Energy Procurement Insights for July 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, 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 Senate Passes Landmark Renewable Energy Mandate

On June 14, the Massachusetts state senate unanimously cleared an omnibus renewable energy bill calling for a transition to 100% renewable energy by 2047. The Senate Bill 2545, dubbed an “An act to promote a clean energy future,” will revisit benchmarks of emissions reductions from 1990 levels set for 2030 and 2040, call for the installation of 2 gigawatts (GW) of energy storage capacity by 2025, and lift limits on net-metering caps, among other measures. The bill also suggests a feasibility study will be conducted on the addition of 5 GW of offshore wind by 2035. Although there is considerable political momentum to address climate change and continue to install mitigation efforts in Massachusetts, it seems highly unlikely that the Massachusetts House of Representatives would pass such a sweeping piece of legislation.

The Senate bill would require utilities and competitive suppliers of electricity to purchase increasing amounts of renewable energy under the Renewable Portfolio Standard (RPS) program. Specifically, the bill proposes raising the annual growth rate in Class I resources from the current 1% to 3% annually, growing from 13% in 2018 to 100% by 2047. Currently, obligations under the Clean Energy Standard (CES), passed in August of 2017, are driving the schedule of renewable energy implementation in the state as it exceeds current RPS mandates. Under the proposed RPS increase, Class I percentages would exceed CES requirements starting in 2022, and since RPS compliance also satisfies the CES, the new legislation would effectively supplant the CES at that time.

Since the CES has already effectively increased the requirement of Class I RECs, the proposed legislation should not impact rates until 2022, when the RPS compliance percentage will exceed that of the CES. Between 2022 and 2025, EnerNOC estimates the impact to average $0.00075/kWh. However, the expected supply-side consequences of the senate bill could vary depending on future REC prices. Other provisions, such as the storage requirement and further offshore wind procurements, will likely fall on the shoulders of distribution utilities, and MA ratepayers would see those increases on the distribution side of their bill.

While significant uncertainty remains around which aspects of the bill (or how much of it) will make it through the Massachusetts House, any measure to further mandate emissions in Massachusetts will increase costs for ratepayers (particularly in the near-term). The exact extent of any such increase will become clearer as this bill or pieces of it become law. Also, customers in long-term electricity contracts should be wary as suppliers may invoke a "change-in-law" clause to recoup any additional costs associated with any new supplier requirements (such as an increasing RPS).

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

New York
Carbon Pricing Coming to New York

Implementation of the Clean Energy Standard, including Zero Emission Credits, moved the state closer to achieving its objective to reduce greenhouse gas (GHG) emissions 40% from 1990 levels by 2030 and 80% by 2050. However, the wholesale electricity market did not align with the state’s aggressive GHG goal. To achieve its goal, the NYISO would require generators to incorporate the cost of carbon (CO2) emissions into its bidding process to incentivize the development of cleaner resources.

Under the current proposal, the New York Public Service Commission will come up with the gross social cost of carbon (SCC), but would allow those holding allowances from the Regional Greenhouse Gas Initiative (RGGI) to deduct these costs from the SCC. The NYISO will require generators to incorporate carbon pricing into each component of their energy offer (startup, minimum generations, and incremental cost curves). The NYISO is taking this approach, as opposed to requiring suppliers to submit emission rates, because it does not require any additional modification of their dispatch and pricing optimization models. Suppliers will be still be compensated on the full Locational Based Marginal Price (LBMP). In addition, the NYISO would also charge electricity imports for emissions and credit exports for avoided emissions to prevent “leakage” and any market distortion. The proposal aimed to incorporate a carbon price in a way that is transparent and economically efficient, and which avoids major cost shifts among consumers and provides market or regulatory stability.

Raising the LBMP will increase revenues for Tier 1 renewables, which would reduce the future REC prices. However, the actual amount of the decrease remains unknown, as REC contracts guarantee prices for the duration of the REC contract, while future carbon prices will not. In addition, there will be an impact on ZEC pricing. The ZEC, established in 2016 to compensate at-risk nuclear power plants for avoiding emissions, will come under price pressure. The formulated ZEC price would automatically adjust to reflect changes in wholesale energy and capacity prices. Current estimates expect the carbon charge to decrease ZEC price on a dollar-for-dollar basis. Some participants believe the implementation of carbon pricing should lead to the conclusion of the ZEC program to avoid double counting of carbon cost credits. Currently, the cost of ZECs on the customer is around $0.0032 per kWh ($3.20/MWh).

