FERC 2015 Report on Enforcement

Monday, November 23, 2015

The enforcement arm of the Federal Energy Regulatory Commission has released a report describing its enforcement activities in fiscal year 2015.

The 69-page 2015 FERC staff report on enforcement draws its organization from that of the Commission's Office of Enforcement.  The report presents public summaries of activity by each of the Office’s four divisions -- Investigations, Audits, Energy Market Oversight, and Analytics and Surveillance.  Of these, Investigations and Audits are the most likely to lead to penalties or other direct enforcement action, while Market Oversight and Analytics typically play more of a background role, supporting the Commission's investigations and audits.

According to the report, the Investigations division opened 19 new investigations in fiscal 2015, and closed 22 (through settlement or "no action").  Major settlements in fiscal 2015 focused on the major 2011 Southwest power outage, with the Commission concluding its multiyear investigation into that outage and its causes.  In all, staff obtained settlements resulting in almost $26.25 million in civil penalties and disgorgement of $1 million in unjust profits. All settlements included reporting requirements and provisions requiring the subjects to enhance compliance programs.

The FERC enforcement office's Audits division periodically checks the records of licensees and public utilities to evaluate their compliance with the statutes and regulations administered by the Commission.  It reportedly performed 22 financial and operational audits of public utilities and oil and natural gas pipelines.  The report states that these audits led to 360 recommendations for corrective action, and refunds and recoveries totaling more than $26.3 million.

Generally speaking, the annual staff enforcement report is a summary of what's already happened.  In other words, the enforcement activity described in the annual report has already occurred.  Much of that activity was public; any civil penalties or other remedies described in the report are generally imposed and documented in separate, preexisting proceedings.  The report does also provide summary level information on some non-public Enforcement activities, like self-reported violations or investigations closed without public enforcement action.

The enforcement report also provides an important look into how the Commission staff view their work -- the enforcement office's patterns, trends, and priorities, as expressed by the people doing the enforcing.  By following the Commission's enforcement activity throughout the year, and comparing that history to staff's view of the year, the enforcement office's points of emphasis come into focus.  As expected, in fiscal year 2015, these included fraud and market manipulation, serious violations of mandatory reliability standards, and conduct that the office found to threaten the transparency of regulated markets.

The Office of Enforcement's annual report can also be compared to previous reports dating back to at least 2007.  Compared to some recent years, fiscal 2015 saw a relatively lower total penalty amount resulting from enforcement action.  (Compare 2015's $26.3 million in penalties and $1 million in disgorgement, with 2013's over $304 million in civil penalties and disgorgement of almost $141 million in unjust profits.)

But experience has shown that there can be difficulty, or at least delay, affecting whether FERC will actually collect that money.  The report notes that in fiscal 2015, Enforcement filed three new petitions in federal district court to enforce earlier Commission orders assessing civil penalties.  Along with an anti-manipulation case tried in 2015 before a FERC Administrative Law Judge, the report notes that staff is waging district court and administrative litigation to recover over $500 million in civil penalties and disgorgement.

ISO-NE files IRC-related values for 2019-2020

Thursday, November 19, 2015

In advance of an upcoming auction to sell electric generating capacity into the New England market, regional grid operator ISO New England Inc. has submitted key information about its plans to the Federal Energy Regulatory Commission.

ISO New England is the private, non-profit entity that serves as the regional transmission organization for New England.  In this role, ISO-NE plans and operates the New England bulk power system, administers New England’s organized wholesale electricity market, and has some responsibility over system reliability.  Reliability can be stated in terms of a loss of load expectation or “LOLE”, which measures how often non-interruptible customers are disconnected.

New England has adopted a capacity market as part of its wholesale electricity market structure.  One aspect of system reliability is ensuring sufficient generating capacity is available to meet consumer demand.  Pursuant to Section III.13 of the Tariff, the ISO administers periodic Forward Capacity Auctions, or FCAs, in order “to procure the amount of capacity needed in the New England Control Area.”

ISO-NE will hold its tenth Forward Capacity Auction in February 2016, covering the 2019-2020 Capacity Commitment Period.  To do so, ISO-NE must first identify how much generation will be needed to meet reliability standards in light of total forecasted load requirements for the New England Control Area and to maintain sufficient reserve capacity to meet reliability standards.  One key value characterizing this need is the "Installed Capacity Requirement" or ICR.  ICR refers to the amount of resources needed to meet the reliability requirements defined for the New England Control Area of disconnecting non-interruptible customers no more than once every ten years.  Under Section 205 of the Federal Power Act, ISO-NE files with the FERC proposed ICR-Related Values for the each auction.

On November 10, 2015, ISO New England submitted to the FERC its Installed Capacity Requirement, Local Sourcing Requirement for the Southeastern New England Capacity Zone, Hydro Quebec Interconnection Capability Credits, and Demand Curve Values for the 2019-2020 Capacity Commitment Period.  In that filing, ISO-NE proposed an Installed Capacity Requirement (net of certain credits for imports) of 34,151 MW.

ISO-NE noted that for the most part, this and other key values were calculated using the same Commission-approved methodology that has been used to calculate the values submitted and accepted for other recent Capacity Commitment Periods. One key difference for the tenth FCA is the inclusion of behind-the-meter photovoltaic (“PV”) resources that are not yet reflected in historical loads as a reduction in the load forecast. This change addresses a requirement imposed by the FERC in its January 2, 2015 Order accepting the Installed Capacity Requirement and related values for the ninth FCA.

ISO-NE asked FERC to accept the proposed ICR-Related Values for the tenth FCA to be effective on January 9, 2016 (i.e. 60 days after filing), to enable their use in the tenth FCA scheduled for February 2016.

Report: solar panels add home appraisal value

Tuesday, November 17, 2015

"How will putting rooftop solar panels on my home affect its value?" is a common question among those considering residential-sited solar energy projects. 

It will help, according to a report recently released by the Lawrence Berkeley National Laboratory, finding solar photovoltaic systems add value to homes in a variety of markets under traditional appraisal methodology as well as statistical analysis.

A residential rooftop solar project in Massachusetts.

Intuition and previous studies have shown a "price premium" effect for solar photovoltaic systems in some markets.  Where a price premium applies, a home with a solar PV system can command a higher price than a comparable home without one.

A 2013 study of California using statistical analysis found "clear support that a premium exists in the marketplace; thus, PV systems have value, and their contribution to home values must be assessed."  That study found a strong correlation between premiums and PV system size, and a weak negative correlation with PV system age.  Essentially, "larger systems garner larger premiums and older systems garner smaller premiums," with each 1-kilowatt increase in size estimated as commanding a $5,911 higher premium, while each year of system age yields a $2,411 lower premium.  

A similar 2014 study of eight states found "PV consistently adds value across a variety of states, housing and PV markets, and home types."  Notably, these studies relied heavily on hedonic or regression pricing models to account for characteristics specific to each property (home type, site, neighborhood, market).  While such large-scale statistical analysis is commonly performed in economics, home buying more commonly relies on the appraisal process to support both price formation and financing.  Few previous studies were written by experienced real estate appraisers using paired-sales techniques or other standard appraisal methods.

The Lawrence Berkeley National Laboratory has released a report designed to bridge this gap, featuring a comparison of statistically derived PV premiums and analysis performed by experienced home appraisers.  That report, "Appraising into the Sun: Six-State Solar Home Paired-Sales Analysis", examined 43 pairs of comparable homes that sold with and without PV across seven areas in six state (California, Oregon, Florida, Maryland, North Carolina, and Pennsylvania).  It compared traditional real estate appraisal analysis of these homes to contributory-value estimates based on gross cost, net cost, and income. Overall, it found that under either statistical or appraisal based analysis, PV systems added premiums of $2.68/W to $4.31/W across states, averaging $3.78/W or about $14,000 for an "average-size" system sold in 2011 (3.8 kW).

