Energy Procurement Insights for June 2018: 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.

To receive this update in your inbox every month—as well as our weekly updates on the national energy markets and insights on energy management from throughout the industry—subscribe to the EnergySMART blog today. You can learn more about Enel X's energy procurement services here, and talk to one of our experts here.

New England
Massachusetts & Rhode Island Announce Largest Award of Offshore Wind in Nation's History

On May 23, Massachusetts and Rhode Island officials concurrently announced the award of contracts for two massive offshore wind farms, totaling 1,200-megawatts (MW) of capacity, off the coast of Martha’s Vineyard. Market observers were expecting a decision from the administration of Massachusetts Governor Charlie Baker regarding the outcome of the Commonwealth’s Section 83C Offshore Wind Energy Generation solicitation issued in June 2017 for the state’s first offshore wind farm. However, Rhode Island’s announcement came as a surprise, as the state had not publicly disclosed its intention to participate in the Massachusetts process. The two states ultimately chose two of the three proposals submitted under the Commonwealth’s 83C solicitation.

The Massachusetts Department of Energy Resources (DOER) and the state’s electric distribution companies selected Vineyard Wind, a joint venture between Connecticut-based utility Avangrid and Copenhagen Infrastructure Partners, to build an 800 MW offshore wind farm 14 miles off the southern coast of the Vineyard. The award represents an important milestone towards fulfilling the requirements of the Massachusetts’ Act to Promote Energy Diversity law signed in August 2016, which calls for the state’s utilities to enter into long-term contracts for 1,600 MW of offshore wind by June 30, 2027. Vineyard Wind aims to begin construction in 2019 and bring the project online by late 2021. With 800 MW of capacity, the project represents up to 6% of Massachusetts’ total annual electricity load.

In collaboration with the Massachusetts process, Rhode Island selected Deepwater Wind, based in Providence, RI, to construct a separate 400 MW offshore wind project dubbed Revolution Wind. At that size, the project would be more than 10 times the size of the 30 MW wind farm that Deepwater Wind put into service near Block Island, RI, in December 2016, which was the nation’s first and currently only operational offshore wind farm. The award follows Governor Raimondo’s ambitious target announced in March 2017 to expand Rhode Island’s renewable energy generation ten-fold to 1,000 MW by 2020. Further behind in the permitting process than the Vineyard Wind project, Revolution Wind is expected to begin construction in early 2021 and to be fully commissioned by 2023.

Now that the projects have been selected, the developers are required to enter into contract negotiations with the electric distribution companies in each respective state, in order to then submit a proposed contract to state agencies for regulatory review. The Eversource and National Grid Massachusetts’ negotiated contracts must be submitted to the Department of Public Utilities (DPU) by July 31, 2018, while Rhode Island has not yet announced a deadline.

The contract terms and cost for the two offshore wind projects have not yet been revealed, but industry players expect bids for this solicitation to have ranged between $100-$125/MWh for the equivalent of a 20-year power purchase agreement (PPA). These kind of costs are substantially higher than natural gas and even onshore wind resources, and well over the market price for electricity. Any above-market costs—i.e. the difference between contract costs and the proceeds obtained from the sale of the offshore wind energy, capacity, and renewable energy certificates (RECs) —will be recovered from ratepayers via a non-bypassable surcharge on utility distribution bills.

Based on currently available information, Enel X estimates that Massachusetts ratepayers could see their utility distribution costs increase by $0.002/kWh starting in 2022, while Rhode Island ratepayers could see costs increase as much as $0.01/kWh starting in 2023.*

* Assumes PPA price of $115/MWh, and uses historical and forward curve data to estimate wholesale energy, RECs, and capacity values.

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

New York
NYISO Report Addresses Challenges Stemming from Evolving Fuel Mix

The New York Independent System Operator (NYISO) recently published their outlook on the power market and its goal of creating a dynamic power grid that can handle the new complexities of a changing supply resource. Advancements in technology and new state-level policies, such as New York’s Energy Plan requiring 50% of power sourced via renewables by 2030, makes it challenging to implement a market that will support both the new technology and the shifting fuel mix. In this report, the NYISO addresses the challenges they will face, including reliability, integrating intermittent energy resources, and addressing the aging transmission system so they can manage the changes effectively.