The current generation mix from Downstate (Albany south (Zones F-K)) is predominately sourced from natural gas generation. With the retirement of the Indian Point Nuclear power plant in 2020 and 2021, the fuel mix will become more natural gas-driven. The impact of this shift would put undue price pressure on customers located downstate, where zero emission resources represent less than 10% of the current generation mix. In comparison, nearly 90% of Upstate (Zone A-E) generation comes from zero carbon emissions.  Customers in the high-emission areas (Downstate) could see carbon charge residuals collected from suppliers through a cost levelizing allocation that their Load Serving Entity would allocate to the customers. According to Brattle Group analysis of carbon pricing, the net impact on customers is relatively small (see figure below).

If we look at around-the-clock price in NYISO Zone J (New York City) in terms of dollars per megawatt hour, the effects of these proposals are plain to see. The state has proposed setting the NYISO proposal’s effective date for 2021, not 2023. The bottom line is that whenever NYISO finalizes the de-carbonization proposal, prices will spike dramatically.  We are already seeing the impact of this in the forward markets.

State and federal regulators could still shake things up, and there is a good deal of uncertainty. From what they are seeing now, traders and analysts expect de-carbonization to drive energy prices up by $10/MWh or more when it comes into effect in NYISO. The impact is not limited to Zone J; prices across the state are creeping up in reaction to May’s proposals. NYISO Zone A (Buffalo area) has seen around-the-clock prices increase $4.50/MWh.

For deals running beyond 2021, customers should continue to pass through REC and ZEC costs, as the impact of carbon pricing should lower the cost of the Clean Energy Standard. In addition, the state has not finalized all the details of carbon pricing, and changes to the current plan could impact future prices. Therefore, locking in prices beyond 2020 at this point comes with some risk.

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

Mid-Atlantic
PJM Releases Updated NITS Rates Effective July 1, 2018

On June 27, PJM posted updates to the Network Integration Transmission Service (NITS) prices, which can be seen in the chart below. The latest round of updates include NITS rate reductions in two zones, Duquesne (DLCO) and MAIT, which is comprised of METED and PENELEC. These reductions will be billed effective July 1, 2018 going forward until the rates change again. Duquesne NITS rates increased by 10% with the June NITS filing, but these rates were reduced in the latest filing by 2%. MAIT (METED and PENELEC) NITS rates increased 15% in the January posting for half of the 2018 year, but have since been reduced by 4% in the latest PJM posting.

NITS charges are paid by every PJM customer in each respective zone based on their transmission tag. Transmission tags are calculated based on a customer’s demand during hours when the transmission system experiences peak congestion. These hours typically coincide with the periods of highest demand.

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

Midwest
Ameren Missouri Customers Offered Greater Access to Renewables

In the latest push for green resources, Ameren Missouri will begin offering commercial and industrial customers greater access to renewable generation through its Renewable Choice Program. Historically, it has been difficult for customers in regulated utility zones to gain access to renewable sources to meet their sustainability goals. The program will allow customers in these categories, including municipalities, to meet 100% of their usage from renewable sources.

The new Renewable Choice program will add 200 MW of renewable generation and up to 200 MW through purchase agreements. This is in addition to the 700 MW of wind generation additions proposed in Ameren’s 2017 Integrated Resource Plan. Each of these programs reflect the changing demands of stakeholders in the utility zone, who find it necessary to source an increasing amount of their electricity demand from green resources. Traditionally, customers in regulated utility zones, such as Ameren Missouri, have had difficulty meeting corporate sustainability goals without installing behind-the-meter capacity on-premises or through virtual power purchase agreements. Last year, Consumers Energy in Michigan implemented a similar program, which set a target of 6,000 MW of renewable generation by 2050.

