Energy Procurement Insights for February 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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For analysis of the major issues in the energy markets that could affect your energy costs for the year ahead, download the Energy Intelligence team's new whitepaper, What to Expect from Energy Markets in 2018.

New England
Region Turns to Oil as Cold Snap Drives Gas Prices Up

As temperatures plummeted in late December and early January, many of ISO-NE’s generators switched from natural gas to fuel oil to produce electricity.

Following the polar vortex in 2014 and in anticipation of new ISO-NE rules which will penalize generators for not being able to produce electricity under scarcity conditions, many natural gas-fired generators invested in dual-fuel capabilities. In addition, the price of oil has come down considerably since 2014, from roughly $100/barrel to less than $50/barrel, making it a more economical resource when gas prices start to climb.

Under normal conditions, nuclear energy and natural gas predominantly supply ISO-NE’s system, with coal, hydro, and some renewables (wind, solar, wood, landfill gas, and waste-to-energy) rounding out the supply stack. Oil-fired generation is almost a non-factor. However, as cold weather drives up demand for natural gas for heating, and consequently natural gas prices, generators still turn to oil in large numbers to meet electricity demand. The graph below illustrates the fuel mixtures used to supply grid power over the 10-day stretch from December 25 to January 5. Massachusetts alone consumed more than 2 million barrels of oil in that timeframe, more than doubling total consumption from 2016 and nearly four times more than what was needed in 2017 up to the point, according to a Worcester Telegram & Gazette report.

Although the report claimed Massachusetts Energy and Environment Secretary Matthew Beaton called the environmental impact of the spike in oil burn a “disaster,” the availability of the alternate fuel source did help keep a lid on power prices. While spot power still averaged over $100/MWh for the month of January 2018, it was roughly 36% lower than the spot average in January 2014.

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

New York
Governor Cuomo Unveils Comprehensive Agenda to Combat Climate Change

Earlier this month, during his 2018 State of the State address, New York Governor Cuomo outlined the steps to further reduce emissions and expand the Regional Greenhouse Gas Initiative (RGGI). Several key initiatives could have an impact on the future of electricity in New York. They include:

  • Expanding RGGI to include smaller plants of 25 MW and less. This will impact oil-fired peaking units used to meet demand on critical days.
  • Adopting regulations that will end the use of coal in New York by 2020. New York has already removed 90% of the coal consumed in 2014. Currently, only 200K tons of coal is being consumed for electric generation. This is the equivalent of around 60 MW per hour around the clock.
  • Issuing a solicitation for at least 800 MW of wind generation in 2018 and 2019 with a goal of 2,500 MW by the mid-2020s.
  • Investing $200M to meet an energy storage target of 1,500 MW by 2025. This is a critical portion of the plan as it is the bridge necessary to transform renewable resources that can match peak demand hours.

Critics of the plan highlight its cost and the fact that New York already has some of the highest electricity rates in the country—for example, New York’s focus on offshore wind despite the fact that it is more than twice as costly as onshore wind. Some officials have indicated a desire for the state to have a special tier within the Clean Energy Standard to help subsidize the development of offshore wind. Though appealing politically, does this reflect the best use of ratepayer resources? The bottom line is that, while the agenda does provide some short-term goals, the details are not well-defined. Reducing the diversity of supply could lead to higher and more volatile energy prices.

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

Utilities Seek to Pass Tax Savings Onto Ratepayers

Multiple utilities in the Mid-Atlantic region will seek to pass on savings generated from the Tax Cuts and Jobs Act.

As a result of the law’s reduction in corporate tax rate, from 35% to 21%, regulated utilities in the region face a profit windfall. The various Public Utility Commissions or Public Service Commissions control profits for utilities in the region to protect ratepayers from price gouging. Proactively, representatives from BGE, PEPCO, and Dominion have filed with their respective commissions to pass these savings on to their ratepayers instead of waiting for the traditional rate review process. Any authorized rate change will be recognized on the distribution side of a customer’s bill.

Mid-Atlantic Temperature Outlook

The February temperature outlook for the Mid-Atlantic appears mild overall, with below-average temperatures persisting in the region for the first two weeks of the month giving way to seasonal-to-above-average temperatures. Disagreement between the American and European models highlights a conflict in exactly how much above normal the back half of the month might be. Regardless, a warmer-than-average February would help place bearish pressure on future power pricing in the face of a high-priced prior month.

