Energy Procurement Insights for October 2017: See What's Driving Prices in Your Region

Energy markets are complex, and it can be difficult to find useful information to inform the energy procurement strategy for your organization. What you need is detailed information on the factors driving prices in the region where your facilities are located.

Every month,Enel X's Energy Intelligence team develops in-depth reports on activity in individual energy markets. Here you can read the highlights for this month and access the full report for each region. Just click on one of the tabs above to jump directly to a specific region.

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New England
2017 Summer Peak Projected to be Lowest on Record

Preliminary data released by ISO-NE projects the hourly peak demand for the 2017 summer season to be the lowest on record. The projected of 23,717 MWs (June 13, 2017 Hour Ending 17:00) would be 1 MW lower than the previous low hourly peak demand set in 2004. ISO-NE will reveal the official peak hour in February.

A facility’s demand during that peak hour will determine their share of capacity costs for the 2018/2019 planning year. Weather and economic factors are the primary drivers for fluctuations in energy demand—weather affects near-term demand, while economic factors typically exert their influence on longer time horizons. Peak demand in particular tends to follow a period of sustained heat and relatively high humidity, which drive up energy consumption from air conditioning systems. The highest peak on record for the region—over 28 GW—occurred on August 2, 2006, when the temperature in Boston was 97 degrees Fahrenheit following 6 consecutive days of average temperatures near 90 degrees. Prior to this summer, since system peaks began being recorded in 2001, eight have occurred in August and seven in July. If this summer’s peak holds, it would be only the second peak in June and the first since 2008.

While a customer’s demand during system peak and the Forward Capacity Auction zonal clearing price are the main determinants of capacity costs, this summer’s low overall demand will heighten the impact of the Reserve Margin, another component in the capacity cost calculation. Since the Forward Capacity Auction procures a certain number of MWs based on projected system demand, actual demand must be grossed up by the reserve margin to account for the difference. The lower the actual demand relative to the number of MWs procured in the auction, the higher the Reserve Margin will be. Typically, the Reserve Margin has fallen between 20% and 30%, but is currently being projected to land above 40% for 2018/2019. For customers with capacity pass-through contracts or even customers seeking fixed-price contracts, which span the 2018/2019 delivery, the increased reserve margin will increase projected capacity costs, all else being equal.

For further updates on the electricity and natural gas markets, read our full report for this month.

New York
NYISO Announces Results of Winter 2017/18 Strip

On October 3rd, the NYISO published the results of the Winter 2017/18 Capacity Strip Auction. The auction is used to set the prices of capacity for Load Serving Entities (LSE’s) and their customers for the November 2018 through April 2019 period.

Capacity prices in New York vary by time of year and by physical location. In the summer period (May through October) when demand is higher, capacity prices are more expensive. Prices are also generally higher in New York City than in Lower Hudson Valley and the Rest-of-State capacity zones.

The Winter 2017/18 capacity auction generated historically low prices. The NYC zone cleared at $3.10/kW-Month, down 40 cents from the previous winter. The Lower Hudson Valley zone cleared at $2.70/kW-Month, down 80 cents from last winter. The New York Control Area (NYCA) zone, which serves the Rest-of-State customers, cleared at just $0.37/kW-Month, down 38 cents from last winter. The clearing prices were the lowest on record in their respective regions since the NYISO created the capacity markets.

Future markets also show a continued trend of historically low capacity prices across New York for the upcoming summer strip. Low capacity prices are a result of sufficient generation, which has been aided by lower demand as well as the Zero-Emission Credit (ZEC) program, which has kept the upstate nuclear plants from closing. Capacity charges make up approximately 25% of a customer’s supply rate, but will vary from account to account.

With capacity prices at historic lows, now is an attractive time to go to market and fix supply costs through a competitive third-party supplier.

For further updates on the electricity and natural gas markets, read our full report for this month.

PJM Releases First Incremental Auction Results for Delivery Year 2019/20 Capacity

On September 22, PJM posted the 2019/20 first incremental auction results for capacity requirements. All zones in the RTO saw a very slight increase (<1%) to the Base Residual Auction results, as depicted in the chart below. Currently, PJM provides a Base Residual Auction, and three incremental auctions to true up capacity for each delivery year. Customers should be informed that capacity clearing prices have risen slightly in delivery year 2019/20, although all clearing prices for 2019/20 are still lower when compared to the prior delivery year 2018/19.

