Half of the new electricity generation plants added in 2013 are fired by natural gas and almost 30% of new generation is powered by solar and wind energy, according to an April 8 report from the Energy Information Administration. This combination is likely to mean even more demands on the already-strained natural gas delivery infrastructure.
A need for more pipeline capacity is an obvious impact of adding more gas-fired generators. However, substantial additions of renewable generation also add demands on pipelines. As reported in a recent edition of the trade publication Megawatt Daily, Frank Brock with ICF International points out that when renewables are not running, such as when the sun goes down and the wind stops blowing, “you have a big surge in the need for replacement generation — and that’s coming from natural gas.” This demand for more gas deliverability is weather dependent, and, according to Brock, there will not be a lot of investment in new pipeline capacity unless the demand is “solid and steady.”
This impact will be especially felt in California. According to the EIA report, nearly 60% of the natural gas generation capacity and 75% of solar resources added in 2013 are in California. The state needs generation just to meet load, and also needs flexible generation resources like gas to complement the renewable resources being added to meet an ambitious renewable resource requirement. Deliverability constraints will also be felt in New England, according to Brock, as a result of the shale gas boom in the region.
Part of a solution may be additional gas storage. This could come from distant traditional storage facilities or close-in LNG peak-shavers. Brock says no one is really thinking about storage now, but a probabilistic analysis based on expected weather over the next 10 years would likely show “a huge need for high-deliverability storage.”
The Federal Energy Regulatory Commission (FERC) encourages new storage facilities by allowing storage providers to charge negotiated, market-based rates. FERC allows market-based rates if the seller shows it has no market power. However, for storage and storage-related services related to a facility placed in service after August 8, 2005, market-based rates are allowed without such a showing if FERC determines that: (1) market-based rates are in the public interest and necessary to encourage the construction of the storage capacity in an area needing storage services; and (2) customers are adequately protected.
 Platt’s Megawatt Daily, “Gas fired additions pressure gas deliveries: Analyst”, April 10, 2014 at 1.
Three independent, but not wholly unrelated, events occurred over the last few weeks, each arising out of the Natural Gas Act’s application and the growing importance of LNG exports to the United States and the international community.
(1) Following the crisis in Ukraine, there were continuing calls from a variety of politicians and pundits to increase LNG exports to Europe and decrease Europe’s reliance on Russian exports of natural gas. In particular, a congressional sub-committee considered and advanced H.R. 6 (The Domestic Prosperity and Global Freedom Act). This measure would expedite the application process for contracts with supplies destined for any member nation of the WTO (currently, an expedited process only applies to contracts with supplies destined for countries with which the United States has a free-trade agreement).
(2) Cheniere Energy and Endesa, a Spanish utility company, signed two 20-year LNG sale and purchase agreements (“SPAs”) for 2.25 million tonnes per annum (“mtpa”) commencing upon completion of the Corpus Christi Liquefaction Project. Cheniere Energy has also entered into agreements with counter-parties from the Asian markets, including South Korea and Indonesia. Notably, each of these agreements is at least partially indexed to Henry Hub.
(3) The Department of Energy (“DoE”) conditionally approved an LNG export application for the Jordan Cove Energy Project in Coos Bay, Oregon. This is the seventh permit conditionally granted by the DoE (over 20 remain in progress). The approval is conditioned on future approval by the Federal Energy Regulatory Commission. DoE reviews applications to ensure that sales resulting to countries that do not have free-trade agreements are in the “public interest” (in accordance with the standard set out in section 3(a) of the Natural Gas Act). Significantly, the DoE continues to highlight the importance of supply security to allies of the United States as one of the considerations in making its decision, stating at page 142:
EPA and the Army Corps of Engineers jointly released a proposed rule last week that defines the scope of “waters” under the Clean Water Act. Once the proposed rule is published, the public will have a 90 day comment period before the rule becomes final. The agencies simultaneously issued an interpretive rule on the exemption from permitting requirements in Section 404(f)(l)(A) of the Clean Water Act for certain discharges of dredged material or fill “from normal farming, silviculture and ranching activities.” In contrast to the proposed rule on the Clean Water Act, the interpretive rule addressing the “normal farming” exemption is effective immediately.
