Energy Procurement Insights for May 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.

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New England
ISO-NE Reveals January Cold Pushed System to the Brink

The brutally cold temperatures which engulfed the Northeast for nearly two weeks from December 26, 2017 to January 8, 2018 severely tested ISO-NE’s ability to maintain system reliability. That stretch saw 10 days with average temperatures 10 degrees below normal or colder. In addition, major winter storms added stress by disrupting fuel supplies.

Although the natural gas market faces a surplus of supply nationwide, New England continues to lack adequate pipeline infrastructure to bring gas into the region during periods of extreme cold. When gas demand increases sharply due to heating demand needs, the availability of gas for power plants diminishes and gas becomes very expensive. Cash markets at the Algonquin city gate skyrocketed, and January 5 saw daily pricing reach an all-time high north of $78/MMBtu, compared to monthly average spot pricing in February and March of $4.40 and $3.97/MMBtu, respectively.

The sudden increase in spot pricing made oil-fired generation economical, and many dual-fuel gas/oil resources began fuel switching. ISO-NE reported that while under normal conditions in December, natural gas produced 46% of the region’s electricity, and oil accounted for less than half a percent. In contrast, under the cold snap conditions, oil actually eclipsed gas, producing 27% of New England’s power and trailing only nuclear for the lead position.

Although ISO-NE’s market initially operated as expected, the prolonged frigid temperatures quickly depleted oil supplies. Winter storm Grayson, which reduced solar output and idled several wind generation stations, also prevented the arrival of new oil supplies to replenish reserves. Over the 13-day period, available fuel oil dropped from 68% of maximum capacity to 19%. In addition, many oil-fired resources were approaching their emissions limits. This forced ISO-NE to “posture” certain oil-fired generation, which means that although they might have cleared the energy market with the lowest marginal offer, ISO-NE dispatched other more expensive resources to generate to mitigate risks of the lack of fuel diversity. Daily power prices surged as a result and reached nearly $300/MWh.

As the polar vortex conditions dissipated, the system resumed to relying on gas and regional oil stocks returned to normal levels. However, the takeaway is that cold weather once again exposed the precarious nature of the fuel situation in New England. Although the region continues to build out renewable resources like wind and solar, extended cold and other extreme weather events still necessitate a reliance on traditional generation sources. Customers with index exposure in winter months will continue to be susceptible to extreme pricing volatility in New England, due to the infrastructure constraints and fuel diversity in the region.

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

New York
New York Pushing Forward to 2030 Environmental Goals

To help achieve its goal of 50% renewable electricity by 2030, New York State Energy Research and Development Authority (NYSERDA) has launched its second annual request for proposals. By 2020, the agency is aiming to bring up to 20 large-scale renewable projects capable of generating 1.5 million MWh per year to the state. This represents less than 1% of the electric generation usage in New York.

Currently, renewable resources, including hydroelectric generation, represent about 27% of the New York generation mix but only supply 22.3% of the retail electric usage, as New York remains a net importer of electricity. The chart below shows the breakdown of the state’s generation by resource. Natural gas and nuclear generation still dominate the fuel mix in New York.

Last year’s solicitation yielded 26 agreements to develop 1,383 MW of clean energy. The new developments were primarily split between wind (734 MW) and solar (634 MW). These facilities are expected to be operational by 2022 and should produce around 2.5 million MWh. This equates to an additional 1.5% renewable energy to the retail electric usage. The weighted average price for these contracts was $21.71/MWh for each Tier 1 Renewable Energy Credit (REC).

The impact to customers is relatively small as these costs are spread out over the retail load. However, as New York heads toward 50% renewable energy, these costs will add up and could increase supply costs by as much as 10-20%.

For New York to achieve 50% electricity (about 78,000 GWh) from solar and wind resources, it will require a lot of acreage, depending on the resource. For wind power, studies show that it takes over 60 acres for each 1 MW or 2.2 GWh, while solar only takes around 2.5 acres for 1 MW or 1.3 GWh. To ensure that New York gets the full benefit of these solar and wind projects, integrating battery storage will be key since the generation can be shifted to match the load profiles rather than the sun and wind. New York has plans to add 1,500 MW of battery storage by 2025. 

