Energy Procurement Insights for July 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, EnerNOC'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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In August 2016, Massachusetts Governor Charlie Baker signed “An Act to Promote Energy Diversity” into law. While the Act’s focal provision centered on a mandate for electric distribution companies (EDCs) to solicit power purchase agreements (PPAs) for offshore wind, it included a number of other directives as well. One piece of the Act required the Massachusetts Department of Energy Resources (DOER) to provide a recommendation by July 1, 2017 for a target for energy storage to be in place by January 2020. The Act called on the DOER to evaluate how much “cost-effective” energy storage the state could reasonably achieve by the start of 2020, and allowed the DOER to consider several incentive schemes to help meet the established target.
On June 30th, the DOER fulfilled its initial obligation by announcing an “aspirational” target of 200 MWh. Unlike traditional generation, energy storage capacity is often referred to in MWh rather than its potential power output (MW) because discharge rates may differ between different types of energy storage. Based on its findings at the conclusion of the initial implementation period, the DOER may add additional recommendations regarding energy storage beyond 2020.
According to the DOER, the target should complement the work already put in motion by the Massachusetts’ Energy Storage Initiative (ESI), which was created with a $10 million commitment to study the potential impact of energy storage in Massachusetts. ESI published the “State of Charge” report, which claims that energy storage has the potential to create hundreds of millions of dollars in ratepayer benefits. Under the second phase of ESI, the DOER and Mass Clean Energy Center launched a $10 million grant program called ACES (Advancing Commonwealth Energy Storage). ACES supports energy storage pilots ostensibly to understand the cost-effectiveness (and general effectiveness) of the various energy storage options currently available. While the state has pledged support, the onus to procure energy storage ultimately falls on the EDCs (e.g. National Grid and Eversource), who will now submit annual reports to the DOER detailing their progress towards fulfilling the energy storage mandate.
While EDCs will bear the cost upfront, in all likelihood, ratepayers will pay the cost of the programs in the form of pass-through charges on their distribution bills. Massachusetts consumers already pay some of highest power prices in the country, due in large part to the state’s aggressive Renewable Portfolio Standard and specific solar carve-out programs. It is unclear exactly how the charge structure for the energy storage requirement itself will play out as the DOER is considering including energy storage as part of an Alternative Portfolio Standard, to work in tandem with the Renewable Portfolio Standard. Grid-scale energy storage is still in its nascent stages and is likely to be relatively expensive at the outset, so exactly how the state will interpret “cost-effective” and whether the DOER purposefully left themselves wiggle room by calling it an “aspirational” target remain to be seen.
Read our full report for this month for insights into energy pricing trends and updates on pipeline construction in the region.
In its Phase 2 Implementation Plan Proposal for the Clean Energy Standard (CES), NYSERDA has updated its requirements for suppliers to meet regarding their purchase of Renewable Energy Credits (RECs). The proposal takes into account a new value mechanism for behind-the-meter generation which allows only some of these resources to be eligible to earn RECs.
Overall, the proposal drastically reduces the amount of RECs suppliers will have to procure in upcoming years compared to the original Order released in August 2016. This is because most of the new renewable generation in the state is anticipated to come from behind-the-meter (BTM) generation which will not receive RECs. Initially, NYSERDA anticipated that these BTM resources would be eligible for RECs, and included them in their forecast for eligible generation. This was later corrected by the New York Public Services Commission (NY PSC).
On March 9, the NY PSC released an order improving the existing compensation for BTM generation, which in a press release stated, “recognizes the full and accurate value of DER (distributed energy resources).” Due to this change, this will be the main driver of new renewables in the state in upcoming years, rather than the REC program. According to NYSERDA, only 262 GWh of renewable generation will earn RECs in 2018, while another 1,969 GWh of renewable generation will come from Non-REC BTM resources. Given these new circumstances, NYSERDA has adjusted the number of RECs that will be available for sale and has therefore revised the amount of RECs suppliers will be required to purchase in upcoming years.
For customers this means REC charges will continue to be a miniscule component on their electric supply bills in 2018. In November 2017, NYSERDA revised its mandate from 0.6% of load to 0.035% after the state clarified which resources would be eligible for the program. This meant that instead of suppliers needing to purchase one REC at $21.16 for every 116 MWh of energy they supplied, they would only need one REC for every 2,857 MWh of energy they supplied, making the cost component insignificant. This similar reduction for 2018 in the Phase 2 Proposal announced in May is precisely why EnerNOC has been advising our New York customers to treat RECs as a pass-through until the program has fully matured.
Read our full report for insight into electricity and natural gas pricing trends for this month.
PJM recently posted the updated Network Integration Transmission Service (NITS) rates effective July 1, 2017.
