% in 2019.ERCOT Houston gained 8.37% in 2018 and 3.46% in 2019. Western market forwardgains ranged from 6% to 15% in the 2018-2019 Calendar years.
Forwardimplied spark spreads were mixed, as the impact of higher natural gas priceshad different regional impacts. PJM Western Hub saw forward spark spreads for2017 fall 5.92% as higher natural gas prices reduced the competitive advantageof shale. Mass Hub spark spreads fell substantially, by 18.68% in 2017, as thecontinued erosion of winter basis pressures generator revenues. Other easternmarkets saw gains, with Hudson Valley Zone G, up 24.64% for 2017, seeing substantialbenefit from lower natural gas prices and forward power supported by NYC Zone Jexport opportunities. ERCOT 2017-2019 spark spreads showed moderate gains, withHouston Zone averaging a 13% gain quarter over quarter.
InWestern markets, relatively strong power price growth drove substantialincreases in forward spark spreads, with Palo Verde averaging an increase ofapproximately 55% over 2017-2019, and SP15 notching a gain of more than 30%quarter over quarter. These large gains primarily reflect a boost in sparkspreads from very low levels to levels that still lag power markets in the Eastand ERCOT.
SNL Energy on-peak priceforecast
SNL Energy on-peak priceforecast
Thisquarter's relatively stable loads and higher natural gas prices generallyprovide a boost to spark spreads in most regions with some noteworthyexceptions. New gas-fired builds have tapered in most regions, while theannounced retirement of key nuclear plants provides price support to efficientnatural gas generation in 2017-2019.
PJMWestern Hub pricing is projected to increase in 2017 by approximately 8%relative to the prior quarter, with lesser gains in 2018-2019. On-peak energypricing is projected at $36.90/MWh, while 2018 on-peak average pricing gained4.77% to $36.15/MWh. Gains in forward natural gas prices closely match thechange in forecast power, leaving spark spreads at similar levels to the priorquarter's outlook. While a higher natural gas strip tends to support higherspark spreads, this is offset by increasing efficiency of natural gasgeneration and reduced regional export opportunities.
On-peakpricing at MISO's Indiana Hub is projected to be up roughly 3% to 6% in2017-2019 relative to the first quarter 2016 forecast. 2017 annual averageon-peak pricing is projected at $37.10/MWh, or an increase of 6.08% relative tothe prior quarter. Indiana Hub 2018-2019 pricing is projected to trend higherby 3.57% quarter over quarter to $37.38/MWh. Forecast spark spreads areconsistent with comparably dated forwards, as Indiana Hub is expected tobenefit from less expensive natural gas on MISO's eastern boundary sold intosomewhat higher-priced regions in MISO zones to the west.
SNLEnergy's Mass Hub on-peak power price forecast grew 10.26% compared to theprior quarter, with a higher natural gas strip creating more marginopportunities in the winter season in particular. SNL Energy projects Mass Hubat $48.98/MWh in 2017. From 2018-2019, SNL Energy projects more modest gains atMass Hub averaging 6.20% compared to the prior quarter. Increasing efficiencyof gas generation in the region and higher forward RGGI carbon prices tends tolimit spark spread growth after 2017.
Similarto Mass Hub, NYISO energy pricing at Zone G saw gains in the current quarterforecast versus the prior quarter, with the higher gas prices also beneficialfor forecast spark spreads. SNL Energy's average on-peak price forecast for2017 grew 11.66% to $49.31/MWh, with 2018-2019 forecast growth averaging 6.69%.SNL Energy's forecast on-peak spark spreads 2017-2019 show growth quarter overquarter, supported both by regional retirements and stronger wintertime gasprices.
SNLEnergy's on-peak pricing forecast in the Southern Company region shows modestgrowth of 3.98% quarter over quarter, at $38.24/MWh for 2017. From 2018-2019,forecast on-peak calendar year prices are virtually unchanged. Firmer powerprices against higher natural gas input costs drives modestly lower sparkspread forecasts for regional natural gas generation from 2017-2019, downroughly 4%. The relative stability of power prices is partly attributable tothe region's significant amount of coal generation, which becomes more economicat higher natural gas prices, tending to mitigate upward pressure on powerprices.
ERCOTHouston pricing is projected up 9.65% in 2017 compared to the prior quarter, at$37.50/MWh. The ERCOT Houston forecast on-peak prices in 2018-2019 average 3.88%higher quarter over quarter. With natural gas price declines reversing to gainsover the past quarter, SNL Energy projects that ERCOT spark spreads will belower for 2017-2018, by an average of just over 12%, before moving higher in2019. Higher natural gas prices during 2017-2018 are undercut by the region'sbase of coal capacity, as coal prices have not moved up as rapidly as naturalgas. By 2019 the combination of higher coal prices and modestly greaterscarcity contribute to higher spark spreads.
SPPSouth on-peak pricing is forecast higher quarter over quarter, by 9.07% in2017, which moderates in 2018-2019. This follows the quarter-over-quartermovement in Gulf Coast natural gas during this time. Forecast spark spreads arelargely unchanged quarter over quarter, as the change in natural gas vs. poweris comparable. SNL Energy projects that much of the Southwest Power Pool'sreserve surplus will erode by 2017-2018 due to regional coal and nuclearretirements, creating some upward price pressure.
