Montana to study customer-generator costs, benefits

Thursday, June 22, 2017

Montana utility regulators are preparing to study the costs and benefits of distributed solar energy projects and other customer-generators.  The results could reshape the way net-metered customers are charged for electric service, including the creation of a separate service classification and rates for customer-generators.

Earlier this year, the Montana legislature enacted House Bill 219, a law requiring utility NorthWestern Corp. to "conduct a study of the costs and benefits of customer-generators," for submission to the state Public Service Commission to inform future ratemaking.  The law allowed the Commission to establish "minimum information requirements" for inclusion in the study.

On June 16, 2017, the Commission posted a Notice of Opportunity to Comment on potential benefit and cost elements and study questions.  That notice identified categories of potential benefits including avoided energy costs, avoided capacity costs, avoided transmission and distribution capacity costs, avoided system losses, avoided renewable portfolio standard compliance costs, avoided environmental compliance costs, market price suppression effects, avoided risk, avoided grid support services costs, avoided outages costs, and non-energy benefits.  It also identified categories of potential costs, including reduced revenue, administrative costs, interconnection, integration, and cost shifts in production, transmission, and distribution.

The Commission's notice also posed a series of questions relevant to cost-benefit studies, including:
  • What, if any, assumptions regarding the adoption rate of solar or other net metering technologies should the Commission specify?
  • What, if any, time frame for calculating benefits and costs should the Commission specify (e.g., 10 years, 20 years, etc.)?
  • What, if any, assumptions regarding utility rates should the Commission specify (e.g., rate of increase, changes in rate design (time-of-use, other))?
  • What, if any, methodology for cost-effectiveness tests should the Commission specify (e.g., standard practice manual or the Cost Benefit Framework developed by the Electric Power Research Institute)?
  • What cost-effectiveness perspective(s) should the Commission require be evaluated (e.g., societal, utility/program administrator, ratepayer, participant)?
  • Should the Commission specify the generating resource avoided by net-metered systems?  If so, what generating unit should be used?
  • Should the Commission specify a particular locational attribute that counts as either a benefit or cost adder/subtractor?
  • What, if any, other compensation approaches in addition to net metering should be assessed in the study NorthWestern is required to conduct?
The Commission invited interested persons to submit written comments addressing the potential benefit and cost elements and study questions identified above no later than July 7, 2017.  It also directed the utility to provide information on the scale and scope of data it has collected, or intends to collect, regarding variations in the usage profiles of customer-generators compared to other customers in the same rate class.

US considers Arctic offshore oil exploration

Monday, June 19, 2017

U.S. regulators are evaluating an application by a company seeking to explore for oil in the Arctic.

On June 12, the federal Bureau of Ocean Energy Management or BOEM announced that it had deemed Eni US Operating Co.'s exploration plan (or EP) to be submitted, and invited public comment on the plan. The company is a subsidiary of the Italian gas and oil company Eni S.p.A.

Under federal law, an Exploration Plan describes all exploration activities planned by the operator for a specific lease or leases, including information on locations, timing, drilling processes, and actions to be taken to meet safety and environmental standards and to protect access to subsistence resources. 

According to its Exploration Plan for the Nikaitchuq North Project dated March 2017, Eni proposes to drill into submerged lands on the Outer Continental Shelf beneath the Beaufort Sea, from its existing Spy Island drillsite which is located in Alaska state-jurisdictional waters.  Eni has secured federal leases for the "Alaska – Harrison Bay Block 6423 Unit".

BOEM's decision to deem the Exploration Plan as submitted triggers various deadlines:
While the Obama administration placed an indefinite hold on further leasing in much of the Beaufort Sea and other U.S. Arctic waters in December 2016, the Trump administration has expressed interest in reversing this decision in favor of expanded U.S. Arctic oil exploration and production.  The Arctic Ocean is home to significant fossil fuel resources, but environmental and logistical concerns have recently proved challenging

Rover pipeline HDD spill investigation

Friday, June 16, 2017

Federal energy regulators overseeing the development of a new interstate natural gas pipeline have announced the opening of an investigation, following the inadvertent release of about 2 million gallons of drilling fluid from a horizontal directional drill operation.

Rover Pipeline LLC describes itself as a new interstate natural gas pipeline that is designed to transport 3.25 billion cubic feet per day (Bcf/day) of natural gas to markets in the Midwest, Northeast, East Coast, Gulf Coast and Canada.  The Rover project received a Certificate of Public Convenience and Necessity from the Federal Energy Regulatory Commission (FERC) on February 2, 2017, and construction commenced.  The Commission's Order Issuing Certificates included an environmental condition requiring Rover to adhere to construction procedures as described in its application and identified in the Commission’s Environmental Impact Statement (EIS).  As described by FERC, "Rover committed to use drilling fluid composed only of a 'slurry made of nontoxic/non-hazardous bentonite clay and water.'"