The study did identify some difficulty in conducting comparable-sales analysis on homes with solar panels.  (It also includes a section titled "Warning to Users of this Study", noting the analysis was limited to specific times and places, only considered host-owned systems with crystalline-silicon panels, and does not address potential sales price implications related to the location of the PV systems.)  However, it found that appraised premiums are in agreement with the hedonic modeling results as well.  Practically speaking, this means cost- and income-based statistical estimates of PV premiums could be reliable when paired-sales analysis is impossible.

Further information about the Lawrence Berkeley National Laboratory report on appraisal value of residential solar PV systems can be found in a November 12, 2015 presentation hosted on its website.

FERC considers 2015 enforcement report

Monday, November 16, 2015

The Federal Energy Regulatory Commission is scheduled to consider its 2015 Report on Enforcement when it meets later this week.

The FERC is an independent federal agency charged with regulating certain U.S. energy resources and activities, including the interstate transmission of electricity, natural gas, and oil, as well as hydropower and liquefied natural gas (LNG) terminals.

Since at least 2007, FERC releases an annual report describing its enforcement activity.  Recent FERC enforcement reports include:

These reports illustrate that FERC's enforcement of the federal energy laws it manages has become a higher priority for the Commission in recent years.  Congress enhanced FERC's enforcement powers through the Energy Policy Act of 2005, which gives FERC the authority to levy fines of up to $1,000,000 per day for some violations.  Enforcement continued to escalate in priority through a subsequent restructuring of the Commission's Office of Enforcement, and President Obama's selection of chief enforcement officer Norman Bay as FERC's chairman.

Penalties assessed by FERC through enforcement actions have also increased in recent years, with over $5.8 million in refunds, over $148 million in civil penalties and disgorgement of over $119 million in unjust profits in fiscal year 2012, and over $304 million in civil penalties and disgorgement of almost $141 million in unjust profits in fiscal year 2013.

The Commission will next meet on November 19 at its Washington, DC headquarters.  On its agenda is an item captioned as A-3, AD07-13-009, "2015 Report on Enforcement."  While much of FERC's enforcement activity begins in a non-public mode, the annual staff report sheds some light on the Commission's overall approach to enforcement.  FERC's free live webcast is also available during the meeting and will be archived for 3 months.

DONG Energy proposes Massachusetts offshore wind farm

Thursday, November 12, 2015

A subsidiary of Danish energy company DONG Energy has proposed an offshore wind development to be located in federal waters off the Massachusetts coast.  The "Bay State Wind" project would be a utility scale offshore wind farm, located 15 miles south of Martha's Vineyard.

Largely owned by the Danish government, DONG is the world’s largest developer of offshore wind projects, reportedly having built over 3,000 megawatts or about a third of all installed offshore wind capacity in the world.  Other branches of the company engage in serving Danish customers, oil and natural gas exploration and production, and thermal power generation. 

Because the Bay State Wind project's site is over the outer continental shelf, it falls under federal jurisdiction for site leasing purposes under subsection 8(p) of the Outer Continental Shelf Lands Act.  The wind energy area in question was originally auctioned by the U.S. Bureau of Ocean Energy Management in January 2015.  In that January auction, RES America Developments, Inc. provisionally won the rights to Lease OCS-A 0500 (187,523 acres) with a winning bid of $281,285.  BOEM signed the commercial wind energy lease for the site on March 23, 2015, and the lease went into effect on April 1, 2015.

In April 2015, RES agreed to transfer the lease to DONG.  In accordance with BOEM's process for assigning a site lease, BOEM agreed to assign the lease to DONG Energy Massachusetts (U.S.) LLC on June 12.

According to DONG, full development of the Bay State Wind project might entail 1,000 megawatts of generating capacity.  Its lease area is adjacent to the wind energy area offshore Rhode Island and Massachusetts won by Deepwater Wind in 2013 in BOEM's first competitive lease sale for offshore wind sites.

US auctions NJ offshore wind sites

Tuesday, November 10, 2015

The U.S. Department of the Interior has auctioned the rights to lease nearly 344,000 acres offshore New Jersey for potential offshore wind energy development. 

Under federal law, the Department of the Interior's Bureau of Ocean Energy Management is responsible for leasing marine sites on the Outer Continental Shelf for energy development.  In addition to BOEM's oil and gas site leasing programs, the agency also operates renewable energy programs focused primarily on offshore wind and hydrokinetic resources (waves and currents).  Prior to yesterday's lease sale, BOEM had awarded nine commercial offshore wind leases offshore Massachusetts, Maryland, Rhode Island, and Virginia.

In September, BOEM announced that it would auction off the rights to two designated Wind Energy Areas offshore New Jersey.  That auction was held yesterday.  According to BOEM, the provisional winner of lease area OCS-A 0498 (160,480 acres) was RES America Developments Inc., with a bid of $880,715.  US Wind Inc. provisionally won site OCS-A 0499 (183,353 acres), with a bid of $1,006,240. Fishermen’s Energy LLC also reportedly participated in the lease sale but did not win either parcel.

Generally centered offshore of Atlantic City, the New Jersey Wind Energy Area starts about 7 nautical miles offshore and runs about 21 nautical miles seaward.  The U.S. Department of Energy’s National Renewable Energy Laboratory reports that full development of the area could support about 3,400 megawatts of wind generation.

Since the Obama administration's early "Smart from the Start" program, BOEM has engaged in efforts to spur offshore wind development.  President Obama's June 2013 Climate Change Action Plan features offshore wind as a tool to reduce the emission of carbon dioxide and other greenhouse gases from domestic industry.

This emphasis on the linkage between offshore wind and action on climate change is increasingly clear in the administration's messaging.  Early press releases on BOEM's offshore wind programs emphasized "the Obama Administration's all-of-the-above energy strategy to continue to expand domestic energy production."  By July 31, 2013, in announcing the first ever competitive lease sale for renewable energy in federal waters, BOEM described "President Obama's comprehensive plan to move our economy toward domestic clean energy sources and cut carbon pollution."  Just two months later in September 2013, after the release of the Climate Action Plan, BOEM began using the phrase "President Obama's Climate Action Plan to create American jobs, develop domestic clean energy sources and cut carbon pollution."  BOEM continues to use this phrase in touting its offshore wind program's consistency with the Climate Action Plan, as recently as yesterday's press release about the New Jersey lease sale.

Perhaps more tellingly, the Department of Interior press release announcing yesterday's New Jersey sale references "COP21", the upcoming 2015 Paris Climate Conference, in its brief summary.  This reference to the Paris climate convention is not otherwise explained in the text of the press release.  Nevertheless its inclusion here highlights the interplay between domestic and international energy policy, as well as the potential role U.S. offshore wind might play in addressing climate change.

Tide Mill Institute 2015 conference

Thursday, November 5, 2015

The Tide Mill Institute will hold its 11th annual conference on November 6-7, 2015, at the Cummings Center in Beverly, Massachusetts.  Participants will explore the past, present, and future uses of tidal energy through expert presentations, exhibits, and a field trip to a mid-seventeenth century tide mill site.

Part of the tidal barrage at the site of Heal's Lower Mill, Westport Island, Maine.

A nonprofit corporation, the Tide Mill Institute hopes to advance the appreciation of tide mill history and technology by encouraging research, by promoting appropriate re-uses of former tide mill sites and by fostering communication among tide mill enthusiasts.  The Institute's mission is:

  • to advance appreciation of the American and international heritage of tide mill technology;
  • to encourage research into the location and history of tide mill sites;
  • to serve as a repository for tide mill data for students, scholars, engineers and the general public and to support and expand the community of these tide mill stakeholders; and
  • to promote appropriate re-uses of old tide-mill sites and the development of the use of tides as an energy source.

