With both spot and forwardpower markets in decline due to low gas prices and declining load, thefollowing dynamics impact the trajectory of energy and capacity prices over thenext 20 years.
* In the Northeast,dependence on natural gas has caused expected spark spreads to decline. TheISO-NE rest-of-pool capacity market has weathered the loss of a nuclear unit byadding more gas-fired generators, putting downward pressure on the clearingprice. In New York, lower in-area requirements for Zone J have caused aprecipitous drop in the value of capacity in the city while the exit of Dunkirkin Western New York has contributed support to the New York Control Areaclearing price. PJM's upcoming base residual auction is expected to clear lowerthan last year's, on lower load expectations. MISO also revised its loadforecast downward, leading to convergence in the forecast for notional value ofcapacity in the "classic" RTO region.
* ERCOT spark spreadforecasts also declined relative to last quarter's outlook. This year could bea turning point for the market, as older, less economical units may retire dueto the lack of meaningful scarcity payments being produced by the OperatingReserve Demand Curve. If this happens, the reserve margin is expected to fallinto a range conducive to new investment by 2021-2022.
* In the West, power priceexpectations are down modestly. CAISO continues to be characterized by itsdevelopment of renewable energy resources, as hundreds of megawatts of solarwere again added to the forecast for this quarterly update. The CaliforniaRenewable Portfolio Standard is expected to make development of fossil-firedgeneration economically unattractive.
Spot market recap
On-peak spotpower prices for the first quarter of 2016 trended substantially lower incomparison with the same period last year across key eastern U.S. hubs, asmilder winter weather pressured both natural gas prices and loads downward.Heating Degree Days, or HDDs, were 18% lower across the continental U.S. duringthe first quarter of 2016 than the same period last year. The late winterperiod of 2015 was also warmer than normal, causing a surplus of natural gas tocarry forward into 2016, with resulting lower natural gas prices.
Average on-peak powerprices at the Mass Hub in ISO New England fell by more than 65% year over yearin the first quarter, while prices dropped by roughly 60% in NYISO. HDDs forthe first quarter were down 27% in ISONE. Relative natural gas prices fell evenfaster than power prices in ISONE, with Mass Hub-Algon Gates spark spreads fora benchmark 7,000 Btu/kWh natural gas combined cycle edging up to $5.38/MWh, a47% gain. All further discussion of spark spreads shall reference ahypothetical 7,000 Btu/kWh heat rate.
Weak load inNYISO caused spark spreads to decline, by more than 11% and 10% for HudsonValley-Iroquois Zone 2 and New York City-Transco Z6, respectively. With naturalgas prices having broad influence even in traditional coal regions, sparkspreads also declined by nearly 55% to $17/MWh for PJM Western Hub-TCO Pool andby more than 28% to $12/MWh for Indiana Hub-Lebanon gas.
In ERCOT, year-over-year declines in on-peak power prices for thefirst quarter of 2016 kept pace with weakening spot natural gas prices,resulting in essentially flat spark spreads for Houston Hub-Houston ShipChannel spark spreads, at $6.86/MWh.ERCOT load was down by 5% relative to the first quarter of 2015, as productioncutbacks in the oil sector along with mild winter temperatures, including HDDsdown 46% year over year for the quarter, impacted electric sales.
In contrast to load declines across Eastern RTOs, the West showedfirm to slightly higher loads. CAISO first-quarter load was essentially flat comparedwith the same period last year, with the Northwest up approximately 1.7%, withHDDs up 25%, in contrast to the milder Eastern U.S. Despite firmer demand,average on-peak power prices fell during the first quarter by nearly 25% to$24.74/MWh for the SP-15 hub in SouthernCalifornia. The Pacific Northwest's hydroelectric output trended lower yearover year, as it came off an exceptional amount of generation in 2015.First-quarter 2016 generation numbers from BPA were 16% less than the sameperiod in 2015. Lower gas prices dragged spot power prices down 14% to$17.75/MWh at Mid-Columbia. However, supportive load and scarce hydropowersupplies supported higher spark spreads for Mid-Columbia-NW Sumas. Sparkspreads and Mid-Columbia averaged $5.22/MWh,up 39% in comparison with the first quarter of 2015.