Distributed energy resources (DER), such as rooftop solar, are transforming consumption patterns and are reducing energy consumers’ reliance on the bulk power system. These resources are not directly visible to the NYISO and complicate forecasting. Over the next decade, both peak demand and energy usage should decline around 0.13% per year as a result of the growth of DERs. When combined with energy efficiency and demand response, these developments are influencing both the energy and capacity markets. Additionally, achieving the state’s goal of sourcing 50% of power from renewable resources by 2030 will require generating power from intermittent sources, such as solar and wind, which will put additional economic pressures on existing conventional resources. These resources will run less and will balance the demand requirements, rather than meet base load. To mitigate the reliance on conventional fossil generation, energy storage could fill part of the gap, but not the whole gap. The marketplace will need to incentivize these resources to provide this ancillary service. The bulk power market would need these facilities to provide both peaking service and quick response to sudden changes in the intermittent generation. This could lead to ancillary service costs increasing, as this service will require different operating procedures from their original design.

Another challenge facing the New York bulk market is how they are going to replace aging resources. In addition to the nuclear facilities—three of the four of which are over 40 years old—866 MW (2% of In-State Generation) of steam turbine generation is older than 62 years old. Nationally, 95% of such capacity at this age has ceased operations. This figure is set to grow to 4,898 MW (12.5%) by 2028. For gas turbines, 2,356 MW (6%) are currently past the normal retirement age of 46. This figure will reach 3,403 MW by 2022. Although there are proposed plans to add nearly 15,000 MW, nearly 8,000 MW are either natural gas or dual-fuel (typically natural gas and another fuel). New York Energy Policy has put roadblocks in front of natural gas projects, especially gas produced from shale using fracking. The state has denied crucial permits for several pipelines and thus has not been very welcoming to new natural gas facilities, nor the pipelines to feed them. In the short term, New York is working on extending plant operations for reliability, but the impact of these aging generation sites is worth monitoring.

New York is at risk at becoming a two-market system: upstate (Zones A-E) and downstate (Zone F-K). The upstate market receives most of its energy from clean resources, while the downstate market receives 70% of its energy from fossil-fuel generation. New and upgraded transmission will help alleviate fracturing the market in two and will also provide operational flexibility in dispatching resources and gaining efficiencies in managing operating reserves and ancillary services. NYISO is evaluating many transmission projects with the hopes that they can find a project that can relieve transmission constraints between upstate and downstate.

New York’s policies are clearly targeting a cleaner grid. NYISO must adapt through new products to attract resources that are capable of handling the intermittent and variable nature of the new renewable resources. If there are hiccups in the process, we can find the market split between upstate and downstate, where there is potential for downstate prices to trade significantly above those in the upstate market. Currently, the New York City market is trading about $11.50/MWh above the upstate market. This spread has ranged from $8.00 to nearly $14.00 over the last five years on an annual basis. Another risk is that ancillary costs will rise if NYISO introduces a new product that results in suppliers claiming change-in-law and passing these costs directly to the customer.

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

Mid-Atlantic
PJM Releases Base Residual Auction Capacity Results for Delivery Year 2021/2022

On May 23, PJM posted the results for the 2021/22 Base Residual Auction. Capacity prices cleared much higher for most of the RTO (nearly 83% higher) compared to the prior year, but cleared lower comparatively for AE, DPL, JCPL, PECO, and RECO, all of which are part of EMAAC (Eastern Mid-Atlantic Area Council). According to RTO Insider, PJM stated that the increase in clearing prices was a result of higher resource offers, partially due to lower LMPs and ancillary services over the past few years. Generators need to make a profit to be operational, and Capacity and LMPs (energy market) are their two largest sources of revenue. PJM also noted that there was a decrease in new generation offers compared to the prior year. The 2021/22 Capacity year is the second where all assets are under the Capacity Performance initiative, which expects resources to be available year-round and imposes steep penalties for non-performance.

All customers in PJM are obligated to pay zonal capacity prices as part of their electric supply cost. Energy users pay the above clearing prices multiplied by their capacity tag (along with Zonal Scaling Factor and Forecast Pool Requirement) each month of their bill. It is very important to manage down a customer’s capacity tag to offset some of the cost. Of particular importance will be mitigating peak demands in the summer of 2020 due to the high prices in the associated capacity year. Please reach out to an Energy Advisor to learn how Enel X’s System Peak Predictor program can help in this process.

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

Midwest
ComEd Capacity Rates and Summer 2018 Outlook

This month’s commentary will focus on the details and importance of capacity charges in ComEd and what customers can expect for the summer 2018 outlook. Capacity rates in ComEd are slated to rise starting this June for the 2018/2019 delivery year, and Capacity pass-through customers will begin to see a rise in these charges starting this month, as shown in the chart below. The latest Base Residual Auction for the 2021/2022 delivery year cleared at $245.11/MW-day, including scaling factors, a price which was important and unknown to customers signing 36-month contracts. The clearing price is in line with the higher capacity rates customers will experience in the next three delivery years.

The driving force behind the increase in capacity rates for ComEd is the need for more generation to meet peak demand in the zone. The ComEd zone’s peak load is higher than its internal generation, meaning it must import power from nearby zones and RTOs in order to meet demand on peak days. Higher capacity rates incentivize generators to build more generation to meet this demand, and rates will continue to be elevated until more generation is built in the zone.