Tide Mill Institute's 2015 symposium includes presentations on tide mills and tidal power by experts from France, Ireland, and the U.S.  Thomas McErlean will describe his experiences uncovering a nearly 1,400 year old tide mill at Nendrum, Northern Ireland, whose bed logs were cut in 619 AD.  The conference includes a low-tide field trip to view the site of the Friend's Mill, built about 1647-1649 on the Bass River in Beverly, Massachusetts, where a later foundation and some remains are still visible.  Concurrently, the Beverly Historical Society is opening its new exhibit on the Friend's Mill this weekend.

For more information or to register, contact Bud Warren at 207-373-1209 or email info@tidemillinstitute.org.

Record low prices in summer 2015 New England wholesale electricity market

Tuesday, November 3, 2015

The summer of 2015 brought New England the lowest wholesale electricity prices since 2003, thanks to record low prices for natural gas.  According to regional grid operator ISO New England Inc., this illustrates what happens "when New England power plants can access the vast supply of lower-priced, domestic natural gas being produced in the Marcellus shale deposit."

ISO-NE, "Summer 2015: The lowest natural gas and power prices since 2003"

In a post on its ISO Newswire site, the grid operator noted that the average real-time wholesale electricity price for June, July, and August 2015 was $26.86 per megawatt-hour (MWh). By comparison, the average real-time price of wholesale electric energy in 2014 was $63.32 per megawatt-hour.  While summer energy prices have typically averaged lower than winter prices in New England, 2015's summer prices were low even in comparison to other recent summers: $34.31 in 2014, or $43.94 in 2013.

What explains New England's low wholesale electricity prices this summer?  According to ISO New England, it's because existing natural gas-fired power plants could get fuel at a low price:
In essence, the reason was the low price of natural gas that could be delivered to the power plants that burn natural gas to make electricity. For most of the year, the price of natural gas is low in New England, and as a consequence, the demand for natural gas for both heating and power generation just continues to grow. In fact, in 2014, New England power generators using natural gas produced 44% of the region’s electricity.
The ISO-NE post describes how low-priced natural gas plus adequate interstate pipeline transportation capacity yields New England low electricity prices.  Indeed, the average price of  natural gas in New England during June, July, and August averaged a record low $2/MMBtu.  This is nearly 40% below last year's summer average ($3.27/MMBtu), itself the next-lowest summer record.

New England's average summer electricity price was even below that of other regions, like the Midwest.  According to ISO-NE, "This summer’s prices indicate that the region’s electricity prices can be competitive, in the more commonly understood sense, with other regions of the US when low-cost fuel is available." Indeed, at times the price of natural gas in New England was below that of the benchmark Henry Hub.

The post also describes how heavy winter demand for natural gas for both heating and power generation, combined with pipeline constraints, yields high natural gas prices and thus high electricity prices.  This has occurred repeatedly in recent winters, such as in January and February 2014 and February 2015.  What is at issue is thus the ability of the interstate natural gas pipeline transportation network to ship enough gas into the Northeast -- a capability exceeded through much of the recent winters, with the resulting price paid in coal and oil emissions as well as dollars.

As ISO-NE notes, most customers' retail rates for electricity are set using mechanisms to reduce rate volatility, and time of use rates are not yet widely adopted.  But the net movement of wholesale markets is eventually priced into retail rates.  Can New England keep competitive with other regions?

Declining demand for residual fuel oil?

Thursday, October 29, 2015

Global demand for residual fuel oil is expected to decline, according to the U.S. Energy Information Administration.

A Maine State Ferry Service boat near Vinalhaven, Maine.

Residual fuel oil is basically what's left after gasoline and other lighter hydrocarbons are distilled from crude oil.  Industry recognizes several grades of residual fuel oil, including No. 5 (used in steam-powered vessels in government service and inshore powerplants) and No. 6 (used for the production of electric power, space heating, vessel bunkering, and various industrial purposes.) 

Because residual fuel oil is composed of the residue left after distillation, it can contain large amounts of contaminants such as sulfur, nitrogen, or heavy metals.  As environmental regulations limit emissions of pollution, residual fuel oil can become less attractive (or more expensive) as a fuel source for electric power generation or marine transportation.

The EIA notes declining global demand for residual fuel oil since the mid-1980s.  In a brief report, EIA projects that the electric power and heating sectors will likely be responsible for continuedlarge reductions in residual fuel oil demand.

EIA also points to tighter international emissions regulations for the marine transport sector.  Rules under Annex VI of the International Maritime Organization through the International Convention of Pollution from Ships (MARPOL, or Marine Pollution) require global controls on emissions of sulfur and nitrogen oxides.  While residual fuel oil with a sulfur level no more than 3.5% can be used to meet the MARPOL requirements throughout most of the oceans, stricter limits apply to designated emission control areas like the North Sea, the Baltic Sea, and coastal areas in North America and the Caribbean Sea.  These strict limits effectively require 0.1% sulfur content residual fuel oil or lower in the covered emission control areas.  EIA suggests that strategies for MARPOL compliance will likely include low-sulfur fuels (marine gasoil or intermediate fuel oil, or even liquefied natural gas or LNG), or using scrubbers or other technology to remove sulfur post-combustion from the exhaust.

At the same time, EIA notes that some developing countries' power sectors may rely on residual fuel oil as a "transitional fuel" if they are "more sensitive to price and less sensitive to environmental and health implications."

Northern Pass files with NH SEC

Wednesday, October 21, 2015

The developer of the Northern Pass Transmission Project, a proposed high-voltage transmission line from Canada into New Hampshire, filed a formal application to New Hampshire regulators this week.

First proposed in 2009, the Northern Pass project would include about 190 miles of new direct current transmission lines and an AC-DC converter station.  Collectively, the project would be capable of importing over 1,000 megawatts of power from Canada into the New England electric grid.  Its formal sponsors are two companies affiliated under the Eversource family: Northern Pass Transmission LLC and Public Service Company of New Hampshire d/b/a Eversource Energy.

Early versions of proposal drew criticism and controversy over issues including siting, visual impacts, the potential use of eminent domain, and impacts to domestic renewable energy production.  After a series of public information meetings and other dialogue, Eversource released a revised route and plan in August 2015.

On October 19, Eversource announced that it had filed a formal application to the New Hampshire Site Evaluation Committee.  The Northern Pass Transmission application to the SEC is available on the project's website.  It describes a project cost estimate of $1.6 billion, and a capacity of 1,090 megawatts. 

The SEC was established by the state legislature for the review, approval, monitoring and enforcement of compliance in the planning, siting, construction and operation of energy facilities.  It includes members from the Public Utilities Commission, cabinet level commissioners, and two members of the public.  The SEC has jurisdiction to review applications for siting and construction of large-scale energy facilities and to issue a Certificate of Site and Facility enabling a project's development.  The process before the SEC is likely to play out through 2016.

Massachusetts nuclear power plant to close

Tuesday, October 13, 2015

The Pilgrim Nuclear Power Station, the sole nuclear power plant in Massachusetts, will close by June 2019, according to its owner Entergy Corp.

Entergy is an integrated energy company headquartered in New Orleans, Louisiana.  Entergy is one of the leading nuclear generators in the U.S., with nearly 10,000 megawatts in nuclear generating capacity as well as about 20,000 megawatts of other electric generating capacity, as well as serving retail utility customers in Arkansas, Louisiana, Mississippi and Texas.