Movements inmarket forwards
While natural gas forwards continued to ease down quarter over quarter asthe mild winter pressured the strip, the declines were relatively modest. Thissuggests that production slowdowns and demand pressures associated with ongoinglow natural gas prices may be edging toward a turning point. Weak heatingseason demand has been the principal driver for recent low natural gas prices,but this weak demand has spilled over to the power sector as well, resulting incorresponding declines in power prices. Declines in the Calendar 2017 on-peakcontract ranged from approximately 2% to 12% in the East, with Northeastmarkets showing the steepest declines and PJM markets toward the lower end ofthe range. MISO Indiana Hub also fell 10.83% as low-priced shale gas supplygrew in the region, pressuring MISO forward natural gas strips. Western 2017forwards fell by roughly 1% to 7% quarter over quarter, with California and theNorthwest showing the larger declines. ERCOT's Houston Hub 2017 forwards eased2.38%.
Calendar2018-2019 forward pricing benchmarks showed more stability quarter over quarterat PJM hubs, with MISO Indiana Hub falling an average of 8%. Pricing hubs inNew York and New England continued to decline quarter over quarter, asincreased availability of forward gas in winter time impacts those Calendarstrips. ERCOT Houston fell further, by approximately 6%, as market expectationsof generation supply pressured the strip. Western market forward declinesranged from 2% to 10%.
Forward implied spark spreadsfell substantially across several regions, as lower power demand exertedgreater influence on spreads than lower natural gas prices. PJM West sawforward spark spreads for 2017 fall 5.70%. Penetration of shale gas had greaterinfluence on hubs in the Northeast and MISO. In the Northeast, rapid erosion ofwinter basis pushed down spark spreads, while MISO gas basis turned negative inconjunction with lower load expectations. The Northeast and MISO hubs sawdeclines in forward spark spreads of 19% to 25% for 2017. ERCOT 2017-2019 sparkspreads showed moderate declines, with Houston Zone averaging a 7% loss quarterover quarter.
In Western markets, relativelyfirm natural gas prices drove substantial declines in forward spark spreads,with SP-15 averaging a decline of approximately 25% over 2017-2019, andMid-Columbia dropping by more than 28% quarter over quarter for 2017-2019. PaloVerde Hub declines were more moderate on firmer demand.
On-peak price forecast
This quarter's mild winter and slackening prospects forlonger-term demand again pressured the natural gas strip. The March 31 powerprice forecast indicates firming market heat rates over the next few yearsrelative to the prior quarter forecast. New builds have tapered in key regions,providing more pricing support to efficient natural gas generation in2017-2018, while the 2016 outlook remains pressured both by low natural gasprices and a below-normal demand outlook for the first half of the year. Thisis particularly evident in the Northeast, but projected to a lesser degreeacross most markets.
PJM Western Hub pricing is projected to fall in 2017-2019 byapproximately 2.5% to 3.5% relative to the prior quarter, following lowerregional gas pricing. 2017 on-peak energy pricing is projected at $34.11/MWh,falling 2.74% versus the prior quarter, while 2018 on-peak average pricingdropped 2.55% to $34.50/MWh. With the forecast natural gas strip fallingsomewhat less than power prices across PJM, forecast spark spreads are 8%lower, quarter over quarter. This is mainly attributable to lower near-termdemand and higher reserve margins across PJM, which pressures the dispatch ofless efficient generation.
On-peak pricing at MISO's Indiana Hub is projected to bemodestly down at roughly 1.5% to 3.5% 2017-2019 relative to the fourth-quarter2015 forecast. 2017 annual average on-peak pricing is projected at $34.98/MWh,a decline of 1.43% relative to the prior quarter. Indiana Hub 2018-2019 pricingis projected to fall by 2.80% to $36.09/MWh quarter over quarter, again in linewith lower regional natural gas pricing. Spark spreads are forecast roughly 7%lower at Indiana Hub over this period, on lower projected demand.
Downward forecast movement in prices at ISO New England'sMass Hub was moderate quarter over quarter. Forward regional gas pricing isexpected to ease more than in other regions as inbound pipeline capacity growsand access to competitive shale gas improves. This is especially evident inwinter season natural gas pricing. Mass Hub is projected at $44.42/MWh in 2017,representing a 4.37% decline quarter over quarter. From 2018-2019, Mass Hub isprojected for steady declines ranging from 4.5% to 6.5%. A slightly lowerforecast of reserve margins supports generator spark spreads, but this is morethan offset by growing renewable generation and low projected load growth.Spark spreads are projected to be modestly down 5% from 2017-2019.