Each customer in PJM pays their zonal NITS rate multiplied by their transmission tag. The July 1, 2017 NITS rates increased nearly 50% for MAIT (METED and PENELEC), while Rockland increased almost 55% from prior rates. The June 1, 2017 NITS filing saw an overall increase to NITS led by PPL, AECO, UGI (PPL), AECO, AEP, BGE, and EKPC. Utilities will determine final transmission tags passed on to customers in each respective zone. By taking part in peak load reduction (through EnerNOC’s System Peak Predictor program), customers can try to manage summer peaks to reduce capacity tags along with transmission tags, although some PJM zones will use winter peaks in calculating final transmission tags.
PJM will usually make updates to NITS rates in January, June, and July of each year. Transmission tags are set by the utility for the entire calendar year.
Read our full report for insights into natural gas and electricity pricing for this month.
FirstEnergy’s two nuclear facilities in northern Ohio—the Davis-Besse and Perry Power stations—are at risk of early retirement without assistance from a state subsidy, which is currently stalled in the legislature.
In April, lawmakers put forward a bill to keep the plants operating; however, the Ohio House of Representatives suspended hearings on the bill in May. The decision to delay has put the future of the plants in question, while intensifying the regulatory debate of state subsidies supporting at-risk nuclear plants. The proposed bill in Ohio would pay for the subsidies through a rate rider in customer distribution bills, increasing utility rates for customers in any Ohio area with nuclear generation. Fearing a patchwork of state subsidies that would undermine the market-based price of power across the region, PJM has made critical statements in recent weeks, which suggest how the RTO will handle this challenge.
The two at-risk nuclear facilities along Lake Erie face the same existential threat as other high-cost generators in the current low-power price environment. Nuclear power accounts for a larger share of generation than the rest of PJM, where low-cost wind and new gas facilities are pitted against aging baseload generators. Nuclear and coal facilities are increasingly being priced out of the wholesale power market and forced into retirement. While PJM views this as a sign of properly functioning competitive energy markets, others, such as Energy Secretary Rick Perry, see the market development as a potential problem. Local economic, tax, and job considerations aside, the debate hinges on whether or not “baseload” generation benefits the grid in ways that are not captured in current market pricing mechanisms.
PJM officials have recently made a number of statements positioning themselves in the growing debate. In direct reference to FirstEnergy’s nuclear plants, the RTO stated bluntly that the plants are not necessary and there will be no reliability issues if FirstEnergy retires the plants early. PJM officials went further, pointing out the well-functioning procedures for generator retirement, which have successfully managed nearly 30,000 MW of retirements in the last five years.
FirstEnergy CEO Charles Jones Jr has joined some state and federal lawmakers in taking a different stance. Supporters of nuclear subsidies assert these “baseload” generators offer grid “resiliency,” broadly meaning the solid fuel stored on-site at these facilities is more robust during catastrophic events than gas facilities relying on continuous pipeline flow for fuel. They believe current market pricing mechanisms, such as the capacity market, do not capture this benefit and “baseload” generators should be compensated accordingly.
In the face of an increasing number of states adopting or proposing Zero Emission Credit schemes to support at-risk nuclear generation, PJM has advocated for a regional market-based solution to capture grid “resiliency” benefits not currently priced into the wholesale power market. The fear is the RTO’s organized power market will be undermined by a patchwork of inconsistent state subsidies. In June, PJM laid out a road map of required steps to examine grid resiliency, its ability to withstand external shocks to the system, and how it might be priced into competitive markets beyond 2018. While this was welcomed by supporters of baseload generation, it may be too late for FirstEnergy’s Ohio nuclear facilities, which will likely announce early retirement by the end of the year without a revival of the state subsidy bill.
With low gas prices for the foreseeable future and 34 of 61 nuclear facilities becoming unprofitable in the current environment, expect regulation changes as the debate accelerates. Utility rate rider increases could surface in areas with subsidized baseload generation.
Read our full report for insight into the impact of natural gas storage levels on pricing.
Last month, stronger demand and higher natural gas prices drove June day-ahead spot market power prices 17% higher than those seen in the same month last year. Aside from the rebound in natural gas prices, which were at historic lows last year, warmer weather played a key role in driving higher grid demands and spot prices. In fact, due to the warmer weather, the measured peak load of 67,698 MW was more than 2,800 MW higher than in June 2016 and also set a new monthly peak demand record going back to 2011. The monthly average day-ahead power price was $28.51/MWh last month across all hubs, compared to the average monthly spot price of $24.30/MWh in June 2016.
Consumer demand and the cost of fuel used to produce electricity are the two primary drivers of spot market electricity prices. This past June, temperatures in the central footprint of ERCOT were generally above seasonal daytime averages, featuring several days in excess of 100 degrees Fahrenheit. On balance, wholesale power prices were propelled higher by delivered prices for natural gas. The monthly average natural gas price in June was $2.983/MMBtu at the Houston Ship Channel delivery point in Texas, about 22% higher than the $2.455/MMBtu average seen in June 2016. The price of electricity is closely linked to the cost of natural gas in Texas since it is the predominant fuel used to generate a significant share of the 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. ERCOT system demand peaked at 67,698 MW in June, which is 4% higher than the June 2016 peak load of 64,876 MW. The average daytime high temperature for Austin, TX in June 2017 was 94 degrees Fahrenheit, which is three degrees warmer than historical averages. Aside from the observed temperatures and higher natural gas prices, power prices remained in check as a result of increased wind generation year-over-year. Wind generators increased generation share by 34% when compared to the same month last year, while coal and natural gas generation’s share saw small declines.