The company's Entergy Wholesale Commodities business owns and operates five nuclear power units located in the northern United States, and sells electricity produced by those plants to wholesale customers.  Those units include Pilgrim Station's Unit 1, a boiling water reactor with a maximum dependable capacity of 688 megawatts.  The Pilgrim Station unit was installed in 1972, and is currently licensed through June 8, 2032.

Today Entergy announced plans to close Pilgrim Station by June 2019.  In its press release, Entergy cites "poor market conditions, reduced revenues and increased operational costs."  In Entergy's view, low current and forecast wholesale energy prices "brought about by record low natural gas prices, driven by shale gas production" hurt Pilgrim's revenues; wholesale energy market design flaws mean merchant nuclear power plants are inadequately compensated, while "unfavorable state energy proposals ... subsidize renewable energy resources at the expense of Pilgrim and other plants."  Entergy also cites "increased operational costs and enhanced Nuclear Regulatory Commission oversight" following a recent NRC decision to give Pilgrim a higher level of scrutiny.

The announcement resembles a 2013 decision by Entergy to close the Vermont Yankee Nuclear Power Station, a plant similar in vintage to Pilgrim Station.  Entergy announced Vermont Yankee's closure in 2013; that plant ceased commercial operation at the end of 2014, and Vermont Yankee's decommissioning is now underway.  In announcing the Vermont Yankee closure, Entergy pointed to financial factors including a "natural gas market that has undergone a transformational shift in supply due to the impacts of shale gas, resulting in sustained low natural gas prices and wholesale energy prices", high plant cost structures, and wholesale market design flaws.

According to Entergy, it has notified regional electric grid operator ISO New England Inc. of its intent to exit the region's capacity market.  Entergy said the exact timing of plant shutdown will be decided in the first half of 2016.

Auction set for NJ offshore wind sites

Friday, September 25, 2015

The U.S. government has scheduled an auction for the rights to lease two areas of federal ocean space off New Jersey for offshore wind energy development.  The auction, to be held November 9, 2015, will be the fifth competitive lease sale for renewable energy on the outer continental shelf.

Under the Outer Continental Shelf Lands Act, the Department of the Interior has responsibility for managing use and development of the federally controlled outer continental shelf and the waters above it.  The Bureau of Ocean Energy Management exercises key functions in support of this role, managing resource evaluation, planning, and site leasing for energy activities ranging from oil and natural gas exploration and production to hydrokinetic, offshore wind, and other renewable ocean energy projects.

Since early in the Obama administration, BOEM has worked to offer leases to federal ocean sites for offshore wind development or related activities.  To date, BOEM has awarded seven offshore wind site leases through competitive lease sales, plus two more commercial wind leases offshore New Jersey awarded through earlier interim policies.  BOEM's competitive processes have generated over $14.5 million in high bids for over 700,000 acres in federal waters off states including Massachusetts, Maryland, Virginia, and Rhode Island.

Since at least 2009, BOEM has been involved in efforts to lease sites off New Jersey for offshore wind development, including multiple task force meetings, a 2011 Call for Information and Nominations – Commercial Leasing for Wind Power on the Outer Continental Shelf Offshore New Jersey, and a 2014 Proposed Sale Notice.  That notice described a 343,833-acre Wind Energy Area split in two parts, known for leasing as OCS-A 0498 and OCS-A 0499:

BOEM has now announced that it will publish a Final Sale Notice setting a commercial lease sale for November 9, 2015, for the Wind Energy Area offshore New Jersey.  Similar in format to other recent BOEM offshore wind site auctions, the New Jersey sale will include consideration of both monetary factors (the bid) and nonmonetary factors (i.e., whether a bidder has obtained a Power Purchase Agreement or New Jersey Offshore Renewable Energy Certificate award).

No offshore wind projects are in commercial operation in the U.S., although Deepwater Wind is currently constructing its Block Island Wind Farm in state waters offshore Rhode Island.

Propane inventory in US sets new record

Thursday, September 24, 2015

As the U.S. prepares for another winter, government records show stockpiles of propane have reached record levels.  What's in store for propane markets?

Propane is a hydrocarbon gas liquid used mostly for space heating and as a feedstock for other chemicals like ethylene and propylene, as well as for drying agricultural crops.   Natural gas processing plants and petroleum refineries are the two largest sources of propane. 

The U.S. Energy Information Administration has collected weekly propane inventory data for 22 years.  According to its most recent report, U.S. inventories of propane and propylene reached 97.7 million barrels as of September 11.  EIA describes this as the highest level of propane inventory on record.

What explains the buildup of propane in storage?  Record high propane inventories are partly due to seasonal dynamics in supply and demand.  Demand for propane for heating and agricultural uses is highly seasonal, while demand for propane as a chemical feedstock lacks strong seasonality.  Over recent years, propane and propylene stocks are typically drawn down during the winter heating and agricultural drying season (October to March), and then rebuild from early April through September. 

This year, EIA data shows inventories began increasing in mid-February.  EIA notes that domestic consumption is relatively flat, but found increases in propane production.  In particular, EIA's latest data shows that natural gas processing plants are producing a greater share of propane than in previous years (rising from 62% in 2008 to 76% in 2014), while propane production at refineries has remained relatively constant.

Maine considers net metering alternative

Wednesday, September 23, 2015

The Maine Office of the Public Advocate has proposed a new mechanism to encourage the development of solar energy capacity in the state.

Under Maine’s existing law, customers with onsite generation may choose “net energy billing” treatment. Similar to “net metering” policies in other states, Maine’s program gives eligible consumers credit for the power they send back to the grid from their onsite generation. Presently, the value of that credit varies with the applicable retail electricity rate.

But according to the Public Advocate, Maine’s version of net metering raises concerns including net metering customers’ uncertainty over the future value of power, the potential for cost-shifting to non-net metered customers, and a lack of transparency.

In its white paper, “A Ratepayer Focused Strategy for Distributed Solar in Maine”, the Office of the Public Advocate offers an alternative to Maine’s existing net metering program. It envisions policies to support development of two types of solar energy projects in Maine: customer-sited systems and wholesale systems.

For customer-sited systems, the white paper proposes a “Solar Standard Buyer” to serve as an aggregator of the attributes solar energy can provide. Customers would enter into a Customer-sited Solar Contract or CSC, a fixed-price, 20-year contract with the solar aggregator. As under Maine’s existing net metering structure, the “payment” to customers would be based on a per kWh rate that would appear as a monthly bill credit on the customer’s bill. Under the Public Advocate’s vision, the level of compensation would be capped at $0.20/kWh.

As more solar capacity comes online in Maine, the Public Advocate proposes incremental “step downs” in the CSC contract price paid to solar customers. Both the payments to customers under a CSC and the revenues received through this aggregation and sale would be credited to all customers through transmission and distribution utilities’ existing stranded cost mechanisms.

For wholesale systems between 1 megawatt and 5 megawatts in scale, the white paper envisions that the Commission would solicit competitive bids, with the ultimate purchaser being the Solar Standard Buyer. The white paper notes an expectation that economies of scale will enable these larger, utility-side solar projects to reduce the price per kilowatt-hour to Maine’s non-participating ratepayers. It proposes to compensate developers of wholesale systems at a fixed rate, with contracts procured by the state’s utilities through bi-annual competitive processes.

The Public Advocate suggests that its proposal is consistent with recent analysis of the value of solar energy in Maine. Pursuant to the 2014 “Act to Support Solar Energy Development in Maine”, the Maine Public Utilities Commission developed a methodology for determining the value of distributed solar energy generation in the state. Its Maine Distributed Solar Valuation Study, released this spring, provided a methodology for estimating the cost and benefits of solar, values for each cost and benefit, and options to encourage solar adoption within Maine’s existing utility framework.