On April 13, 2017, Rover alerted the Ohio Environmental Protection Agency and FERC’s Compliance Monitor that it had located an inadvertent return of drilling fluid while completing the HDD of the Tuscarawas River.  Two days later, on April 15, 2017, Rover alerted Commission staff of the release. According to a May 10, 2017 letter from Commission staff, the HDD release resulted in the deposition of approximately 2 million gallons of bentonite-based drilling fluid into a state-classified "high-quality" wetland, covering about 6.5 acres of wetland soils and vegetation with bentonite clay and bore-hole cuttings.  Through that May 10 letter, the Commission suspended further new HDD activity on the Rover project.

But the Commission isn't done with its investigation of the incident, according to a June 1, 2017 letter it sent to Rover.  In the letter, Commission staff states that on May 26, the Ohio Environmental Protection Agency "notified FERC staff and Rover of the presence of petroleum hydrocarbon constituents, commonly found in diesel fuel, in samples of drilling fluid from various locations near the HDD of the Tuscarawas River."  The letter reiterates Rover's descriptions of the drilling fluid to be used, and the related environmental condition imposed in the Order Issuing Certificates.  It then describes a newly-launched enforcement investigation:
Based on the results of the sampling conducted by Ohio EPA, the Commission’s Office of Enforcement will immediately initiate an investigation to determine the underlying facts that led to the presence of petroleum hydrocarbons in the drilling fluid. Rover is reminded of the data preservation directive in Commission staff's May 10 letter, which includes the requirement that Rover preserve and maintain all documents and information related to the composition, acquisition, preparation, and disposal of the drilling fluid used at Rover's HDD of the Tuscarawas River. We also expect Rover’s full and immediate cooperation with the Commission’s Office of Enforcement regarding this investigation.
Both sitting FERC Commissioners issued a joint statement expressing support for their staff's recent actions on the project:
We are troubled by the Tuscarawas River HDD spill and the indications that diesel fuel is present in the drilling mud utilized for the Tuscarawas River HDD. Although we have no reason at this point to believe the release represents an imminent threat to human health or the environment, this incident raises concerns about potential long-term environmental impacts, including impacts on sensitive wetlands in Ohio. Moreover, the presence of diesel fuel in the drilling mud is inconsistent with the commitments made by Rover on which the Commission relied to certificate its project. We fully support the action of OEP and OE staff to address and investigate these issues.
Further investigation into the Rover pipeline's compliance with its FERC certificate requirements will follow.

Forest Service approves transmission lines

The U.S. Forest Service has released its final approvals for two major electricity transmission lines proposed for development across several western states, issuing Records of Decision for the TransWest Express and Energy Gateway South projects.

The TransWest Express Transmission Project is a high-voltage, direct current regional electric transmission system proposed by TransWest Express LLC.  The 600-kilovolt, bidirectional transmission line would connect the Marketplace Hub near Las Vegas, Nevada, to south-central Wyoming.  A core value of the project is its ability to provide the transmission infrastructure and 3,000 MW of capacity necessary to deliver approximately 20,000 GWh/yr of clean and sustainable electric energy generated in Wyoming (mostly from wind) to Arizona, Nevada and southern California.  Future plans could include another interconnection near Delta, Utah.  The project has links to the Chokecherry and Sierra Madre Wind Energy Project, a proposed 3,000 MW wind farm to be sited in southern Wyoming.

Energy Gateway South is one segment of the larger Energy Gateway Transmission Expansion under development by PacifiCorp.  The 500-kilovolt alternating-current transmission line would run about 400 miles from the planned Aeolus Substation in southeastern Wyoming into the Clover Substation near Mona, Utah.

In each case, the project proponents applied to the Bureau of Land Management and Forest Service for a right-of-way grant and special-use permit to construct, operate, and maintain high voltage transmission lines on federally managed land.  The BLM signed Records of Decision on December 13, 2016 for both projects authorizing the agency to issue a 250-foot-wide right-of-way for the line and areas for other project components.
On May 31, the USFS released its final Records of Decision for the TransWest Express and Energy Gateway South projects.  In each case, the Forest Service approved the project and issued a special-use authorization.

Renewable portfolio standards and clean energy mandates are driving the development of wind farms like Chokecherry and Sierra Madre, as well as transmission lines like TransWest Express and Energy Gateway South.  Some of these projects raise issues of siting, rate impacts, and how costs should be allocated.  At the same time, a number of other major transmission lines have been proposed around the country, many of which are similarly motivated by the opportunity to connect new renewable generating resources with distant utilities and consumers. 

North American electric reliability summer 2017

Wednesday, June 14, 2017

The North American bulk power system is expected to have sufficient resources to meet summer electricity demand for 2017, according to the U.S. electric reliability organization NERC.