For further updates on the electricity and natural gas markets, read our full report for this month.

MISO Price Volatility on Weather-Driven Demand

The second half of September brought unseasonably warm weather to the Midwest, with some locations experiencing temperatures 15 degrees or more above normal. The above-average temperatures had a significant impact on electricity customers in the region, driving increases in utility loads and real-time market prices. The table below highlights Cooling Degree Days (CDDs) from a few selected cities, which capture the daily temperature deviation from 65°F and are associated with cooling demand.

The Midcontinent Independent System Operator (MISO) declared a conservative operations notification on September 21st and extended the protocol through September 26th. Warnings were issued daily for Max Gen Alert during this time period, citing above-average demand, generation forced outages, and warmer-than-average temperatures. Max Gen Alerts are called by MISO when they forecast potential capacity shortfalls and could lead to supply disruptions if conditions deteriorate.

With the transition from summer to fall, many generators use the opportunity of lower demand to perform routine maintenance and refueling. MISO’s ability to meet volatile increases in demand becomes difficult as larger resources shut down for repairs. The chart below shows the forecasted capacity margin and selected Real-Time Locational Marginal Prices (RT LMP) at the peak hour for each day surrounding the call for conservative operations. The blue bars show the total load obligation for the highest usage hour each day. The capacity margin, represented by the green bars, reflects the excess generation available to meet demand in a peak hour. Each of the lines on the chart represent LMPs for different market price hubs. September 21st saw the highest hourly LMP prices in Indiana Hub ($785.42/MWh) and PJM West Hub ($674.06/MWh), while LMPs in the region remained elevated through the event. Prices blew out on the 21st due to significant real-time market purchases. Real-time incremental external market purchases were almost 2,200 MW flowing into MISO, driving prices up in surrounding markets. Even with the tighter capacity margin on September 22nd, most market purchases were scheduled day-ahead, leaving only roughly 200 MW exposed to real-time prices.

The two main factors contributing to this volatile price event are the available capacity and LMP market redesign. As mentioned above, the higher demand had caught the market off-guard, with several resources unable to react to dispatch signals due to planned or forced maintenance outages. In each of the conservative operations days, the resources used to ramp up to meet demand were primarily natural gas generators and “other” resources like gas/oil-fired combustion turbines. This is compounded by the change in the way LMPs are calculated.

Earlier this year, an LMP market redesign known as the Extended Locational Marginal Pricing (ELMP) Phase II was implemented. The goal of this market redesign was to reduce uplift charges that subsidize medium to longer start-up resources. The uplift charges make up for the difference between the market clearing price and the actual operating costs (mainly start-up costs) of a dispatched resource. Depending on what the generation resource stack looks like, as resources lower on the stack shut down for outage while leaving higher cost resources available, pricing during peak hours with tighter capacity margins could become more volatile.

Looking ahead, customers who have exposure to the market through a partially or fully indexed position should anticipate the potential for significant cost increases for bill cycles that include the last two weeks of September. Forecasts for warmer-than-normal weather during tighter capacity margin periods could add to the potential for additional max generation events and volatile pricing.

For further updates on the electricity and natural gas markets, read our full report for this month.

ERCOT Expected to Have Ample Resources for Record Winter Load

The Electric Reliability Council of Texas anticipates record load levels in the upcoming winter, but expects to have sufficient capacity to meet its needs even under the most extreme load and generation outage scenarios, the grid operator recently stated.

In its latest Seasonal Assessment of Resource Adequacy (SARA) report for the winter months of December through February, the grid operator projected peak load would reach 61.1 GW, compared with the current winter record of just over 59 GW set on January 6th. However, ERCOT expects total available generation resources to top 84 GW this winter.

The SARA report studies multiple scenarios that could impact the availability of generation resources on the ERCOT system.

Under the highest expected demand and generation scenarios, with estimated outages of 7.6 GW, the capacity available for operating reserve—the surplus to demand—would be 16.1 GW.