According to the Public Advocate’s white paper, its proposal could drive up to 300 MW of new solar capacity in Maine by 2025.  It has been characterized as an addition to net metering, not a replacement.  But the Maine Public Utilities Commission continues to evaluate Maine’s solar energy policies.  Its process could have outcomes ranging from continuation of Maine's net energy billing programs to the creation of some new mechanism to address solar and distributed generation's integration into the grid.

North Carolina offshore wind advances

Tuesday, September 22, 2015

Federal efforts to lease ocean sites off the North Carolina coast for offshore wind development advanced last week, when the Bureau of Ocean Energy Management issued a report finding that there would be no significant environmental or socioeconomic impacts from issuing wind energy leases in three specific areas.  The determination brings BOEM one step closer to auctioning off leasing rights off North Carolina for offshore wind development.

The Bureau of Ocean Energy Management is part of the U.S. Department of the Interior.  BOEM performs key duties under the Outer Continental Shelf Lands Act, including resource evaluation, planning, and site leasing.  In furtherance of President Obama’s Climate Action Plan, BOEM has auctioned off the rights to lease sites in federal waters for offshore wind development off states including Massachusetts, Maryland, Virginia, and Rhode Island.  Altogether, BOEM has awarded nine commercial wind leases.  Seven of these were awarded through its competitive lease sale process, generating over $14.5 million in high bids for over 700,000 acres in federal waters. 

Federal law prescribes the process BOEM must undertake to lease sites for offshore wind development.  Under the National Environmental Policy Act (NEPA), BOEM must evaluate the environmental and socioeconomic impacts of proposed actions.

For the proposed leasing off North Carolina, in January 2015 BOEM published its Environmental Assessment (EA) of the impacts of granting commercial wind leases and allowing of site characterization and assessment activities on the Atlantic Outer Continental Shelf.  On September 17, BOEM issued a revised Environmental Assessment.  That EA found there would be no significant environmental or socioeconomic impacts from issuing wind energy leases and allowing site characterization activities.  This "Finding of No Significant Impact", or FONSI, enables BOEM to proceed to the next step in the leasing process.

That next step will occur in October, when BOEM will convene a public meeting of the North Carolina Renewable Energy Task Force.  After considering the input from the Task Force, BOEM will publish a “Proposed Sale Notice” in the Federal Register, which will include a 60-day public comment period. That notice would be followed by a lease auction, likely similar to those held for sites off other states.

In addition to its proposed North Carolina activity, BOEM expects to hold a competitive lease sale for sites offshore New Jersey later this year.

NH regulation of solar PPAs, leases

Monday, September 21, 2015

If a solar energy company installs solar panels on its customers' roofs, and sells those customers the power they produce, will it be regulated like a public utility under state law?  A petition by Vivint Solar, Inc. has asked the New Hampshire Public Utilities Commission to declare that it will not regulate Vivint Solar as a public utility, competitive electric power supplier, or limited producer of electrical energy under state law.

Vivint Solar describes itself as the second largest installer of residential solar energy systems in the U.S. residential market, with approximately 42,000 residential customers and 274 megawatts of solar systems installed.  The company describes two primary business structures for residential solar projects: long-term power purchase agreements or PPAs, under which a customer agrees to purchase all of the power generated by a solar energy system installed on the customer’s rooftop; and solar leases, under which a customer leases the solar energy system which is installed at the customer’s site. In either case, the solar facilities are owned by Vivint Solar’s affiliates and financing parties to enable efficient use of tax benefits and low-to-no upfront costs for customers.

In its August 14, 2015 petition, Vivint Solar asked New Hampshire regulators for “regulatory clarity on how it may be regulated” if it enters the state to offer its PPAs and solar leases to New Hampshire customers. In particular, Vivint Solar argues that because it would not sell the electricity generated by its solar energy systems to the broad “public,” it is not a public utility under New Hampshire law. Vivint Solar also argues that its contractual relationship with residential customers is fundamentally different from the relationship between a competitive electric power suppliers and its customers, largely because Vivint Solar’s activity occurs on the customer’s side of the utility meter. The company  also asks the Commission to declare that it would not be a limited producer of electric energy, a kind of generator regulated lightly by the Commission. Vivint Solar also notes that its PPAs and solar leases promote New Hampshire’s goal of encouraging competition for retail access, and customer choice for more affordable electricity, as well as New Hampshire’s renewable portfolio standard and other clean energy policies.

The New Hampshire Public Utilities Commission has issued an Order of Notice in the case, with interventions due and a prehearing conference scheduled for early October.

NH explores electric grid modernization

Friday, September 18, 2015

New Hampshire regulators are considering whether and how to modernize the state’s electric grid. In a recently opened investigation, the New Hampshire Public Utilities Commission seeks to educate stakeholders about grid modernization and to explore to what extent that grid modernization is workable in New Hampshire.

Last year, the New Hampshire Office of Energy & Planning issued its 10-Year State Energy Strategy.  In that document, the administration called for "a more flexible and resilient electric grid to support new technologies, increase consumer participation in energy management, and fortify our resiliency in the face of price and supply volatility and extreme weather events."  The first step identified in the Energy Strategy was to open a PUC docket on grid modernization:
The electric grid is aging, and changing consumer use patterns, a new generation mix, and increased threats from severe weather events require a more modern system. The New Hampshire Public Utilities Commission should open a docket to determine how to advance grid modernization in the state. In light of the potential breadth of the topic, which could include dynamic pricing, better consumer access to technology, and even rethinking the role of utilities, an investigation or information ‐ gathering proceeding may be an appropriate first step. This less formal proceeding would give all stakeholders a chance to learn about grid modernization and could inform the specific areas that should be pursued within future dockets. This would allow the PUC and stakeholders to determine which approaches will benefit New Hampshire consumers, and when and how they should be implemented.
Earlier this summer, the New Hampshire legislature enacted House Bill 614, implementing the recommendations in the Energy Strategy.  As Governor Hassan noted in her signing statement, the bill requires the Public Utilities Commission to "begin a process focused on modernizing our electric grid to ensure that we are prepared for an innovative energy future and to set an electricity peak time reduction goal, which can help lower the high costs of producing electricity when demand is greatest."

That process is now underway.  The New Hampshire Public Utilities Commission opened its investigation by order dated July 30, 2015.  The Commission gave interested parties until September 17, 2015 to provide comment on the definition, or elements, of grid modernization that should be included in its investigation.  The Commission directed its staff to schedule a technical session following a review of comments submitted, and to develop a procedural schedule for the rest of the case.

Maine PUC considers community energy projects

Thursday, September 17, 2015

The Maine Public Utilities Commission is evaluating the viability of proposed community-based renewable energy projects that remain under development.

Maine has run a community-based renewable energy program since 2009.  The program gives qualified wind, solar, and other renewable energy projects long-term contracting opportunities to sell the facility’s output to a Maine transmission and distribution utility at attractive rates.

In 2015, the Maine Legislature adopted P.L. 2015 ch. 232, An Act to Amend the Community-based Renewable Energy Program”.  Beyond minor revisions to the law, the act adds strict deadlines for key program milestones: the Public Utilities Commission has until December 31, 2015 to order or allow utilities to enter into long-term contracts under the program, and all projects selected for a contract must become operational and commence generating electricity by December 31, 2018.

Section 5 of the Act also created a new "viability assessment" process designed to make sure the program is as effective as possible.  The program size is capped at 50 megawatts statewide; all of this capacity was quickly claimed by certified projects.  But not all projects that have been certified are operational; some have yet to be built.  Some stakeholders expressed concern over "permit banking" -- developers obtaining and holding onto program capacity, without actively developing it, while other projects would move forward if they could get the capacity.