A customer’s total capacity cost is obtained by multiplying the total capacity rates above by the customer’s capacity tag or Peak Load Contribution (PLC). In ComEd, PLCs are set differently than they are in most zones in PJM, presenting some challenges for customers looking to manage their capacity tag. Capacity tags in ComEd are set by the higher of one of the following: the customer’s average demand during the five highest PJM system peak hours (as the rest of the RTO is set), or the customer’s average demand during the five highest ComEd zonal peak hours. Zonal peak hours, particularly in ComEd, are difficult to predict and frequently do not overlap with the PJM system peak hours. In the last three years, only 4 out of 15 peak hours were the same for both the PJM system peak and the ComEd zonal peak.

The first weeks of summer 2018 have arrived and forecasts have proven to be accurate thus far, as most sources have been expecting warmer-than-average temperatures across the country. The National Weather Service’s Climate Prediction Center is forecasting a moderately high probability of above-average temperatures in June and milder temperatures in July. The complete summer forecast shows an equal chance of above- or below-average temperatures for the mid-continent states west of Ohio and north of Tennessee. While temperature forecast is warm to mild, the precipitation forecast is significantly above average for most states east of the Mississippi, which could dampen hot temperatures this month.

Customers in ComEd on pass-through products or on the utility default rate should look to manage their capacity tags as much as possible this summer, as capacity rates will remain elevated through May 2022. While it is more difficult to manage peak demand charges in ComEd, it is still prudent to do so given the significant rise in rates. Rolling power forwards have been near all-time lows since the last quarter of 2017, trending between $26-27/MWh. Customers looking to lock in longer dated strips now would be in a good position to do so. If demand management is possible, passing through capacity is a good strategy keeping in mind the differences in tag management in ComEd.

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

Texas
June Outlook: Hot May Leads ERCOT Into Summer Demand Season

May 2018 set records across the state of Texas for heat, driving up power demand and making many in the state wonder if this heat will persist into the summer months. If the early days of June were any indication, then yes, those of us in the Lone Star state should be prepared to crank the A/C. However, recent forecasts from the Climate Prediction Center (CPC) show the ERCOT region is in for a moderate summer demand season. The CPC predicts Cooling Degree Days (CDD) of 458, 561, 563, and 366 for June, July, August, and September, respectively. CDDs are a measure of temperature above a set benchmark where cooling would be required. A higher CDD represents how much temperatures will exceed that benchmark. The CPC’s forecasted summer total of 1,948 CDDs would be almost in-line with the 10-year average of 1,991 CDDs for the region. This means that average temperatures for summer 2018 should correlate closely with the 10-year average.

From a demand perspective, this is a bearish signal. Load, and therefore grid demand, is closely correlated to temperatures. There are, however, two more pieces to this puzzle. Texas has experienced GDP and population growth that outpace many other states. This additional manufacturing and cooling demand contributes directly to record peak demand forecasts despite the moderate CDD forecast from the CPC. Increased forces on the grid leads to potentially higher spot prices and influences increased demand charges related to the 4CP transmission charges. These market dynamics are important to any organization with assets in Texas and enforces the importance of having a partner that can assist in managing demand during crucial summer hours.

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

California
Ominous Statewide Outlook for Summer 2018 in California

In early May, the California Independent System Operator (CAISO) released a report on its assessment of summer load for 2018, which revealed a significant risk of operational conditions that the state’s current fleet of generators may not be capable of meeting. Southern California, as it stands right now, is at the highest risk of curtailment for both power and gas. 

Just a few weeks ago, Southern California Gas Company (SoCal Gas) stated that it was anticipating pipeline outages on its system through much of the summer and that it will have difficulty filling storage to necessary inventory levels in time for the peak summer demand period. The company is calling for expanded use of the Aliso Canyon storage facility, which has returned to service following a massive 2015/2016 gas leak. Without the use of Aliso Canyon, SoCal Gas will likely not be able to meet demand on a peak day. 

Even though some late-winter storms in Northern California increased hydro supply levels, total reservoir levels were still 70% below average as of early April. On average in March 2018, hydro power plants produced about 56,939 MWh/d, a drastic decrease from the 107,170 MWh/d generated in March 2017. According to the California Department of Water Resources, the state is expected to remain in an overall draught for the remainder of the year.

Due to sustained temperatures well below average in February, both gas utilities in southern California—San Diego Gas and Electric (SDG&E) and SoCal Gas—were forced to issue curtailments for their noncore customers as demand jumped more than 30%. This forced the system to withdraw gas from the Aliso Canyon storage facility. This “asset of last resort” was used to prevent power outages by providing enough natural gas to power generators. Short-term prices spiked to $22/MMBtu at the SoCal Citygate basis point. The curtailment of supply to the power generators had impacts on electricity prices, resulting in spikes as high as $970/MWh.