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

FirstEnergy Wins Appeal Over 2011 RECs Purchase in Ohio Supreme Court

The Ohio legislature established the state Alternative Energy Portfolio Standards (AEPS) when it passed State Bill 221 in 2008. The legislation targeted a 2025 goal to source 25% of all energy generated in Ohio from alternative resources, escalating annually. Half of the generation could be met with any new, converted, or environmentally retrofitted power plants, or "advanced energy resources," located in Ohio. The other half would be met by traditional renewable technologies (wind, solar, biomass, etc.). In 2014, State Bill 310 removed the 12.5% requirement for advanced energy resources, froze the standard for two years, and pushed out the final requirement of 12.5% to 2026. State Bill 310 also removed in-state requirements for compliance and allowed utilities to source compliance from any renewable resource.

For market participants to comply with AEPS, Renewable Energy Credits (RECs) are either earned, through generation ownership, or purchased from brokers or suppliers. RECs represent the environmental benefit associated with one megawatt hour generated by renewable generation. FirstEnergy, which owns competitive generation in Ohio and other states, procures RECs to offset its predominately fossil fuel- and nuclear-heavy fleet. Since 2007, along with utilities and generation owners across the US, FirstEnergy has retired several coal-burning and fuel oil-burning assets (approximately 2,535 MW).

After the Ohio AEPS was established in 2008, FirstEnergy began holding request for proposals (RFP) to procure RECs in 2009, 2010, and 2011. FirstEnergy’s Ohio utilities Cleveland Electric Illuminating, Ohio Edison, and Toledo Edison have a cost recovery mechanism for REC purchases known as the “Alternate Energy Resource” (AER) Rider. The AER rider has the ability to change on a quarterly basis to reflect incurred costs. In September 2011, the Public Utility Commission of Ohio (PUCO) opened a review of FirstEnergy’s procurement history associated with the AER rider.

Nearly two years later, on August 7th, 2013, PUCO closed the review and approved FirstEnergy’s procurement process and REC purchases, with the exception of one auction. A deeper look at the purchase in question focused on an auction run to procure solar RECs (sRECs) and non-solar RECS. PUCO retained Exeter to run a review of FirstEnergy’s process and purchases. According to the PUCO case summary (Case No. 11-5201-EL-RDR), Exeter concluded that the sRECs portion of the RFP was conducted appropriately and the price points reflected current market value. Exeter’s report found that a purchase of all state non-solar RECs were “unreasonably high” and exceeded observed market prices for non-solar RECs for the previous three years. The review was also critical of the lack of contingency planning and recommended that FirstEnergy conduct thorough market analysis prior to conducting another RFP to establish a maximum acceptable price. The final order in 2013 called for FirstEnergy to refund customers $43,362,796.50 plus interest.

FirstEnergy appealed the PUCO’s order to the Ohio Supreme Court a few weeks later in 2013, and the court released its opinion on January 28, 2018. The court acknowledged that the non-solar RECs purchases were imprudent, but declared that PUCO cannot force FirstEnergy to refund customers through "retroactive ratemaking" and any revisions to the law would be borne from the Ohio legislature.

Customers should note that unless retail contracts explicitly pass through AEPS charges, fixed-price contracts include RECs and do not change quarterly. In a story highlighted by Midwest Energy News from April 2017, a PUCO compliance report showed utilities procured RECs in 2015 at roughly a $6.40/MWh premium. The key takeaway is that retail suppliers have a more competitive procurement process yielding a greater benefit for customers who switch.

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

ERCOT Wholesale Spot Power Prices Jump 62% Year-on-Year in January

Last month, bouts of extreme cold helped propel record winter season peak loads and energy prices in the state of Texas. Thus, January day-ahead spot market power prices jumped 62% higher than last year. In addition, delivered natural gas prices rose 26% higher versus the same month a year ago. The gains in energy pricing were the result of two abnormally cold-weather events that saw temperatures plummet to nearly 30 degrees below normal averages for this time of the year. As a result of cold temperatures, the measured peak load of 65,731 MW was 10% higher than in January 2017—a new winter record by more than 6GW. The monthly average day-ahead power price for January 2018 was $37.77/MWh across all hubs, whereas the average monthly spot price in January 2017 was $23.33/MWh.

Consumer demand and the cost of fuel used to produce electricity are the two primary drivers of spot market electricity prices. This past January, temperatures around the central footprint of ERCOT were overall colder than their seasonal daytime averages for the duration of the month. On balance, wholesale power prices were driven by higher delivered prices for natural gas when compared to last year. The monthly average natural gas price in January was $4.060/MMBtu at the Houston Ship Channel delivery point in Texas, about 26% higher than the $3.223/MMBtu average seen in January 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 65,731 MW in January 2018, which is about 10% higher than the January 2017 peak load of 59,650 MW. 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.