As a result, the Legislature directed the Commission to review all certified projects that have not yet reached commercial operations, to determine whether the projects are reasonably likely to achieve commercial operations within a 3-year period.   If the Commission determines a project will not be viable by December 31, 2018, the Act directs the Commission to revoke any contract awarded, but such projects will remain certified under the program.   If the removal of nonviable projects frees up program capacity for contracting, the law directs the Commission to conduct an expedited request for proposals to select community-based renewable energy projects to become program participants and enter into long-term contracts.

The Commission's viability assessment process is now ongoing.  A July 13, 2015 procedural order identified six projects as having been either certified or awarded a contract, but not been placed in commercial operation.  Project developers were invited to submit information related to the viability assessment by August 7. 

The Commission meets on September 22 to deliberate on the viability assessments.

CT examines energy storage, grid improvements

Tuesday, September 15, 2015

The Connecticut Department of Energy and Environmental Protection has opened a proceeding to implement a state law advancing energy storage systems and other improvements to the electric grid.  The Distributed Energy Resource Integration Demonstration Project program is designed to find best practices on how different grid-side system enhancements can be reliably and efficiently integrated into the grid in a manner that is cost-effective for all ratepayers.  The recently opened case has the potential to lead to significant investment in energy storage in Connecticut and other grid advancements.

The Department of Energy and Environmental Protection, or DEEP, was established on July 1, 2011 as a combination of the Department of Environmental Protection, the Department of Public Utility Control as well as other state energy policy staff.  DEEP has a dual mandate of conserving, improving and protecting Connecticut's natural resources and environment, as well as supporting economic development by making cheaper, cleaner and more reliable energy available.

In June 2015, the Connecticut legislature passed a sweeping bill formally known as June Special Session Public Act 15-5, An Act Implementing Provisions of the State Budget for the Biennium Ending June 30, 2017, Concerning General Government, Education, Health and Human Services and Bonds of the State (“the Act”).  Section 103 of the Act requires Connecticut electric distribution companies to submit a proposal or proposals to DEEP for demonstration projects to build, own, or operate grid-side system enhancements, such as energy storage systems.  Proposals are supposed to:
  • Demonstrate and investigate how distributed energy resources (DER) can be reliably and efficiently integrated into the electric distribution system;
  • Maximize the value provided to the electric grid, electric ratepayers, and the public from distributed energy resources; and
  • Complement and enhance the programs, products, and incentives available through the Connecticut Green Bank, the Connecticut Energy Efficiency Fund, and other similar programs.
As an initial step in the implementation of this program, DEEP has opened a proceeding to establish priority goals and objectives for the DER Integration Demonstration Projects.  The proceeding includes opportunity for public comment, as well as a stakeholder workshop scheduled for October 5.

Ultimately, Connecticut's electric distribution companies will propose specific demonstration projects for approval first by DEEP, then by the Connecticut Public Utilities Regulatory Authority or PURA.  Much emphasis has been placed on energy storage systems as a likely beneficiary of the program.  Other grid-side system enhancements could include distribution system automation and controls, intelligent field systems, advanced distribution system metering, communication, and systems that enable two-way power flow.  DEEP has until January 1, 2017 to evaluate the approved proposals and report to the state's legislative committee with jurisdiction over energy.

Energy Dept 2015 Quadrennial Technology Review

Monday, September 14, 2015

The U.S. Department of Energy has released its second Quadrennial Technology Review, a 505-page report describing the nation’s energy landscape and the dramatic changes that have taken place over the last four years.

The 2015 Quadrennial Technology Review examines the current status of energy technologies and research opportunities to advance them in addition to key enabling science and energy capabilities.  The updated report comes four years after the Energy Department's original Quadrennial Technology Review, issued in 2011.

The 2015 report notes, "The last four years have been defined by dramatic change in the nation’s energy landscape." Huge growth in domestic production of oil and natural gas has made the U.S. the world leader in combined oil and natural gas production for the last three consecutive years. Wind energy capacity has increased by 65 percent and wind energy generation has nearly doubled; solar capacity has increased 9 fold and solar photovoltaic generation over tenfold; old, inefficient power plants are being replaced by cleaner, more efficient ones; transportation efficiencies continue to improve.

It also highlights the Energy Department's view of "the most promising research, development, demonstration, and deployment (RDD&D) opportunities across energy technologies to effectively address the nation's energy needs. Specifically, this analysis identifies the important technology RDD&D opportunities across energy supply and end use in working toward a clean energy economy in the United States."  Individual chapters focus on specific technology types, including grid modernization, clean power, buildings, manufacturing, fuels, and transportation. 

The report also draws some overarching conclusions:

  • Energy systems are increasingly interconnected through the internet and other technologies, which could enable new paradigms for cost and emissions reduction. 
  • Increasingly diverse options are available to meet the nation’s energy needs is increasing, creating a more dependable and flexible energy system for consumers.
  • Substantial energy efficiency opportunities remain untapped.
  • More research and development could lead to innovation and breakthroughs in how to deliver clean energy cheaper and faster.

Maine PUC solicits standard offer proposals

Thursday, September 10, 2015

The Maine Public Utilities Commission has issued Requests for Proposals for retail electricity standard offer service.  At stake is the right to supply default electricity service to customers of Maine's two largest utilities -- as well as the price those customers will pay for power.

Maine restructured its electricity sector in the late 1990s.  Formerly, utilities owned both power plants and the wires and other infrastructure needed to supply consumers with electricity.  But as of March 1, 2000, investor-owned transmission and distribution utilities may own and operate wires, but generally cannot have a financial interest in or otherwise control generation or generation-related assets.  Power plants became "deregulated" from the perspective of state retail rate regulation, and were sold off by the utilities.  At the same time, Maine law created a new kind of entity called a "competitive electricity provider" to perform the role of supplying electricity as a commodity.

Customers can choose among supply offers from competitive electricity providers.  Suppliers can offer specific types of product (e.g. 100% renewable power, locally-sourced) or particular contract terms (e.g. pricing schedules, payment terms).  Most large industrial energy consumers choose competitive electricity supply under this option, as do many commercial accounts and some homes.

If a customer does not choose a competitive electricity provider, that customer is placed on "standard offer service" by default.  Maine law requires the Maine Public Utilities Commission to arrange for standard offer service though a competitive bid process, and to ensure that standard offer service is available to all customers in Maine.

The pending RFPs cover retail electricity standard offer service for calendar year 2016 for all customer classes in the territories of Central Maine Power (CMP) and Emera Maine-Bangor Hydro District.  Collectively, CMP and Emera Maine deliver approximately eleven million megawatt hours annually, of which about 45% currently comes from standard offer service.

The RFPs and related materials are available on the MPUC website.  Initial proposals are due on October 6, 2015. Following negotiation of non-price terms and a submission of final bid prices, the Commission is expected to select one or more proposals,  Service terms will begin on January 1, 2016.

DOE report finds Solyndra gave "false and misleading" info

Tuesday, September 1, 2015

The Department of Energy's Office of Inspector General has released a special report finding that failed solar panel maker Solyndra, Inc. provided the Department with inaccurate and misleading information during the application process for a $535 million loan guarantee.  The report summarizes the results of a 4-year investigation into what went wrong with the Solyndra matter, and what lessons the Department can learn as it proceeds to exercise its authority to grant an additional $40 billion in loan guarantees.

In 2005, Congress established a federal loan guarantee program for eligible energy projects that employed innovative technologies. Title XVII of the Energy Policy Act of 2005 authorized the Secretary of Energy to make loan guarantees for a variety of types of projects, including those that “avoid, reduce, or sequester air pollutants or anthropogenic emissions of greenhouse gases; and employ new or significantly improved technologies as compared to commercial technologies in service in the United States at the time the guarantee is issued.”

