Energy Procurement Insights for August 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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New England
Massachusetts SREC Costs Will Increase Again in 2018

The Massachusetts Department of Energy Resources (DOER) releases an annual mandate of what percentage of power supplied in the state must come from solar resources each summer. According to recent preliminary figures from the DOER, electricity suppliers and utilities will be required to purchase roughly 40% more solar power in 2018 compared to 2017. Specifically, the DOER plans to increase the Solar Renewable Energy Credit (SREC) compliance obligation requirement, which falls under the state’s Renewable Portfolio Standard (RPS) mandate. Based on current SREC prices, the upcoming increase could add as much as $0.004/kWh in additional retail supply costs for Massachusetts customers in calendar year 2018.

The Massachusetts SREC program is designed to provide economic support to expand solar installations across the Commonwealth. The original program, referred to as SREC 1, was initiated in January 2010 and targeted development of 400 MW of solar PV across the state. The program expanded in 2014 and the SREC 2 program was launched to bring Massachusetts to its goal of installing 1,600 MW of solar capacity by 2020. Paying for this requirement has not come without controversy, as requirements have increased significantly over the last several years. Between 2013 and 2017, total RPS costs increased roughly 1 cent per kWh, and they are now poised to increase again next year.

For customers under fixed price contracts (including RPS costs), suppliers may exercise the "change in law" provision at their discretion, in order to pass-through incremental costs as a result of the change in compliance percentages beginning in 2018. For other customers with an explicit SREC II expansion clause, the financial impact will depend on when the customer entered into their current supply contract. Preliminarily, if the contract was signed between April 25, 2014 and May 8, 2016, the SREC II compliance obligation percentage for 2018 is projected to increase to 2.8762% from the current 2.0197% mandate, and the SREC I percentage is projected to increase to 1.7903% from the current 1.6313%. Based on current SREC prices, this would equate to a pass-through charge of approximately $0.003/kWh effective January 1, 2018.

For any current supply contract signed after May 8, 2016, the SREC II compliance obligation percentage is projected to increase to 4.1049% from the current 2.8628% mandate for 2017, and the SREC I percentage is projected to increase to 1.7903% from the current 1.6313%. Based on current SREC prices, this would equate to a 2018 pass-through charge of approximately $0.004/kWh.

The same compliance obligation percentages apply to customers who have a supply contract coming up for renewal. Total Massachusetts renewable portfolio standard costs, which include SREC requirements, will rise to nearly 2.2 cents per kWh in 2018. Depending on when a retail power customer last signed their contract, the increase in RPS costs, alongside rising capacity costs, could result in a higher renewal rate.

For questions or further discussion about these topics, please contact your EnerNOC Energy Advisor or talk to an Energy Sourcing Expert.

For additional insight, including updates on electricity and natural gas pricing in New England, read our full report for this month.

New York
National Grid Files for Electric and Gas Rate Increase

Upstate New York utility National Grid has filed for a rate increase for both its electricity and natural gas customers. The increase would allow the utility to collect an additional $261 million from electric rates and $69.7 million from natural gas rates annually. National Grid has said that the increase will go towards infrastructure investments, increasing the grid’s ability to connect to distributed generation, advanced metering initiatives, and efficiency programs.

The impact to customers will vary depending on their rate class and load shape. Estimates provided by National Grid show an increase for large commercial customers of $801.77 per month, or 12.3% on their electricity distribution costs based on a monthly measurement of 500 kW of demand and 225,000 kWh used. For natural gas, the utility estimates an increase for large commercial customers of $79.09 per month, or 21.8% on their natural gas delivery costs based on a monthly meter read of 1,555 therms used. If approved, rate changes would go into effect in April 2018. The rate case review is currently underway with the next milestone being the deadline for written testimony on August 25. The decision will fall to the Public Services Commission on whether to approve, deny, or request further changes to the rate filing.

For questions or further discussion about these topics, please contact your EnerNOC Energy Advisor or talk to an Energy Sourcing Expert.

For additional insight, including updates on electricity and natural gas pricing in New York, read our full report for this month.

Mid-Atlantic
Update: Impact of Balance Transmission Congestion Charges

Approval of the PJM rules change to add a billing charge for "Balancing Transmission Congestion" led to speculation about the size of the potential rate increase and the eventual effect on forward pricing in the region. Now, two full months into the start of the billing change, some light has been shed on the actual impact.