Even under the most extreme case scenario, and using 2011 winter events as a guideline, with load increasing 5.7 GW and additional outages of 4.6 GW due to extreme low temperatures, capacity could still exceed demand by 5.9 GW this winter, the grid operator said. That is more than double the emergency level of 2.3 GW, which would see ERCOT declare an Energy Emergency Alert, which includes calling for energy conservation and importing power from neighboring grids to maintain reliability.

On the supply side, ERCOT estimated 2.2 GW of new capacity would be added between now and the start of the winter season. Of those additions, wind generation would comprise 1.3 GW, while 0.7 GW would be gas-fired resources and 0.2 GW would be solar generation.

ERCOT also added that it did not expect Hurricane Harvey to impair system-wide generation availability for the upcoming winter season.

As generation capacity has come online at an increased rate over the past five years and very limited retirements have been experienced, ERCOT’s reserve margin should remain well supplied in the near future. Resource shortages across the winter months are rare despite maintenance outages and occasional extreme weather events.

For further updates on electricity and natural gas markets, read our full report for this month.

California Proposes Plan to Incentivize Load-Shifting Product for Energy Storage

In California, the growth of renewable energy has fundamentally changed the shape of the generation stack. For instance, the influx of hydro and solar generation over the course of the last year has caused higher incidents of negative spot pricing and created a new market dynamic known as the Duck Curve. The Duck Curve, named for the distinctive shape of net load generation, typically occurs mid-day when solar generation floods the grid and causes a deep dive in net load during the day, followed by a steep ramp-up in the late afternoon.

During these events, natural gas power plants have struggled to stay online. This not only impacts resource reliability, but also depresses the ability for these plants to stay profitable. Additionally, negative spot pricing indicates that the market is out of balance and that demand isn’t meeting supply.

To alleviate these concerns, the CAISO proposed a new solution to encourage the use of energy storage systems. During the duck curve, the storage resource would absorb excess energy from the grid. This should stabilize the market during that time and allow traditional generation resources to remain profitable. Furthermore, during times of tight supply, these batteries can make the excess energy available, which should provide price relief during peak pricing events. Ultimately, implementing this type of program would smooth out the duck curve, thereby balancing the grid and stabilizing pricing.

At this time, this proposed ruling will have no immediate impact on customers. However, if passed, this could mark a significant improvement to real-time pricing and provide long-term benefits to all market stakeholders.

For further updates on electricity and natural gas markets, read our full report for this month.

CFE Default Rates Increase for Commercial and Industrial Customers in October

The Mexican utility, the Comisión Federal de Electricidad (CFE), announced that the default electricity prices for commercial and industrial users will increase in October. Residential customers will see their rates hold month-over-month.

Relative to the tariff rates seen in September, industrial customers will see a tariff rate increase between 1% and 1.4%, and commercial customers will see an increase of between 0.6% and 1%. The increase is the result of small movements in natural gas prices, which are one of the main determinants of power prices. The increased October tariff rates break a streak of six consecutive months of tariff decreases for CFE’s large customers. Meanwhile, residential customers will continue their streak of 34 consecutive months without a price increase.

CFE’s monthly updates to the tariffs can be problematic for power customers that require more budget transparency and certainty—particularly when prices are increasing. Third-party suppliers are offering increasingly competitive rates that can provide greater budget certainty. Enel X is actively working to vet new entrants to the supplier pool and can assist customers in finding and choosing the best independent contract to manage their costs and risk at the most competitive price.

For further updates on the electricity and natural gas markets, read our full report for this month.

Henry Hub
NYMEX Market Trends

Over the course of 2017, the Henry Hub Natural Gas rolling 12-month strip has traded in a range between $2.82/MMBtu and $3.70/MMBtu. However, since June, that range has tightened to $2.82/MMBtu and $3.15/MMBtu. This represents a spread of just $0.33/MMBtu between the high and low points of the summer season.

This trend of a slow contraction of the market’s movements provides a technical signal that a “break-out” is imminent. In other words, the market is running out of room to consolidate, and this upcoming shoulder season will likely be the last time we see forward pricing trading within this tightened range.

For further updates on the natural gas market, read our full report for this month.

Authored By The Enel X Energy Intelligence Team

The Energy Intelligence team provides talent and knowledge to our customers by making the complexity of energy management simple.

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