The Department of Energy loan guarantee program was expanded by the American Recovery and Reinvestment Act of 2009, which added billions of dollars of new authority to support renewable energy, electric transmission, and advanced biofuels projects.  The Department's Loan ProgramsOffice has supported a portfolio of more than $30 billion in loans, loan guarantees, and commitments covering more than 30 projects across the United States.

The Department made its first award under this program in September 2009, approving a $535 million loan guarantee to a company called Solyndra, Inc.  Solyndra said it would build a solar photovoltaic equipment manufacturing facility in Fremont, California.  The Energy Department disbursed over $500 million to Solyndra through the program.  But just two years later, Solyndra showed signs of failure, as it ultimately stopped operations and manufacturing, let 1,100 employees go, and filed for bankruptcy.  U.S taxpayers lost over $500 million.

The Solyndra matter drew significant public attention, with even the Department calling it an "ordeal" and many labeling it a scandal.  What went wrong?  Should the government have guaranteed Solyndra's loans?  Was the loan guarantee program flawed?  Or was it acceptable bad luck that the first awardee failed?

Since 2011, the Department of Energy's Office of Inspector General has investigated the Solyndra matter.  Its special report released August 24, 2015, describes the Inspector General's findings:
Our investigation confirmed that during the loan guarantee application process and while drawing down loan proceeds, Solyndra provided the Department with statements, assertions , and certifications that were inaccurate and misleading , misrepresented known facts , and, in some instances, omitted information that was highly relevant to key decisions in the process to award and execute the $535 million loan guarantee. In our view, the investigative record suggests that the actions of certain Solyndra officials were, at best, reckless and irresponsible or, at worst, an orchestrated effort to knowingly and intentionally deceive and mislead the Department.
In particular, the report identified "notable misrepresentations and omissions made to the Department by Solyndra" relating to Solyndra's sales contract commitments and ability to command a premium market price for its panels.  The report suggests this false and misleading information led the Department to approve the loan guarantee, when it might not have done so with the right information.  The report found that Solyndra failed to meet contractual obligations from the loan guarantee documents relating to truth and full disclosure.

The Inspector General's special report also found that the Energy Department's due diligence efforts were "less than fully effective", with missed opportunities to detect and resolve indicators that portions of the data provided by Solyndra were unreliable.  Nevertheless, the report concludes that ultimate blame should fall on the company: "the actions of the Solyndra officials were at the heart of this matter, and they effectively undermined the Department’s efforts to manage the loan guarantee process. In so doing, they placed more than $500 million in U.S. taxpayers’ funds in jeopardy."

The Department of Energy continues to offer loan guarantees for a variety of technologies and projects.  The report suggests that the Department strengthen its due diligence process, and reemphasize to loan applicants their absolute obligation to be truthful, complete, timely and transparent.

Navy signs solar energy deal

Thursday, August 27, 2015

The U.S. Department of the Navy has announced an agreement for the development of a 210 megawatt (DC) solar project to supply electricity to Navy and Marine Corps facilities in California.  The Navy described the deal as the largest purchase of renewable energy by a federal entity to date.

Solar photovoltaic panels in Utah - much smaller project than the Navy project.
The Navy has expressed interest in renewable and alternative energy for some time, buying biofuels and renewable electricity.  According to the website for Deputy Assistant Secretary of the Navy - Energy, Joseph Bryan:
The Navy's energy strategy takes the "long view" necessary to keep our Navy and our nation strong. Bottom line: incorporating energy initiatives now will allow us to more effectively carry out our mission in the future.
In 2009, Congress mandated that 25 percent of the energy used in Department of Defense facilities come from renewable sources by 2025.  Secretary of the Navy Ray Mabus then set an accelerated goal for his branch of the military: 1 gigawatt of renewable energy procurement by the end of 2015.  In the Navy's view, resources like solar power can help diversify its shore energy portfolio and provide long-term cost stability, which ultimately contributes to the Navy's overall energy security priorities.

In furtherance of this goal, last year the Western Area Power Administration issued a request for proposals for renewable energy projects to supply power to Navy facilities in California.  Through a competitive process, Sempra U.S. Gas & Power LLC was selected to develop the Mesquite 3 Solar project.  Sempra is a subsidiary of San Diego-based Sempra Energy, a major energy services holding company. It has developed a variety of solar and wind energy generation projects, including the existing Mesquite 1 Solar project about 60 miles west of Phoenix, Arizona.

The Navy announced that it had signed the agreement on August 20, at a ceremony co-hosted by Western Area Power Administration and Sempra.  Under the Navy deal, Sempra will develop the Mesquite 3 project as an expansion of the existing Mesquite site.  Mesquite 3 will feature over 650,000 photovoltaic panels on ground-mounted, horizontal single-axis trackers.  Construction is scheduled to begin in August, with completion expected by the end of 2016.  While pricing terms have not been disclosed, the Navy reports that it will save at least $90 million over the life of the project.

Will other units of federal government follow the Navy's model in contracting for renewable energy in this manner?  How will solar project business structures change if federal entities start playing a larger role as buyers?

Cross-border infrastructure and presidential permits

Wednesday, August 26, 2015

A recent report casts doubt on whether proposed federal legislation would actually accelerate decisions on the siting of cross-border energy infrastructure.

Cross-border pipelines and electric transmission lines play an important role in the North American energy industry.  Under U.S. law, cross-border energy infrastructure projects require a presidential permit and a finding of consistency with the national interest.  Executive orders give the State Department jurisdiction over cross-border oil pipelines, the Department of Energy jurisdiction over electric transmission lines, and the Federal Energy Regulatory Commission jurisdiction over natural gas pipelines. 

Recent projects like the Keystone XL pipeline have focused attention on the presidential permit process, as that project's presidential permit application has remained pending for years.  Some have raised questions about the scope of agency review and perceived differences in the approaches taken by the State Department, Energy Department, and FERC.

As a result, several members of Congress have proposed legislation designed to accelerate the permitting process.  These bills include:

These bills take various approaches, including limiting agency jurisdiction over cross-border energy infrastructure or the scope of agency review, or setting strict deadlines for agency action following completion of environmental review.

Could federal legislation like this speed up the process for reviewing proposed cross-border pipeline and electric transmission projects?  A recent report by the Congressional Research Service suggests that overall timelines for project review are driven by the scope of the environmental review process, not by delays following that environmental review or agency idiosyncrasies.

In particular, the report found that agency review is "driven largely by the National Environmental Policy Act (NEPA)", which requires federal agencies to consider the environmental impacts before acting.  Moreover, the report notes that the same NEPA requirements apply to all three:
Faced with Presidential Permit applications for energy projects of similar physical scope, the agencies appear to perform NEPA reviews of similar proportion. Very short, smaller projects are generally reviewed more narrowly and quickly, whereas multi-state projects of large capacity are subject to more expansive environmental review and tend to face much greater public scrutiny and comment—regardless of which agency has jurisdiction. 
The report also found that NEPA review is the key driver of overall permitting decision timelines:
As long as agencies apply NEPA to Presidential Permitting decisions, changes to the delineation of, or jurisdiction over, the border-crossing portion of large projects for permitting purposes may not change the scope of project environmental review. The imposition of decision deadlines on the permitting agencies after NEPA review is complete, either for national interest or public interest determination, could provide greater process certainty to stakeholders. However, the overall project review would still be contingent on the completion of NEPA review. Thus, the effects of legislative proposals to change cross-border infrastructure permitting on the review or approval of future border crossing energy infrastructure projects are open to debate. 
It's unclear how the Congressional Research Service report will affect pending legislation.  Likely more influential may be any final action by the State Department on the Keystone XL project's application for a presidential permit.  Nevertheless, interest in cross-border energy trade will likely continue to grow.