The charge for Balancing Transmission Congestion in June, which was generally warmer than normal, averaged $0.08/MWh ($0.0000818/kWh) for the month. The charge in July, with a generally mild yet more sporadic temperature range, averaged $0.1428/MWh ($0.0001428/kWh) for the month. The initial indications of a 15-to-30 cent/MWh increase to prices in PJM may still happen in the event of more seasonally warm temperatures or unexpected outages.

Customers should see a slight increase on current and future contracts as the Balancing Transmission Congestion charge is adopted by suppliers.

LMPs Unresponsive to Summer Temperatures

Halfway through the year, and in the throes of summer, it is important to step back and take a look at the 1,000-foot view of the impact of temperature on price in the PJM region.

With the changing dynamic of natural gas production in the Mid-Atlantic, pricing has broken from its traditional seasonal variability and tied itself in-step with this currently leading marginal commodity. Year-to-date, temperatures in the region have been mild, allowing for an equilibrium of gas and power prices to settle in the Mid-Atlantic. Day Ahead On-Peak power at West Hub was once a guarantee to average north of $40/MWh for the month of July, but closed out July 2017 averaging $35.62/MWh. In fact, no month has averaged DA Peak prices higher than $36/MWh so far in 2017.

As natural gas prices go, so will power. With natural gas at Henry Hub again trending downward, we expect power prices in the region to follow, making the fall an opportune time to explore options to lock up portions of forward power.

For questions or further discussion about these topics, contact your EnerNOC Energy Advisor or talk to an Energy Sourcing Expert.

For additional insight, including updates on electricity and natural gas pricing in the Mid-Atlantic region, read our full report for this month.

Midwest
Illinois and Ohio Nuclear Subsidy Legislation at Odds

Several new pieces of legislation in two PJM states have taken opposing paths on the issue of using zero-emissions credits to support at-risk nuclear plants. The Ohio General Assembly put on hold two bills designed to support two financially distressed FirstEnergy nuclear plants. FirstEnergy has stated the plants may not make it through the fall without assistance. Similar legislation in Illinois, providing zero-emissions credits, has already been implemented, and recently scored a legal victory in federal court. The legal challenge had come from generators who claimed the state was over-stepping its authority by distorting the competitive market in nuclear power’s favor. The court ultimately ruled that Illinois was in its legal right to implement the ZEC program, which has now set the precedent for future states to enact similar legislation to help their own at-risk nuclear plants.

PJM has weighed supporting a market-based solution, including putting a price on carbon emissions, to avoid a patchwork of inconsistent state subsidies. However, it is unclear how PJM will implement changes, or if any changes would be put in place before future capacity auctions, which are an important revenue stream for generators.

These legislative subsidies bring uncertainty to future capacity prices in zones with at-risk nuclear generation, as well as an increased risk of additional rate riders on customers' bills. While PJM and opposing generator associations are working on broad market-based solutions, it is unlikely that changes will be drafted, debated, and adopted in time to benefit the most at-risk nuclear plants. The appeals of the recent legislation are also unlikely to be overturned in the near-term, further supporting the possibility for ZEC-like subsidies and rate rider increases. MISO energy prices, where capacity rates are set for only a year into the future, could see an impact in the near team if states elect to implement ZEC programs. Customers located in MISO territory that are considering long-term contracts should elect to treat capacity as a pass-through component in order to benefit from potentially lower capacity rates due to subsidized nuclear plants bidding into capacity auctions.

For questions or further discussion about these topics, contact your EnerNOC Energy Advisor or talk to an Energy Sourcing Expert.

For additional insight, including updates on electricity and natural gas pricing in the Mid-Atlantic region, read our full report for this month.

Texas
ERCOT Wholesale Spot Power Prices up 16% Year-on-Year in July

Last month, stronger demand and higher natural gas prices drove July day-ahead spot market power prices 16% higher than in the same month last year. Aside from the rebound in natural gas prices, which were recovering from 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 69,525 MW was more than 2,100 MW higher than in July 2016 and set a new record for monthly peak demand going back to 2011. The monthly average day-ahead power price was $31.86/MWh last month across all hubs, whereas the average monthly spot price in July 2016 was $27.46/MWh.