New York’s clean energy standard of 50% renewable energy comes at a cost, both in terms of higher retail prices and a reliance on less efficient peaking units to manage load. This could put pressure on pipeline infrastructure, resulting in scarcity prices on peak winter days.

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

Pennsylvania Natural Gas Production Still Booming, Nearing Output from Texas

The shale revolution in Pennsylvania and Ohio continues to change the natural gas marketplace. Historically, most natural gas has been produced in the South around Texas, Oklahoma, and Louisiana. In recent years, Pennsylvania and Ohio have increased drilling and production in these shale formations to reach the levels seen in the Southern states. In the chart below, the US Energy Information Administration (EIA) recently reported natural gas production from five of the largest producing states. From 2013 to 2017, natural gas production increased nearly 50% in Pennsylvania alone. Production in Pennsylvania nearly topped 15 Bcf per day in 2017 with future projections to run higher. The EIA reported that Pennsylvania has issued 2,038 natural gas drilling permits in 2017, up from 1,352 issued in 2016. Related to the drilling permits, oil giant Baker Hughes reported that the rig count in Pennsylvania averaged 33 rigs in 2017, compared to an average of 20 rigs in 2016. Similar to Pennsylvania, Ohio is also showing a rising production curve, doubling output from 2014 to 2017.

With the large increase in natural gas production around the Appalachian Basin, infrastructure must be available to push the gas to other load zones in the Northeast. The EIA regional map above shows additional pipeline projects that have either been built or begun development. Two projects, the Rockies Express (capacity of 3.6 Bcf/day) and the Algonquin Incremental Market pipeline (capacity of 0.342 Bcf/day), have been in service since 2016. Two additional projects, the Rover Pipeline (capacity of 3.25 Bcf/day) and the NEXUS Gas Transmission project (capacity of 1.5 Bcf/day), are currently being built. The additional pipeline capacity in the region should help alleviate some Northeast basis pricing during high demand periods over the winter.

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

MISO Planning Resource Auction Establishes 2018/19 Capacity Year Prices

The Midwest Independent System Operator (MISO) released the results from its latest Planning Resource Auction (PRA) where the capacity prices are determined for the prompt capacity year, which runs from June 2018 through May 2019. Prices settled higher than last year’s historical low of $1.50/MW-day in all zones but Zone 1, which covers the northernmost regions of MISO.

The table below shows the auction settlement history since capacity year 2014/2015. This capacity year settled at $10/MW-day in all zones except Zone 1 (MI, WI, ND, and SD), which settled at $1/MW-day. Based on a conference call MISO held with stakeholders, RTOInsider reports that market constraints on capacity imports have left 2 GW of capacity stranded in Zone 1, causing prices to diverge from the rest of the ISO. Zone 10 (MI) was established in the 2016/2017 PRA.

The upward shift in prices can be explained by changes in cleared supply and demand. Cleared generation within the MISO footprint and imports were down nearly 1,300 MW compared to last year. The region saw more than 1,600 MW growth in behind-the-meter distributed resources, energy efficiency, and demand response. In total, the Planning Reserve Margin Requirement (PRMR) is 426 MW higher at 135,179 MW compared to last year’s requirement of 134,753 MW. Total planning resources offered exceeded PRMR by nearly 7,400 MW.

Customers with load in other markets, such as PJM or ISONE, might wonder why MISO has yet to mirror other grid operators and why prices are so volatile year-to-year. First, MISO’s current capacity auction structure and process is similar to other grid operators because it leverages competitive bids from generators to find the market capacity price given a forecasted peak load. PJM and ISONE take it a few steps further by running auctions for three years into the future. MISO made an attempt to change the structure of its capacity auction in November 2016, known as the Competitive Retail Solution (CRS), only to have it rejected by the Federal Energy Regulatory Commission (FERC) in February 2017 due to "uncertain, and potentially adverse, impacts on price formation" (FERC Docket No. ER17-284-000). The CRS proposal essentially bifurcated deregulated and regulated load. It would have created a Forward Resource Auction (FRA), similar in structure to PJM’s Resource Planning Model (RPM) and ISONE’s Forward Capacity Auction (FCA), for MISO Zones 4 (IL) and 7 (MI) and maintained the current PRA process for all other zones. Generators would need to decide between participating in the FRA or PRA, which could have led to capacity prices that were not competitive.