The proposed rule aims to provide some clarity on an issue that had been muddied by the Supreme Court in Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers, 531 U.S. 159 (2001) (“SWANCC“) and Rapanos v. United States, 567 U.S. 715 (2006). Those rulings had struck down as overbroad the agencies’ interpretation of their jurisdiction in specific instances to regulate discharges into “waters of the United States.” In response to these decisions, the agency developed guidance in 2008 that required case-by-case determinations of jurisdiction for certain categories of waters. Under the new proposed rule, the agencies will now assert blanket jurisdiction over some of those categories — most notably, all “tributaries” as defined in the proposed rule, and adjacent wetlands.
The press release accompanying the proposed rule emphasizes that the new definition of “waters of the United States” does not cover any new types of waters that were not historically covered under the Clean Water Act, and it notes that the proposed rule preserves existing Clean Water Act exemptions for agriculture. The simultaneous release of the interpretive rule on the exemption for “normal farming activities” and publication of a memorandum of understanding between the U.S. Army Corp of Engineers and the Department of Agriculture likewise appears to be aimed at reassuring the agriculture industry that the proposed rule will not result in radical changes in Clean Water Act enforcement. Nevertheless, initial reaction to the proposed rule has not been universally positive: the American Farm Bureau Federation released a statement earlier this week promising to “dedicate itself to opposing this attempted end run around the limits set by Congress and the Supreme Court.”
When Labour leader Ed Miliband made a promise in September 2013 to freeze household fuel bills for 20 months if he were to win next year’s election, he instantly made energy supply and pricing one of the central election topics in the UK. Prime Minister David Cameron’s immediate response was to cut green levies paid through household bills and order Ofgem, the electricity and gas regulator, the Office of Fair Trading (OFT) and the Competition and Markets Authority (CMA) to assess the state of the energy market.
The results of this assessment were published in the State of the Market Assessment report on 27 March 2014. At the same time, Ofgem proposed that the CMA should investigate the market to “once and for all clear the air” and determine whether “there are further barriers to effective competition”.
The report criticises the effectiveness of competition in the energy market and finds “possible tacit co-ordination” on the size and timing of price rises. The UK energy market is composed of six vertically-integrated companies – SSE, Scottish Power, Centrica, npower, E.ON and EDF Energy (known as the “Big 6”) – that generate power and sell it to customers, and who together account for 95% of the market.
The market assessment concluded that:
- Prices and profits are increasing – UK energy prices rose 24% from 2009 to 2013 and energy supplier profits rose from £233 million in 2009 to £1.1 billion in 2012.
- Market shares of all players are very high.
- Switching rates of customers are very low.
- Customer trust is low – 43% of the British customers do not trust energy suppliers to be open and transparent about pricing.
- Segmentation of the market is quite high – suppliers still serve customers in their former incumbent region despite liberalisation).
While Ofgem believes that inefficiencies of the suppliers due to the low level of competition may be contributing to the maintenance of high prices, industry representatives tell a different story. They claim that tariffs have increased due to rising wholesale energy costs, network charges and high government-imposed environmental levies, and add that competition on the market is active and well-functioning.
The CMA now has until July to decide whether to conduct the market investigation or not. Its main focus will be to assess whether vertical integration of the large suppliers might lead to a low level of competition on the market and, if so, whether these companies should be broken up. The potential review will be the newly-established CMA’s first big test following the official assumption of its powers on April 1, 2014.
Initial reaction to the assessment has been mostly positive, stating that a formal market review could restore consumer confidence and remove some of the alleged politicised resentment against the energy industry as a whole. However, against the backdrop of possible demands to break up the Big 6 there are significant concerns that this will put the brakes on badly-needed investment in UK power generation and next generation infrastructure.
On March 28, 2014, the White House released its “Climate Action Plan – Strategy to Reduce Methane Emissions.” The plan summarizes the Administration’s strategy to reduce methane emissions from several sources. The strategy includes proposing new standards, new rules, new voluntary strategies and programs and new regulations. The plan outlines measures to reduce emissions and to improve measurement of sources and emissions.
According to the plan, Methane has a global warming potential more than 20 times greater than that of carbon dioxide, per metric ton. On that basis, methane makes up almost 9% of all the greenhouse gases emitted as a result of human activity in the United States. Although in the United States methane emissions have decreased by 11%, they are projected to increase from the current carbon dioxide equivalent of 560 million tons in 2012 to over 620 million tons in 2030 absent additional action to reduce emissions. The main sources of human-related methane emissions are agriculture with 36%, natural gas systems with 23%, landfills with 18%, coal mining with 10%, petroleum systems with 6%, and wastewater treatment with 2%.