Northern Pass proposes new transmission plan

Monday, August 24, 2015

The developer of a proposed $1.4 billion electric transmission line connecting Quebec to New Hampshire has released a revised route for the project, following public opposition to earlier plans.  The new vision for the Northern Pass project would bury more of the line underground and reduce the project's overall capacity to haul power.  Will this version of the Northern Pass gain more traction?

First proposed in 2009, the Northern Pass would be a 192-mile high-voltage direct current (HVDC) transmission line.  It would bring up to 1,000 megawatts of power from Canadian power plants into New England, running from the Canadian border to a proposed converter terminal in Franklin, New Hampshire.  From there, a new alternating current (AC) transmission line would deliver the energy to New England’s electric grid at an existing substation in Deerfield, New Hampshire. 

Since it was first proposed, the Northern Pass route has drawn criticism; the project was delayed, and despite revisions to the route public opposition remained.  Throughout the process, many comments have focused on local siting impacts, like the effect of above-ground transmission lines and poles through Franconia Notch State Park, the White Mountain National Forest, and the Appalachian Trail.  Eversource proposed running 8 miles of cable underground to reduce these impacts, but argued that undergrounding more would make the project too expensive.

But the forces motivating the Northern Pass project and other proposed HVDC lines from Canada remain strong: demand in New England and New York for electricity, and in particular for hydropower and other renewable electricity imported from Canada.

On August 18, project lead Eversource Energy announced changes to the route and scope of the project.  While the previous vision included 8 miles of underground cable to avoid visual impacts, the so-called "Forward New Hampshire Plan" now includes 60 miles of underground cable. Eversource described its revised route as striking "a balance between New Hampshire and our region’s need for a reliable new energy source and avoiding potential impacts to the state’s scenic landscapes."  At the same time, the revised proposal reduces the line's capacity from 1,200 megawatts to 1,000 megawatts, ostensibly to hold total costs at the previously estimated $1.4 billion.  The plan now includes $200 million to establish the "Forward NH Fund", a pool of money designed to support clean energy innovations, economic development, community investment, and tourism.

The Northern Pass project now faces public hearings.  Eversource is expected to file an application for site review with the New Hampshire Site Evaluation Committee in mid-October.

Block Island offshore wind celebrated, challenged

Thursday, August 20, 2015

U.S. and Rhode Island officials recently celebrated the start of construction on the Block Island Wind Farm, which is on track to be the first commercial offshore wind farm in the U.S.  The five-turbine, 30-megawatt project under development by Deepwater Wind is scheduled to come online in 2016; turbine foundation construction and other "steel in the water" activities are underway.  As a pioneer in U.S. offshore wind development, the Block Island project has survived years of permitting uncertainty and repeated legal challenges by project opponents.  But another such lawsuit was filed this week in federal court.  What does the future hold for the Block Island Wind Farm?

Project developer Deepwater Wind is owned principally by an entity of the D.E. Shaw group.  Its Block Island project is currently under construction in Rhode Island state waters about three nautical miles southeast of Block Island.  The project will feed power directly to consumers on Block Island, but also includes a 25-mile bi-directional submerged transmission cable between Block Island and the mainland. The project's finances rest in part on a power purchase agreement through which Deepwater Wind will sell power to utility National Grid.

That power purchase agreement, or PPA, has been the subject of several legal challenges.  Those challenges often cite the deal's cost: pricing for the Block Island power starts as high as 24.4 cents per kilowatt-hour, and escalates 3.5 percent annually.  These prices are more than double the typical Rhode Island energy price, for an estimated $497 million in above-market costs over the 20-year deal.

In 2009 and early 2010, the Rhode Island Public Utilities Commission rejected proposals by Deepwater Wind and National Grid, largely over cost.  The parties then returned with a revised proposal.  In 2010, TransCanada Power Marketing Ltd. unsuccessfully argued that the Rhode Island commission shouldn't consider that proposal due to constitutional infirmities in the Rhode Island law favoring renewable power contracts with in-state projects.  On August 16, 2010, the Commission issued its order approving the PPA.  After that order was appealed to the state Supreme Court, the Supreme Court issued a written opinion upholding the Commission's Order on July 1, 2011.  In 2012 and in 2015, project opponents petitioned the Federal Energy Regulatory Commission to invalidate the Rhode Island commission's action, which FERC declined to do.  Through all this, the project moved forward and ultimately began local construction earlier this year.

But the project is not yet completely out of stormy seas.  On August 14, 2015, plaintiffs with a history of engagement in some of these earlier challenges filed a lawsuit in U.S. District Court in Rhode Island.  As in previous challenges, this complaint argues that the Rhode Island Public Utilities Commission violated federal laws in approving the Block Island deal because only the Federal Energy Regulatory Commission may regulate wholesale electricity sales.  While it is possible that this case could be swiftly dismissed, if it lingers it could add uncertainty to the project until its resolution.  Last year a federal court invalidated a FERC ruling on the grounds that it impermissibly tread on state rights to set retail electricity rates.  That case, Electric Power Supply Association v. Federal Energy Regulatory Commission, has been appealed to the U.S. Supreme Court.

With construction underway, the Block Island project now has significant inertia behind it.  What impact will the recently filed lawsuit have?  Will it affect Deepwater Wind's position as "first in the water" in the race for U.S. commercial offshore wind development?

EPA proposes methane rules for oil and gas

Wednesday, August 19, 2015

The U.S. Environmental Protection Agency has proposed a suite of new and modified rules affecting the oil and natural gas industry.  Collectively, the proposed rules released on August 18 are designed to reduce methane emissions from oil and natural-gas drilling activities.

As the world tackles climate change and greenhouse gas emissions, methane plays a dual role.  As the key constituent of natural gas, methane offers society an abundant and efficient fuel that can displace reliance on costlier and more carbon-polluting fuels like coal and oil.  At the same time, methane in the atmosphere can act as a greenhouse gas itself, with a global warming potential more than 25 times greater than that of carbon dioxide.  According to EPA, methane is the second most prevalent greenhouse gas emitted in the United States from human activities, and nearly 30 percent of those emissions come from oil production and the production, transmission and distribution of natural gas.  At the same time, U.S. production of oil and natural gas has increased, giving the sector important economic and domestic security impacts.

To address this dynamic, yesterday EPA proposed a series of rules affecting the oil and natural gas sector.  EPA has described the new rules as a "key component" of the Obama administration's Climate Action Plan.  They follow a January announcement of a new goal to cut methane emissions from the oil and gas sector by 40 to 45 percent of 2012 levels by 2025.  Under the administration's view, a key tool supporting that goal is the implementation of standards for methane and volatile organic compound (VOC) emissions from new and modified oil and gas production sources, and natural gas processing and transmission sources.

The rules EPA proposed yesterday include such standards, along with supporting materials.  EPA has described its collective proposal as "a suite of commonsense requirements that together will help combat climate change, reduce air pollution that harms public health, and provide greater certainty about Clean Air Act permitting requirements for the oil and natural gas industry."

EPA's proposed package of rules includes:

According to EPA, the proposed rule will reduce methane emissions by between 340,000 and 400,000 short tons in 2025,  on top of reductions of 170,000 to 180,000 tons of other VOCs and 1,900 to 2,500 tons of hazardous air pollutants.  But industry trade group American Petroleum Institute has called additional regulation "unnecessary for reducing emissions."  Debate over EPA's proposal is likely to be vigorous, before EPA as it considers its proposed rulemaking, as well as before Congress and possibly even federal courts, before the dust settles.

EPA will take public comment on the proposals for 60 days after they are published in the Federal Register.  According to the January announcement, the administration expects the final rule will follow in 2016.  This action on oil and natural gas production follows closely on the heels of EPA's adoption of the Clean Power Plan rules, regulating carbon emissions associated with the electric power industry.