NYISO energy pricing at Zone G saw moderate declines in thecurrent quarter forecast versus the prior quarter, with the mild finish towinter pressuring natural gas prices lower. The 2017 average on-peak priceforecast fell 4.45% to $44.17/MWh, with 2018-2019 forecast declines averaging4.9%. The forecasted on-peak spark spreads 2017-2019 were down 6% quarter overquarter, as weaker 2017 projected demand more than offset falling gas pricesand lower reserve margins.
The on-peak pricing forecast in the Southern Company regionis largely unchanged quarter over quarter, at $36.78/MWh for 2017. From 2017-2019,on-peak calendar year prices are down less than a 1%. Firmer power pricesagainst lower natural gas input costs drives a modest improvement of roughly 1%in spark spread forecasts for regional natural gas generation from 2017-2019.This is partly attributable to a steady decline in reserves through 2018 asannounced coal retirements take effect. Reserve margins in the region areexpected to remain high even with these capacity reductions.
ERCOT Houston pricing is projected down roughly 2.5% to 5.0%in 2017-2018 compared to the prior quarter, with 2017 projected at $34.20/MWh.The ERCOT Houston forecast price in 2019 is 8.11% lower quarter over quarter.With natural gas prices declines moderating over the past quarter, ERCOT sparkspread projections have moved down for 2017-2019, by an average of just over8%. Comparable forwards indicate a similar trend in spark spreads, withdiminished demand and scarcity pricing expectations more than offsetting gainsin sparks from lower natural gas prices.
SPP South on-peak pricing is forecast lower roughly 1% to 3%quarter over quarter, following modest downward movement in Gulf Coast naturalgas during this time. Spark spreads show little movement quarter over quarterduring this time as the change in natural gas vs. power was comparable.Southwest Power Pool's reserve surplus is projected erode by 2019, creatingsome upward price pressure.
On-peak pricing projections in the Western U.S. are mostlyunchanged quarter over quarter on firmer forward natural gas prices. At SP-15,the forecasted 2017-2019 average on-peak pricing to fell to 1.40% over theprior quarter's forecast. Palo Verde followed a similar pattern as SP-15, withon-peak pricing in 2017-2019 averaging a 1.49% decline over the prior quarter.Pricing at Mid-Columbia is projected 1.56% lower over the same period. Firmerforward natural gas prices in the West drive the forecast to modestly lowerspark spreads. Spark spreads are forecast 1.5% to 3.0% lower in California andthe Southwest, with spark spread declines at Mid-Columbia ranging from 5% to8%. Similar-dated forwards are below the forecast, driving substantially lowerexpected spark spreads.
Regional supply,demand and capacity prices
* From 2016-2020, 13,255 MW of firm new projects areexpected to enter the PJM Interconnection. This is almost entirely comprised ofnatural-gas-fired units.
* Firm unit retirements are not materially different thanlast quarter, with coal units making up most of the expected decline. Adownward adjustment of more than 5,000 MW to the demand response assumed toqualify as capacity performance caused the net new supply expected during2016-2020 to decline by that amount, compared with last quarter's projection.
* Peak load expectations for 2016-2020 declined by anaverage of just over 3% per year, relative to last quarter for the same period,based on the RTO's most recent demand forecast.
* Capacity price expectations for the 2019/2020 auction wererevised lower from last quarter's view, to $3.62/kW-month from $4.30/kW-monthfor RTO.
* Expectations for the addition of new generating capacityin New York are materially in line with last quarter's forecast, as the regioncontinues to add small-scale renewable energy facilities.
* Retirement of units in 2016-2020 are projected to be flat,with two units at the C.R. Huntley coal plant making up most of the 382 MWexpected to exit the market. A notable retirement not included in the figureabove is that of three Dunkirk units in western New York that were previouslyplanned for conversion to natural gas. These retirements are assumed to occurbefore 2016 in the current forecast.
* Absent any updates to load expectations, the loss of theseunits provided support to the RTO capacity price forecast, sending the Winter2016/2017 price up to $3.01/kW-month, from $2.41/kW-month last quarter. In NYC,a lower in-area requirement led to materially lower prices, which are no longerprojected to separate from the G-J price in Winter 2016/17, down to$3.46/kW-month from $7.31/kW-month.