The programs are consistent with the shift in fuel mix taking place in the Midwest. Covered in depth in previous Midwest commentaries, the MISO generation queue is overwhelmingly skewed toward an increase in renewable and natural gas generation. The graphic below shows the current MISO generation queue from the RTO’s June 2018 Monthly Market Report.

The planned and completed projects shown total approximately 35 GW in 2017 and 40 GW in 2018, the vast majority of which are wind and solar projects, and the remainder being primarily natural gas. Further support for this shift can be found in planned coal retirements. Ameren plans to retire half of its coal-fired generation by 2022, consistent with Michigan’s goal of complete coal retirement by 2040.

Customers in regulated utility zones such as Ameren Missouri and Consumers Energy in Michigan will have increasing access to renewable generation to meet sustainability goals. The Renewable Choice Program makes meeting these goals easier, as they offer an alternative to behind-the-meter installations or virtual power purchase agreements. These programs reflect a shift in the fuel mix in MISO, which is largely dominated by wind and solar projects. It is likely there will be an increase in this type of program in the coming years.

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

Texas
New June Peak Sets Tone for Balance of Summer

ERCOT set a new June peak record this year when demand reached 69,031 MW on June 27, eclipsing the previous June record of 67,633 MW, which was set last year. In fact, there were six other days in June with peaks that would have beaten last year’s record, keeping in line with the RTOs expectations of load growth in the region. As a whole, ERCOT’s average hourly load was roughly 10% higher than last year, while the new peak load was only 2% above last year’s peak. The higher average hourly load occurred almost directly as a result of temperatures in the region, where Total Degree Days (TDD) were 10% above the 10-year average for the month.

Despite the bullish temperature and load, power pricing failed to respond to the degree that market participants predicted it would. The July-August ATC strip to North Hub entered June trading at $102/MWh, but closed out the month at $73/MWh, down 28% over the month. This was a result of LMPs throughout June coming in well under expectations, averaging $30.35/MWh for ATC at North Hub. Higher demands were satisfied without any sustained real-time capacity issues. With current forecasts from the CPC indicating a slight chance of an above-average July through September, we expect June to be the model for the balance of the summer. We expect the trend to continue with new peak records set in July, August, and September, while the forward heat rate moves closer to the level from the start of the year.

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

Mexico
Mexico Customers Face Growing Number of Options in Competitive Energy Market

Just two and a half years after the official deregulation of the energy market began in January 2016, the options for customers considering switching to third-party supply are growing. The number of registered qualified suppliers is increasing, and the diverse group is able to offer a variety of product types and lengths depending on the requirements of each customer.

In a recent RFP, EnerNOC received more 30 distinct offers from 13 different suppliers. The offers spanned a range of terms and covered a variety of products.

Contract options have included short-term (3 to 5 years) and long-term (10 to 20 years) Power Purchase Agreements (PPAs) for 100% renewable power. Nonrenewable power options included contracts that provide a fixed percentage discount to the CFE basic service tariff, contracts indexed to gas prices or indexed to day-ahead energy prices, and fixed all-in offers. Contract terms ranged from shorter term (1 to 5 years) to longer term (10+ years).   

Payment terms in some cases may be flexible beyond the standard 10-day term, though offers for longer payment terms may come at a premium. Bandwidth can also vary widely and also comes at a premium. Due to the lack of a forward power market in the country, suppliers generally do not offer more than +/- 5% bandwidth on contracts, though they will work closely with customers to create accurate power schedules.

Customers can now take advantage of a variety of third-party supply options thanks to the growing supplier community and diversity of products. Customers can choose to lock in budget certainty with a fixed, all-in price product, or take advantage of offers that guarantee savings relative to the CFE supply. Customers can elect to sign long-term renewable PPAs or short-term brown power contracts. Since the market is still maturing, suppliers have not coalesced around a single offer structure, leaving customers with a full menu of options for whatever suits their needs best.

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

California
Amended Senate Bill Seeks to Reform Direct Access Program

On June 13, the California Senate voted 37-0 in favor of requiring the California Public Utilities Commission (CPUC) to eliminate the cap for customers to participate in the Direct Access program. Starting July 1, 2019, and spanning no longer than three years following, Senate Bill 237 would force the commission to adopt and implement a policy to allow all nonresidential end-use customers to purchase electricity from any approved energy supplier. 