The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority whose mission is to assure the reliability of the bulk power system in North America.  Operating under the oversight of the Federal Energy Regulatory Commission, NERC develops and enforces mandatory reliability standards.

NERC publishes an annual Summer Reliability Assessment.  This document identifies, assesses, and reports on summer resource deficiencies and operating reliability concerns, peak electricity demand and supply changes, and unique regional challenges. In the report, NERC calculates an Anticipated Reserve Margin for each region, based on the difference between anticipated resources' projected capability and forecasted peak load.

According to NERC's 2017 Summer Reliability Assessment, most regions are expected to meet their recommended reference levels for reserve margin -- but New England may have tighter supply conditions, "primarily due to approximately 700MW of delayed new resources that were expected to be available to serve load for this summer."  As NERC noted in its report, "During extreme weather, there is an increasing risk of operational issues when reserve margins are tight. If forecasted summer conditions materialize, New England may need to rely on import capabilities from neighboring areas as well as the possible implementation of emergency operating procedures (EOPs). These actions are anticipated to provide sufficient energy or load relief to cover the forecasted deficiency in operable capacity."

NERC's 2017 Summer Reliability Assessment also examined the solar eclipse anticipated on August 21, finding that it "is not expected to impact the reliability of the bulk power system."  As noted in NERC's assessment, "Total solar capacity (distribution and transmission connected) in the U.S. has increased from 5 MW in 2000 to 42,619 MW in 2016. As the number of photovoltaic generators on the power system increases, the risk created by solar eclipses to reliable system operations will increase as well."

New England power plant portfolio

Tuesday, June 13, 2017

A recent report by the New England wholesale electricity market's monitor sheds light on the region's portfolio of generation resources, and how they are changing.

The ISO New England, Inc. Internal Market Monitor's 2016 Annual Markets Report provides information on the average age of the region's generation fleet, broken down by fuel type.
Figure 2-4, 2016 Annual Markets Report.

According to the report, the average age of New England’s generators is 30 years, but different resource types show diverging average ages.  New England's coal-fired power plants are the oldest on average, with an average age of 53 years.  Oil generators' average age is 37 years.  Natural gas generators' average age is 18 years, reflecting more recent construction.  Wind and solar have the youngest fleet average age, at 6 and 3 years respectively.

Another chart in the 2016 Annual Markets Report shows generator additions, retirements, and cumulative change.

Figure 2-7, 2016 Annual Markets Report.
This chart shows that over 2,000 megawatts of capacity was added to the grid between the Forward Capacity Market's launch and the 2016-2017 capacity commitment period (CCP 7).  But the retirement of a number of large resources for CCP 8 (including the Brayton Point coal unit and Vermont Yankee Nuclear Power Station) "left the market short of capacity and led to higher auction clearing prices."  According to the market monitor, the market reacted to this shortfall in the subsequent three auctions, yielding higher prices that can support new entry in excess of retirement.

New England wholesale electricity market report 2016

Monday, June 12, 2017

Overall, the New England wholesale electricity markets performed well in 2016, according to a report by the grid operator's internal market monitor.

ISO New England, Inc. operates the bulk transmission system and wholesale electricity markets for most of New England.  ISO-NE's Internal Market Monitor is an internal ISO department charged with performing regular market assessments and reporting, as well as "the daily detection and mitigation (lessening) of the effects of any anti-competitive behavior in the wholesale markets or market products."

The market monitor released its most recent report last month.  According to the Internal Market Monitor's 2016 Annual Markets Report, the total wholesale cost of regional electricity in 2016 was $7.6 billion.  Compared to 2015, the total wholesale cost in 2016 dropped 18%, or by $1.7 billion.  According to the report, this was due to the decline in energy costs "which continue to be driven primarily by natural gas prices."
Figure 1-1, 2016 Annual Markets Report.

The report also noted that "wholesale costs to date have been influenced by low capacity market prices that ranged from $2.95 to $4.50/kW-month."  Based on the results from Forward Capacity Auctions 8 through 11, "low capacity prices will continue until the 2017-18 capacity commitment period (associated with the eighth forward capacity auction, or FCA 8) when capacity market prices will increase, reflecting the end of a period when the New England system was structurally long on capacity."

According to the report, both the Forward Capacity Market and the energy market "exhibited competitive outcomes despite the presence of structural market power."

At the same time, the report notes an increase in transmission costs:
Transmission costs totaled $2.1 billion in 2016. Both costs and the regional transmission rate increased by approximately 6% in 2016 over the 2015 rate, moving from $98.07 per kW/yr to $103.30 per kW/yr.
The report attributes the increase to "investment in new regional transmission infrastructure to address deficiencies in meeting reliability criteria, as well as investment to address deficiencies in the condition of existing regional transmission assets."