SNLEnergy's forecast of on-peak pricing in the Western U.S. is modestly higherquarter over quarter on firmer forward natural gas prices. At SP15, SNL Energyforecasts 2017 on-peak pricing to grow 7.06% over the prior quarter's forecast,with 2018-2019 forecast for smaller gains. Palo Verde is forecast to follow asimilar pattern as SP15, with on-peak pricing in 2017 8.06% higher over theprior quarter. Mid-Columbia is forecast at 7.75% higher for 2017. Firmer forwardnatural gas prices in the West drives higher forecast spark spreads across theWest. Spark spreads are forecast roughly 8% higher in California, 15% higher atPalo Verde and 4% higher at Mid-Columbia. Similar-dated forwards are below SNLEnergy's projections, driving substantially lower implied forward spark spreads.
Regional supply, demand andcapacity prices
Plansfor new natural gas-fired projects in PJM continue to materialize. Dominion'sGreensville Power Station comprises most of the firm capacity added to theforecast for new generation coming online from 2016 through 2020. Retirementexpectations are also increased this quarter, with the Quad Cities nuclearretirement announcement being the largest new contributor to capacityreductions.
The netcapacity change projected for PJM RTO during the 2016 through 2020 period is1,423 MW, which is 585 MW higher than last quarter's forecast. Loadexpectations have not been updated since the reductions noted last quarter.
Thecapacity price forecast for the 2020-21 reliability year was revised downwardto $4.52/kW-month for RTO, while the COMED delivery area price held firm at$5.05/kW-month on tighter regional supply.
Capacityadditions projected for New York ISO from 2016 through 2020 remain modest, withrenewable energy dominating the 225 MW of new generation supply forecast tocome online during this period. Retirements in this quarter's forecast arehigher, due to the expected decommissioning of the James A. Fitzpatrick nuclearreactor. The potential of zero-emissions credits to influence retirementdecisions for Fitzpatrick and other New York state reactors will be closelymonitored ahead of next quarter's forecast.
Thenet supply change currently projected for NYISO during the 2016 through 2020reliability period is a contraction of 565 MW. Peak load expectations arerevised lower by an average of 1.5% per year over the same period, incomparison with last quarter's forecast, based on the latest NYISO "GoldBook" report.
Capacityprice expectations are down modestly for New York Control Area in the Winter2016-17 reliability period, from $3.01/kW-month in last quarter's forecast to$2.77/kW-month currently. Summer 2016-17 prices are not materially differentthan last quarter's forecast, at $4.70/kW-month for NYCA and $11.45/kW-monthfor New York City Zone J.
Firmnew projects in ISONE are similar to last quarter, with about 3.6 GW ofcapacity expected to come online during the 2016 through 2020 period, which isprimarily comprised of natural gas-fired units. Expected retirements are alsorelatively constant over the same time frame, with the Pilgrim nuclear reactordecommissioning in June 2019 being the single most notable reduction incapacity projected over the next five years.
Loadexpectations are lower by an average of 2.4% for the years of 2016 through 2020in comparison with last quarter's forecast, based on the latest Capacity,Energy, Loads and Transmission report.
Capacityprice projections for ISONE Rest-of-Pool are down significantly, from lastquarter's forecast of $7.17/kW-month to $5.25/kW-month, for the 2020-2021reliability year.
Firmnew capacity expected to begin operating in MISO over the 2016 through 2020time frame is materially similar to last quarter's forecast, with almost 2.5 GWof mostly gas-fired projects becoming available. However, retirements projectedfor the same time period are significantly higher, partially because of Exelon'splans to decommission the Clinton Power Station reactor by June 1, 2017.
Consequently,the decrease in capacity projected through the 2016 to 2020 time period isgreater than last quarter, with a net loss exceeding 4 GW. The current forecastindicates an escalated need for new build capacity in 2020, up from 2021 lastquarter.
Thistighter supply puts upward pressure on the notional value of capacity in the "classic"zones of MISO, where the average price forecast for the 2017-18 through 2019-20reliability years is up to $4.35/kW-month from $2.96/kW-month last quarter.
Thesupply and demand balance in the SERC-SE region is materially consistent withlast quarter, projected to grow by roughly 2.2 GW during the 2016 through 2020period. Reserve margins remain wide throughout the same period, in excess of30%.
Firmnew additions to supply in SPP are essentially unchanged from last quarter'sforecast, with about 1.2 GW of mostly gas-fired capacity projected to comeonline from 2016 through 2020. However, the retirement of Fort Calhoun NuclearStation tightens the net supply change expectations over this same period,increasing the projected capacity needed in 2020 from generic new-buildresources and raising the notional capacity price forecast for that year to$8.38/kW-month, from $7.39/kW-month last quarter.
Expectationsfor additional projects entering ERCOT are consistent in comparison with lastquarter, with more than 6.4 GW of new supply additions from 2016 through 2020.
Retirementsare also essentially flat, with generators postponing decisions, perhaps inhopes that other market participants will respond to lackluster scarcitysignals first.
Projectionscontinue to indicate that scarcity revenue will be sufficient to incentivizenew build in the 2021-22 time frame, averaging a $7.90/kW-month equivalentthose two years.
Netsupply change in California ISO during the 2016 through 2020 period isprojected to contract by about 5.2 GW, with retirements driven byonce-through-cooling regulations partially offset by substantial renewableenergy development.
Despitethis decline in generation supply, the state's 50% by 2030 RPS requirement isstill expected to virtually eliminate the incentive for new fossil-fueledgeneration to be built.
Theforecast utilizes the AuroraXMP tool to model a number of elements essentialfor the analysis of North American power markets. AuroraXMP is a power marketsimulation tool based on an hourly dispatch engine that simulates the dispatchof power plants in a chronological, multi-zone, transmission-constrained systemand is widely used for electric-market price forecasting, resource valuationand market risk analysis. More information on the power forecast methodologycan be found in the help section.
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