The plan anticipates a number of initial information gathering activities this spring and summer with the results being published in the fall. Any final rulemakings would be completed by the end of 2016.
On March 28, His Serene Highness, Prince Albert II of Monaco bestowed innovation awards for excellence in the field of environmental technology to three emerging technology companies — Mango Materials, Frigesco, and One Earth Designs — out of a field of 22 companies from 11 countries that participated in the annual three-day CleanEquity Monaco conference in Monte Carlo.
The award winning companies featured vastly different technologies to earn awards in three different categories:
- Mango Materials, a San Francisco-area research stage company that produces biodegradable plastics from waste biogas (methane) that are economically competitive with conventional oil-based plastics, earned the award excellence in the field of environmental technology research;
- Frigesco, a UK-based development stage company focused on improving the energy efficiency of commercial refrigeration systems and in particular defrost technology, through innovative and patented engineering solutions, won the award for excellence in the field of environmental technology development; and
- One Earth Designs a Hong Kong-based company that is commercializing SolSource, a high performance parabolic solar cooker designed as a low cost, environmentally benign platform technology to replace traditional wood, charcoal or peat fired cooking that persists in many areas of developing world that lack reliable access to electricity, won the award for excellence in the field of environmental technology commercialization. SolSource can also be combined with a thermoelectric generator to power small appliances or to charge batteries.
CleanEquity, billed as the World’s Leading Emerging Cleantech Conference, invites 20-30 companies each year from approximately 400 that are considered to present to delegates representing a wide range of venture firms, private equity firms, corporate venture arms, and sovereign investors. Over the seven years of its existence, CleanEquity has brought forward multiple energy and environmental technology companies that have executed on public offerings or strategic transactions. Presenting companies this year showcased innovative technologies for grid-connected renewable energy storage and demand response, hydrogen storage and fuel cells, water treatment and water conservation, gas-to-liquid fuels, air treatment, vehicle electrification and electric vehicle telemetry, energy efficiency, cloud computing, thin-film organic solar pv, and nanoparticle magnets that do not use rare earth elements. The conference also features thought leadership panel discussions, including, this year, sessions on cutting edge energy efficiency and sustainability developments in commercial automotive innovation through motorsport trickledown technologies, water technologies, home automation, and digital manufacturing.
Covington has been the sole law firm sponsor of CleanEquity each year for the past five years.
EPA’s current efforts to curb CO2 emissions from power plants are controversial due to their potential impacts on the cost of electricity and the reliability of the grid given the announced retirements of many coal-fired plants. The ISO/RTO Council (IRC), representing the operators of the regional electricity grids, has made two proposals for managing regional compliance costs and reliability impacts that it recommends to be included in any final CO2 rule.
IRC’s first proposal is for a “Reliability Safety Valve” to ensure that any federal CO2 rule or state implementation plan includes a process to assess and, if needed, mitigate regional reliability impacts that result from compliance actions. The system operator would review states’ implementation plans, identify reliability impacts, and identify interim measures (such as keeping plants on line) until the long-term solution can be implemented. Assessments would be made on a rolling basis instead of on a static basis, and thus some flexibility on compliance dates would be necessary. In addition, because actions in one part of the grid can affect other parts, the impact of state implementation plans on regional dispatch would be evaluated so that regional issues and solutions may be identified.
The second proposal is for a “Regional Compliance Measurement” that would give states the option to use reductions achieved across the regional dispatch footprint to measure compliance with the CO2 rule. According to IRC, determining least-cost compliance over a very large multi-state region can optimize the efficiency of a compliance program for a broad fleet of generators and demand response resources. And the efficiencies of a multi-state approach are recognized even if the individual states do not agree on particular compliance strategies.
IRC’s proposals are intended as preliminary concepts to promote dialogue among policymakers, RTOs/ISOs and interested stakeholders. While not stated explicitly, the proposals presumably apply to both EPA’s proposal to limit CO2 emissions from new power plants (those whose construction started after January 8, 2014) as well as EPA’s upcoming proposal regarding existing plants to be issued by June 1, 2014.