As currently constructed, Direct Access is a retail electric program that allows certain approved customers the ability to purchase electricity from an Electricity Service Provider (ESP) instead of being subject to utility rates. Only about 13% of the total commercial and industrial load in each utility has the ability to shop, amounting to approximately 17,000 customer accounts in the state. The majority of Direct Access customers have a load between 20-500 kW per month. The only way for new customers to join is when the overall utility load increases or if other customers drop out of the program. Prospective customers have been placed in a lottery system for any available space under the respective utility’s load cap.

More and more customers have been leaving the investor-owned utilities in California, joining Community Choice Aggregators or purchasing directly from renewable generators. The goal of this bill is to encourage competition, which should reduce prices, enabling commercial and industrial customers to shop for their supply and make cost-effective purchasing decisions. The bill will also help more customers meet or exceed California’s existing renewable energy mandates, as ESPs are required to achieve the same environmental goals as the utility. There is no timeline set for when this could potentially be signed into law.

How California's Changing Time-of-Use Rates Will Impact Customers

Amid a steady rise in renewable power, California’s demand curve has undergone a radical transformation—a phenomenon which is commonly referred to as the “duck curve.” In response, utilities in the state are implementing new time-of-use (TOU) rate schedules, which will have a substantial impact on energy costs for California businesses. Last year, San Diego Gas & Electric (SDG&E) shifted its on-peak hours to the late-afternoon/early evening, when demand tends to spike on the grid. Facing the same challenges, Pacific Gas & Electric (PG&E) and Southern California Edison (SCE) are in the process of making similar changes to their TOU schedules as well. These changes could significantly drive up operating expenses for large energy users across California, and will impact the economic performance of standalone solar photovoltaic (PV) systems deployed on-site.

On Wednesday, July 18, Energy Manager Today will host a 30-minute live webinar where experts from EnerNOC will:

  • Walk through a sample California organization’s utility bills to illustrate the impact of changing TOU rates and schedules on cost
  • Break down how these rates will disrupt the financial results of a standalone behind-the-meter solar PV system in California
  • Explain how combining energy storage with a solar PV system would affect costs for a customer facing new TOU rates

Register for the Webinar

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

Henry Hub
Continued Summer Heat Likely Bullish for 2018 & 2019 NYMEX Pricing

Since May 1, temperatures across the US rarely dipped below normal, forcing an increase in cooling demand for natural gas compared to previous expectations. Current forecasts from NOAA call for above-normal temperatures to continue through mid-July and possibly beyond. The hot temperatures will likely be bullish for NYMEX pricing because more gas will be used for power generation, as we explain in detail below. The potential bullish impact of elevated demand will result in smaller injections into gas storage compared to normal summer temperatures.  Cooling degree days (CDDs) reached 70 CDDs for week ending June 21, versus 18 CDDs during the same period last year. The chart below tracks the temperatures from 5/1/2018 through mid-July (forecast) versus normal temperatures for this timeframe.

The weather desk at Constellation expects temperatures in July and August to track more closely to normal than June actual temperatures. Normal July and August temperatures would allow gas storage to close the gap with historical storage-level benchmarks. The storage deficit is likely to shrink as long as annual growth of another 1-2 Bcf/day occurs by the end of 2018, as predicted by S&P Global. Gas storage is unlikely to reach the 5-year average of 3.86 Tcf at the end of injection season. However, year-over-year supply growth is likely to minimize the upward NYMEX pressure associated with the storage shortcoming versus five-year average. The market is likely to favor a refill to around 3.5 Tcf by late October to early November. The added production would exert bearish pressure to the remaining summer NYMEX contracts (through October). In the meantime, 2018 NYMEX contracts are likely to hold on to the premium versus 2019-2022 until the heat drops to normal temperatures and the supply growth becomes real. S&P Global foresees an additional 2-4 Bcf per day of supply growth by late 2019. As a result, volatility is likely to remain in the meantime while the market searches for balance between supply and demand.

For further updates on the natural gas markets, 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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