Second, MISO’s modeled demand curve is vertical, implying that each incremental MW of capacity has as much reliability value as the one that precedes it. In analysis provided to FERC, MISO’s Independent Market Monitor (IMM)—Potomac Economics—disagreed with the current modeling, stating,"if MISO were to recognize the diminishing marginal value of the capacity in maintaining reliability…the curve would be sloped" (FERC Docket No. ER17-284-000). The IMM conducted an analysis on the impact of the vertical demand curve and determined the 2017-2018 PRA settlement would have come in near $115/MW-Day, and not $1.50/MW-Day. While a change to the way MISO models demand could adversely impact near-term pricing for customers in choice markets, the long-term benefit from adequately compensating resources for reliability value more than outweighs the cost increase. To put this another way, using a sloped demand curve that accounted for the diminishing value of reliability would yield a higher capacity price, but could also lower the probability of a supply disruption. The sloped demand curve would be a move to a more efficient market that provides signals to generators in determining when to enter and exit the market, whether through new build, retirement, or external commitment. The increased market efficiency would also reduce price volatility.

Customers with open positions starting in June 2018 should expect modestly higher prices in Illinois. Customers in Michigan should have already locked in their pricing until May 2022 for the first SRM period, so the PRA settlement might not have much of an impact for the interim period. The issue regarding MISO’s PRA process will remain, but might not be the first priority as more than a year has passed since FERC dismissed MISO’s CRS proposal.

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

ERCOT Wholesale Spot Power Prices Decline 10% Year-Over-Year in April

Last month, average day-ahead power prices were down 10% year-over-year at $22.45/MWh across all hubs, compared to $24.83/MWh in April 2017. The year-over-year price decrease was driven by mild weather for the month, which resulted in a 10% year-over-year decrease in peak load—measured at 48,044 MW for April 2018—and drove a 9% year-over-year decrease in delivered natural gas prices.

Consumer demand and the cost of fuel used to produce electricity are the two primary drivers of spot market electricity prices. This past April, temperatures around the central footprint of ERCOT were about even with their seasonal daytime averages for the duration of the month. On balance, the wholesale power prices were softened by lower delivered prices for natural gas when compared to last year. The monthly average natural gas price in April was $2.831MMBtu at the Houston Ship Channel delivery point in Texas, about a 9% decline under the $3.117/MMBtu average seen in April 2017. The price of electricity is closely linked to the cost of natural gas in Texas since it is the predominant fuel used to generate power produced in the state. In fact, natural gas-fired power plants usually set the price of wholesale electricity in the region.

Power prices will generally react to electricity demand, which is driven by weather and economic factors. As mentioned above, the ERCOT system demand peaked at 48,044 MW in April 2018, which is 10% lower than the April 2017 peak load of 53,437 MW. Aside from the observed temperatures and lower natural gas prices, power prices remained in check as a result of a balanced mix of generation resources.

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

Stakeholders Push California ISO for Greater Storage Inclusion in its Planning

A number of important stakeholders are calling on the California ISO (CAISO) to expand the scope of consideration for energy storage resources in its planning and rules making. In many cases, energy storage facilities can provide a wide range of benefits to the grid, including the ability to charge and discharge quickly to help smooth generation from intermittent resources, provide frequency regulation and quick start services, and add benefits at both the transmission and distribution level. Market participants are calling on the ISO to value and compensate these dynamic resources for all of the value they add to the grid by allowing them to earn market revenues and cost-based revenues.

The Federal Energy Regulatory Commission (FERC) recently released a new set of guidelines opening up the possibility of cost recovery from multiple streams based on the various services that storage units can provide. Now the CAISO is working on incorporating the new guidance into their own transmission planning process. The CAISO has already incorporated two storage projects into their 2017/2018 planning process. While most stakeholders have generally responded positively to the developments, they are pushing the ISO to go further. The California Energy Storage Association wants the ISO to extend their consideration beyond reliability projects to include distribution-level storage resources. The latter would extend the rules into the domain of customer-level battery storage resources. The push for storage inclusion comes amid a drastic drop in storage costs. The chart below from Bloomberg New Energy Finance (BNEF) shows how costs for lithium-ion battery storage have fallen steadily in recent years—more than 70% total since 2010.