The factors above are combining with the retirement of 789 MW of dispatchable natural gas generation throughout the state to create a situation in which the grid operator is predicting a possible Stage 2 Emergency notification. A Stage 2 Emergency occurs when the grid operator calls upon all available resources to produce in order to avoid system-wide curtailment. The North American Electric Reliability Corp (NERC) also joins a growing list of organizations expressing concern over the prospects for California meeting its load obligation this summer. Though CAISO does not anticipate any power outages or blackouts, generation that had been available to meet increased demand in previous summers will not be able to produce when called upon. The greatest risk is during late afternoons, when solar generation begins to ramp down and residential load begins to increase. Should a sustained heat wave hit in late August through early September, the lack of hydro power support and shorter daylight hours will cause grid challenges for maintaining reliability, likely causing electricity and natural gas prices to spike. 

Customers in California that have index exposure for either power or natural gas are going to be extremely vulnerable to sustained heat waves that will drive up spot market prices. Customers currently on a fixed contract that expires later this year may benefit from locking in another contract before the summer heat comes in. Even though current prices are higher than they have been in recent history, it may still be beneficial to lock into a position to avoid the exposure. Reach out to Enel X’s Intelligence and Analytics team for further guidance on hedging strategies.

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

Mexico
Energy Reforms Expected to Stay Despite AMLO Past Opposition, Mounting Lead

With Mexico’s first presidential election since the energy market reform was passed in 2014 coming up on July 1, many in the country’s energy industry have expressed concern that popular candidate Andres Manuel Lopez Obrador (AMLO)—whose support has reached 50% in recent polling—would attempt to roll back the deregulation of the country’s energy market. However, industry speculators and large businesses operating in Mexico have little to worry about regarding the status of the energy market.

To date, the reform has actually been popular in the country. Recent polling from newspaper El Financiero reveals that about 48% of the population supports the reform, with just 37% opposed. This support comes in spite of the fact that a majority of Mexicans believe that the reform has not yet yielded positive benefits, with 61% expressing that sentiment and only 27% feeling benefit from the law. Additionally, AMLO and his team have more recently used softer rhetoric regarding the reform in the final months of the campaign.

Most important to the survival of energy market reform is the way in which it was passed and enacted into law. Since the reform required a fundamental change in the way the law addresses property rights, the energy market reform was passed by lawmakers in 2014 with a two-thirds vote required to change the country’s constitution. In order to roll back the reforms, the country would need to change the law back through the same constitutional amendment process, requiring the same two-thirds support, which is unlikely to occur.

Considering the softening tone of AMLO’s rhetoric, general public support for deregulation, and the near-insurmountable challenges in reversing the law, large energy users should feel confident in leveraging the country’s deregulated energy market regardless of the election’s results. The reform has created opportunities for customers to access power and gas contracts that provide greater budget certainty and lower costs than were previously available. Even with the seemingly inevitable election of AMLO, the law is unlikely to undergo any real changes.

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

Henry Hub
Dynamic Price Movement in NYMEX and Basis Call for Procurement Strategy Review

The growth in gas infrastructure has been the headline story throughout 2018, with around 11 Bcf/day of pipeline capacity construction expected to occur by year’s end. The most impactful project, Rover Pipeline, received approvals from FERC in late May 2018 that will affect pricing in both upstream markets in the Northeast and downstream markets in the Midwest. The approvals for Rover will have significant strategic implications to gas procurement strategies. 

The approvals from FERC in late May 2018 allowed Rover to elevate the current maximum capacity to around 2 Bcf/day. At full utilization, Rover’s capacity is expected to be 3.25 Bcf/day. The remaining 1.25 Bcf/day of capacity is still awaiting approval from FERC and is related to strategically located laterals connecting supply markets in the Northeast to delivery markets in the Midwest and Ontario, Canada. Over the next several weeks, pricing will likely react to news regarding the implementation of these laterals and NYMEX and will have an impact on basis pricing. The analysis in this month's full report (linked below) examines many of the pricing impacts resulting from the pipeline construction. 

As a result of the increased interconnectivity between regions, the majority of basis markets in the Northeast and Midwest are displaying backwardated forward pricing. The backwardation phenomenon means the prices in future periods are offering lower prices in 2020 and 2021 compared to current pricing. Fundamentally, the backwardation shows a strong belief in higher supply growth versus expected growth in demand. Customers may have opportunities for basis savings compared to current contract as a result of these changing dynamics.

For further analysis and 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.

More about the author