* Based on results from the 2019/2020 forward capacityauction, a significant amount of capacity was added to the forecast, relativeto last quarter's view. The bulk of this capacity comes from units that clearedthe auction, namely the Canal 3 CT project and combined cycle configurations atClear River Energy Center and Bridgeport Harbor Station.
* The most notable retirement added to the forecast isPilgrim Nuclear Power Station, a single reactor facility owned by EnergyWholesale Commodities. Pilgrim's exit in June 2019 does not offset the newentrants mentioned above, bringing the projected net supply change for2016-2020 up to 458 MW, significantly higher than the 24 MW expected lastquarter.
* Consequently, capacity price expectations for the2020/2021 reliability year have been revised downward, falling to$7.17/kW-month from the $9.08/kW-month expected in last quarter's view.
* The balance in MISO held relatively constant from lastquarter's forecast, with 2,602 MW of new supply and 4,703 MW of retirements andcapacity reductions expected in the 2016-2020 period. Net new supply wasrevised downward significantly, as Zone 7 is no longer projected to need forcedmodel builds for reliability purposes in this time frame.
* This change is partially attributable to a reduction inload expectations, which fell by an average of just over 2.4% per year acrossall of MISO for the 2016-2020 time period. New capacity added to the forecastin Zone 7 over the past two quarters also helped to raise its reserve margin.
* Consequently, capacity prices in Zone 7 are no longerprojected to separate from the rest of the classic MISO market. Overall, pricesin this region declined quarter over quarter, to an average of $3.08/kW-monthfor the 2016/2017 through 2019/2020 delivery years, from $4.73/kW-month lastquarter.
* Projects and retirements are not materially different fromlast quarter in the Southern Co. region, with just over 100 MW of solargenerating capacity added to the Southern Co. region since last quarter'sforecast for 2016-2020, all of it in the state of Georgia.
* Load projections were updated somewhat less bearishly thanother regions for this quarter's forecast, with declines averaging 1.89% peryear from 2016-2020.
* Despite reduced demand, this market is expected to remainrelatively oversupplied, with reserve margins hovering around 30% throughoutthe 2016-2020 period.
* Projects and retirements are flat in SPP relative to lastquarter, with the addition of 1,224 in firm new capacity and 2,159 MW ofpredominantly coal-fired capacity retiring from 2016-2020.
* The forecast continues to indicate a need for genericnew-build resources beginning in 2020, at which point the region's notionalcapacity prices are projected to rise to $7.39/kW-month.
* Projected capacity additions in ERCOT for the 2016-2020time frame continue to grow, in spite of the modest scarcity payments comingfrom the ORDC mechanism. Over 400 MW of firm new capacity was added to theforecast since last quarter, bringing the total builds projected for 2016-2020up to 6,641 MW, almost 6,000 MW of which will be gas-fired.
* The forecast continues to project 4,813 MW of capacityretirements and reductions in the region from 2016-2020, offsetting much of theprojected increase in supply for a net addition of 1,827 MW in those years.
* Scarcity pricing expectations for 2016-2020 did not changesignificantly from last quarter, with annual payments from 2016-2019 averagingnearly $3.32/kW-month and rising to over $5.66/kW-month in 2020, ahead of a projectedneed for additional capacity in 2021.
* 448 MW of solar generating capacity was added to theforecast in California ISO since last quarter, bringing the total expectationfor firm new supply in 2016-2020 up to 4,147 MW. State once-through coolingregulations are still expected to force enough retirements to offset theseadditions and cause net new supply to decline by over 5,000 MW during thisperiod.
* An update to load expectations reduced demand by anaverage of 2.59% per year for the 2016-2020 period, relative to last quarter'sforecast, placing additional downward pressure on the capacity price, bringingit down to an annual average of $0.94/kW-month from $1.19/kW-month.
The forecast utilizes the AuroraXMP tool to model a numberof elements essential for the analysis of North American power markets.AuroraXMP is a power market simulation tool based on an hourly dispatch enginethat simulates the dispatch of power plants in a chronological, multi-zone,transmission-constrained system and is widely used for electric-market priceforecasting, resource valuation and market risk analysis. More information onthe power forecast methodology can be found in the help section.