ERCOT’s sufficient generation reserve margins continue to provide adequate resources to produce low-cost energy generated by a diverse portfolio of renewables, natural gas, coal, and nuclear units.
Read our full report for for insight into energy price trends and an update on a new transmission project in the state.
On June 29th, the California Public Utilities Commission (PUC) opened a rulemaking to review the current Power Charge Indifference Adjustment (PCIA) and potential changes and alternatives. The PCIA is a non-bypassable charge applied to customers leaving bundled service for direct access.
When a customer of an Investor Owned Utility (IOU) decides to leave the utility to purchase energy from a third-party supplier, that customer is charged an exit fee. The exit fee is meant to recover the cost that the utility incurred to procure and administer power supply for that customer before switching to direct access. Ultimately, this fee is intended to make the utility financially indifferent to the fact that the customer has left utility service.
The participants of the PCIA Working Group have agreed on a proposal to improve the transparency in the PCIA process and have identified three potential alternatives to the PCIA as it now exists:
- A new portfolio allocation methodology (PAM). While it is unclear how PAM will replace the PCIA, utilities have stated that this new system would support the growth of direct access and Community Choice Aggregation (CCA) customers without burdening other customers.
- A lump-sum buyout of what would otherwise be CCA customers’ PCIA obligations.
- The assignment of certain procurement contracts of the IOUs to CCAs, in lieu of imposing the PCIA.
Furthermore, the rulemaking will address the following issues:
- Implementation of SB 350 language discussing bundled customer indifference and protection of departing customers from allocations of costs not incurred on their behalf.
- Transparency of current PCIA methodology.
- Data access for current PCIA methodology.
- Review and possible modification of current PCIA methodology.
- Alternatives to PCIA framework.
- Exemptions from PCIA for CARE and Medical Baseline customers
For customers on independent supply, a revised PCIA charge could be a tremendous benefit. Currently, customers on direct access are charged a monthly fee for costs that were potentially incurred by the utility when the customer was still on bundled service. However, it is not clear that the PCIA is distributed appropriately or if customers are charged for costs that were not actually incurred on their behalf.
Read our full report for insights into natural gas and electricity pricing trends this month.
The Mexican utility, the Comisión Federal de Electricidad (CFE), announced a decrease in default rates in July, which will result in a slight drop in electricity prices for commercial and industrial users. Most residential customers will see their rates hold steady relative to last month.
Industrial customers, however, will see a tariff rate decrease between 0.3% and 0.7%, while commercial customers will see a decrease of between 0.2% and 0.4% relative to June tariff rates. The slight decrease is the result of small movement in natural gas prices, which are one of the main determinants of power prices in the country. Residential customers saw no change in their tariff, marking 31 consecutive months with no increase. That streak is a stark contrast to the volatile and often increasing tariff rates for industrial and commercial customers, highlighting the point that C&I customers are subsidizing the residential customer base.
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. The growing stable of third-party suppliers offering increasingly competitive rates can provide both cost relief and greater budget certainty.
EnerNOC is actively working to vet new entrants to the supplier market in Mexico, and can assist customers in finding and choosing the best independent contract to manage their costs and risk at the most competitive price.
Read our full report for insights into natural gas and electricity pricing trends in Mexico for this month.
Over the last month, the July 2017 NYMEX contract has experienced a considerable amount of volatility. The range for the contract spanned from a high price of $3.24/MMBtu on May 30th to a low of $2.95/MMBtu on June 30th.
Leading up to summer 2017, the weather forecasts called for above-normal temperatures throughout the continental US. This led the market to believe that gas demand would be above the levels seen in summer 2016. This belief drove up natural gas prices above $3.20/MMBtu in late May.
However, June actual temperatures have been rather mild, and gas demand in the Midwest and Northeast have fallen 16% below 2016 levels. This equates to the lowest power burn consumption since summer 2014. The largest year-over-year decrease occurred in the Midwest region, with a decrease of 40% below 2016 power generation consumption. Predictably, the price response to the mild start to summer has been bearish on both NYMEX and many New England and Midwestern basis points as well.
We’re currently at an opportune time for locking in natural gas contracts. At the time of publication, the NYMEX was currently trading around $2.90/MMBtu, well below the $3/MMBtu threshold. This is particularly interesting given that most weather forecasts suggest a hot summer, which could significantly push up natural gas prices in the upcoming months.
Read our full report for July for insight into how coal generation trends and weather forecasts could affect natural gas prices going forward.