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

CAISO Warns of Reliability Issues as Renewable Energy Mandates Threaten Natural Gas Viability

As California becomes more reliant on renewable energy sources to supply the state's power, natural gas and other traditional sources of electricity generation are at risk for closure. Due to the state’s aim to produce 33% of its energy needs from renewable sources by 2020 and 50% by 2030, a recent study published by the California Independent System Operator (CAISO) states that nearly 10,000 MW of gas generation will be at risk of retirement. Some of the state’s natural gas generators are already claiming it is no longer economical to operate at current energy and Resource Adequacy prices.

In order for the state to meet its 2030 renewable energy mandate, 9,635 MW of generation would be required to retire. Natural gas power plants provide over 50% of the electric needs in the state. They provide stability when renewable sources such as solar or wind are not yet producing at their max. Known as a "duck curve," this phenomenon occurs when there is a midday drop in net load due to solar production and a steep ramp up in the late afternoon or evenings after sunset as solar production ramps down. In one scenario that CAISO laid out, it would currently take as little as 1,000 MW to 2,000 MW of gas generation retirements before there would be potential grid reliability issues, especially during high-demand hours.

Earlier in January, the California Public Utilities Commission (CPUC) also approved Pacific Gas & Electric’s (PGE) shutdown of the last operating nuclear power plant in California. The Diablo Canyon facility, producing 2,256 MW, or about 9% of the state’s electricity, is slated to retire when its operating license expires in 2025. Though this closure may not directly affect customers immediately, PGE will continue to purchase power from other natural gas fleets when it needs to increase capacity for reliability.

While the state is continuously reducing its reliance on natural gas, it still represents the majority fuel source used for generation. Natural gas prices should remain steady for the near future. Any customer looking to sign a retail gas contract will likely benefit from the less volatile, flat market.

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

Mexico Will Accept Bids for Private Transmission Line

For the first time under the new deregulated energy regime, Mexico will contract out for private bids to construct a transmission line that will connect the Baja California system to the Mexico national interconnect that comprises the mainland of the country. The project, which is estimated to cost approximately $1.1B for a 1.5 GW direct current transmission line, would connect Mexicali in Baja California to Hermosillo on the national interconnection side. The Baja California network is already connected to the US system through California and enjoys some of the lowest-priced electricity in the country as a result. The new line would help connect that cheap power to the mainland as well as incorporate new renewables projects that are going to be constructed on the peninsula. Customers in the mainland will benefit from cheaper, cleaner electricity delivered from Baja California, which in turn will have an off taker to support the development of more renewable power.

Interestingly, the project is stirring a conversation north of the border in Texas. Currently, the power grids in California, US, and Baja California, Mexico, are interconnected. When the new transmission line interconnects Baja California and the national Mexican interconnection, power will be able to flow from California into Texas via Mexico. ERCOT, the grid operator that covers most of Texas, is not currently regulated by FERC because its grid is not synchronously interconnected with the rest of the country—this power line may change that. Long known for its independence streak, Texas seems unlikely to risk their electricity independence, as the chair of the Texas Public Utilities Commission (PUCT) is already warning. Rather than cede their independence to FERC, ERCOT will more likely cut power ties to the Mexican grid.

This fight is not without implications for customers in Mexico. Currently, there are a number of facilities siting in Texas and sending a portion of their power exclusively to Mexico. Should ERCOT cut ties with the country, that power will need to be supplied from elsewhere, potentially increasing power prices for customers along the Texas border.

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

Henry Hub
2018 NYMEX Holds Premium Over 2019-2021

The start of 2018 is proving to be the new frontier when it comes to natural gas supply and demand, the two major fundamental factors that impact gas pricing. Both gas production and consumption continue to grow and reach previously unforeseen levels. Much of the production growth will come from the shale region, where production is expected to average over 28 Bcf/day in 2018, over 30 Bcf/day in 2019, and around 32.5 Bcf/day in 2020, according to Platts. The forecasted growth puts more risk in the 2018 and 2019 contracts, likely until those contracts reach settlement, making fixed-basis contracts attractive for strategic supply risk mitigation.

From a strategic gas purchasing perspective, this creates an increased value on locking in basis supply contracts as opportunities present themselves in regions such as Dominion South and TetCo M-3, where pricing is closely linked to northeast shale production.

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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