Consumer demand and the cost of fuel used to produce electricity are the two primary drivers of spot market electricity prices. This past July, temperatures in the central footprint of ERCOT were well above seasonal daytime averages, featuring numerous days in excess of 100 degrees Fahrenheit. On balance, the wholesale power prices were propelled higher by delivered prices for natural gas. The monthly average natural gas price in July was $2.966/MMBtu at the Houston Ship Channel delivery point in Texas, about 10% higher than the $2.707/MMBtu average seen in July 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. As mentioned above, the ERCOT system demand peaked at 69,525 MW in July 2017, which is 3% higher than the July 2016 peak load of 67,423 MW. The average daytime high temperature for Austin, TX in July 2017 was 101 degrees Fahrenheit, which is six 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 natural gas generation year-over-year. Imported generation across inter-ties increased share substantially when compared to the same month last year, while both coal and nuclear generation saw a decline in share.

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.

For questions or further discussion about these topics, contact your EnerNOC Energy Advisor or talk to an Energy Sourcing Expert.

For additional insight, including updates on electricity and natural gas pricing in Texas, read our full report for this month.

California
Aliso Canyon Gas Storage Facility to Re-Open

Southern California Gas will be re-opening Aliso Canyon and will begin partial natural gas injections immediately. The facility will be limited to less than one-third of its previous overall capacity, which officials say is just enough to ensure that the Los Angeles area avoids disruptions to energy service.

The decision comes nearly two years after a massive natural gas leak released over 100,000 metric tons of methane over the course of three months. The leak is considered one of the worst methane blowouts in US history, displacing approximately 8,000 families from their homes and sickening thousands of people. According to regulators, the leak was capped in February 2016 and 60% of the wells were taken offline, but the root cause of the leak continues to be under investigation. Meanwhile, 42 wells have been tested and remediated by the oil and gas division and are now available for service.

Customers in California will not see any immediate impact, but it should be noted that Aliso Canyon is a large resource for natural gas in the west. Re-opening the facility should benefit customers in both grid reliability and pricing.

For questions or further discussion about these topics, contact your EnerNOC Energy Advisor or talk to an Energy Sourcing Expert.

For additional insight, including updates on electricity and natural gas pricing in California, read our full report for this month.

Mexico
CFE Default Rates to Decrease for Commercial and Industrial Customers in August

The Mexican utility, the Comisión Federal de Electricidad (CFE), announced that the default electricity prices for commercial and industrial users will decrease in August relative to July. Residential customers will also see their rates fall month-over-month.

Industrial customers will see a tariff rate decrease between 2.6% and 3.3%, and commercial customers will see a decrease of between 1.7% and 2.4% relative to the tariff rates in June. The decrease is the result of minor movement in natural gas prices, which are one of the main determinants of power prices.

It is important to keep in perspective, however, that prices for industrial customers in Mexico in August are up over 30% year-over-year. This is in sharp contrast to the residential tariff, which has enjoyed 32 consecutive months of price decreases. This highlights the fact that large commercial and industrial customers continue to subsidize the residential sector in the country.

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 are offering increasingly competitive rates that can provide both cost relief and greater budget certainty. EnerNOC is actively working to vet new entrants to the supplier market and can assist customers in finding and choosing the best independent contract to manage their costs and risk at the most competitive price.

For questions or further discussion about these topics, contact your EnerNOC Energy Advisor or talk to an Energy Sourcing Expert.

For additional insight, including updates on electricity and natural gas pricing in Mexico, read our full report for this month.

Henry Hub
NYMEX Market Trends

The National Weather Service’s recent adjustment to the August 2017 weather forecast calls for below-normal temperatures for the majority of the lower 48 states, including the major cooling demand centers for the first 10 days of August. This is a meaningful departure from previous forecasts, which predicted that August temperatures would trend above historical norms throughout the month.

Recently, injections into storage have been lackluster. However given the new expectation for mild temperatures and lack of cooling demand, we expect that the pace of storage builds will increase over the next few months. It is our opinion that mild temperatures will prolong the current surplus of gas over the five-year average and put downward pressure on Henry Hub futures contracts. We anticipate that this lull in demand will allow the surplus to hang on into September due to larger storage injections than previously expected.

For questions or further discussion about these topics, contact your EnerNOC Energy Advisor or talk to an Energy Sourcing Expert.

For additional insight into the natural gas market, read our full report for this month.

Authored By The EnerNOC 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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