Earlier this year, the California Public Utilities Commission approved a set of rules that would allow for greater cost recovery for energy storage facilities.

The push to include more planning for energy storage may open up new revenue avenues for batteries, including retail or customer-level assets. This consists of fully compensating energy storage resources for their various potential benefits, including generation, transmission, and distribution on the system. Allowing these resources to be compensated for each of their benefits simultaneously is known as "value stacking," and can make the difference between a profitable project and an unprofitable project. The economics of energy storage and other distributed energy resources (DERs) already make sense for many customers in California. The push for broader value stacking will improve the economics even more.

To learn more about whether an energy storage system makes sense for your business, contact your Enel X Energy Advisor or talk to an Energy Sourcing Expert.

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

Mexico on Pace to Achieve Aggressive Renewable Power Goals Sooner Than Expected

Mexico has made headlines over the last couple of years with a series of world-lowest price bids for various solar and wind power projects. With a robust natural climate for these resources and lower-cost labor resources, experts at the Mexico Energy Secretariat (SENER) now predict that Mexico can achieve its goal of generating 50% of its power from renewable sources by 2034—16 years earlier than the country’s initial target of 2050. The country is also well on its way to overachieve on its 37.7% renewable goal for 2030, now likely to surpass that mark by 2024, 6 years early, according to SENER.

As solar power continues to develop in the country, SENER predicts that the daily load profile will likely develop into a duck curve similar to what California is experiencing (shown in the image below), with low, midday net load and a sharp increase as the sun sets into the early evening. The mid-day load continues to drop as sun shines on the solar arrays then sharply increases in the late afternoon. In addition to this pattern, an increase in intermittent resources on the system will make large price swings more likely. Overall, prices will tend to be lower since solar and wind facilities produce "free" power; however, during periods of low wind and cloudy forecasts, prices can spike without those resources’ contributions to the grid. Customers with index exposure will need to keep these changing power dynamics in mind when considering go-to-market strategies.

Thanks to the attractive renewable climate in the country, some suppliers are able to offer more green power than currently mandated through the country’s clean energy certificate (CELs) program at a small or no premium to traditional power. Customers with national or international sustainability goals can look to Mexico as a low-cost option for green power, even on short-term power contracts.

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

Henry Hub
2018 Injection Season Faces Tough Task to Reach Five-Year Average by October 31

Despite record gas production throughout 2018, the need to refill gas storage will likely be meaningful enough to keep the NYMEX rolling 12-month strip pricing from trading below $2.60/MMBtu, as long as demand factors continue the growth rate seen thus far in 2018. The additional demand will likely assist in keeping commodity pricing around current levels or slightly above, despite the bearish factor of significant summer-over-summer production gains.

April through October is viewed as gas storage injection season for a year with typical temperatures. During this portion of the year, daily gas production exceeds daily demand and excess gas is stored underground. The gas injected into storage will be withdrawn between November and March to meet the winter heating demand resulting from an increased reliance on gas for power generation. During the winter, daily gas consumption exceeds daily production. As a result of this deficit, gas storage is utilized to meet the demand by making up the difference between daily consumption and production. Demand to refill storage throughout summer 2018 will need to exceed the five-year average injections by 402 Bcf over the seven months of injection season in order to reach the five-year average storage level for October 31, 2018. This summer, natural gas storage faces a daunting task as injection season is getting off to its latest start ever by two weeks. 

The five-year average of gas injected during the summer season is 2,147 Bcf. The 2018 gas storage injection season must rely on the record gas production to inject the 2,549 Bcf needed to reach the five-year average for the end of injection season. Historically, the end of injection season occurs on October 31st each year. The chart above displays the previous five years of injection season volumes and denotes the injection level needed in 2018 to reach the five-year average of 3,848 Bcf. Platts predicts gas storage will reach 3,400 Bcf by October 31, 2018, which would mean injections were close to on-par with the five-year average of 2,147 Bcf for the season.

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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