The Polish government has proposed new draft rules on the prospection, exploration and extraction of hydrocarbons as well as their taxation that aim to facilitate the development of shale gas operations in Poland.
The proposed amendments to the Geological and Mining Law would significantly streamline the procedures to grant concessions and also extend concession periods. In particular, they would be subject to a single concession requirement the prospection, exploration, and extraction of hydrocarbons (currently, companies must obtain three separate concession for their prospecting, exploring, and extractive activities). New concessions would typically be granted for periods between 10 and 30 years (currently, the various concessions are granted for periods between three and 50 years).
The proposed amendments would also facilitate the geophysical research of hydrocarbons by requiring that they be subject only to a notification rather than to a prior authorization requirement. Other proposed amendments would also simplify the environmental assessment process and move the timing of the assessments from the beginning of the investment process to a stage just before the drilling commences. The proposed amendments drop the Government’s earlier proposal to establish a state-run fund that would have held a stake in shale gas concessions and that shale gas companies criticized for being overly bureaucratic.
The proposal for a Law on Special Hydrocarbon Tax is intended to establish a preferential tax regime for fossil fuels, including shale gas. The Polish Ministry of Finance estimates that the proposal would bring the overall tax burden imposed on companies engaged in the shale gas production and other hydrocarbon production activities in Poland to around 40%.
In particular, the Hydrocarbon Tax proposal would introduce: (i) a tax on the extraction of certain minerals, and (ii) a special hydrocarbon tax. The tax on the extraction of certain minerals would cover oil and gas and vary according to their type: 3% on conventional gas, 1.5% on unconventional gas; 6% on conventional oil, and 3% on unconventional oil.
The proposed hydrocarbon tax would range between 0 and 25% depending on the ratio of: (i) revenue earned to (ii) expenditure incurred. The tax would amount to 12.5% where the ratio of revenues to expenditure is between 1 and 2; and 25% where the ratio of revenues to expenditure is equal to or greater than 2.
Pursuant to the proposed rules, companies would be required to declare their profits, as well as their expenditure and revenue, via electronic declarations. In addition, they would need to make monthly tax deposits to the Polish tax authorities. Those measures may considerably increase the administrative burden imposed on the companies.
The proposed tax rules will enter into force on 1 January 2015 if they are endorsed by the Polish Parliament in 2014. However, in order to stimulate short-term investments in shale gas operations, the new tax rates would not apply until 2020.
The increasing reliance on natural gas to fuel electricity generators has sparked a need for more coordination between the operators of gas pipelines and electricity grids. Up to now, markets and operations in the two sectors have proceeded independently, but some differences between them have become problematic. Differences are especially problematic in New England, where reliance on natural gas-fired electricity increased from 5% in 1990 to 51 % in 2011. FERC recently launched three initiatives to address some of the problems.
The most far-reaching action is a Notice of Proposed Rulemaking (NOPR) to revise the operating day and scheduling practices of interstate gas pipelines. Generators are challenged in managing fuel procurement risk because of the different operating days used by the gas and electric industries, and because the timeframes for nominating gas pipeline transportation service are not synchronized with the timeframe during which generators receive confirmation of their bids in the day-ahead electric markets. This can cause significant price and/or supply risk for gas-fired generators because, to obtain the best gas price, the generators would need to nominate pipeline transportation service before they know if their electric bid has been confirmed. To address these timing issues, FERC proposed to:
- Start the natural gas operating day earlier (4:00 AM Central instead of 9:00 AM) to ensure that gas-fired generators are not running short on gas supplies during the morning electric ramp periods.
- Start the first day-ahead gas nomination opportunity for pipeline scheduling later (1:00 PM Central instead of 11:30 AM) to allow electric utilities to finalize their scheduling before gas-fired generators must purchase gas and submit nominations for gas transportation service.
- Modify the current times during the day when pipeline nominations may be made and add two additional nomination cycles to provide greater flexibility.
The NOPR also proposes to require pipelines to offer multi-party service agreements that can provide multiple shippers the flexibility to share interstate pipeline capacity to serve complementary needs.
FERC is allowing 180 days for the natural gas and electric industries to reach consensus through the North American Energy Standards Board (NAESB) on any revisions to the proposals and either file consensus standards or notify FERC of the failure to reach consensus. Comments on the consensus standards, or on FERC’s proposals if consensus is not reached, are then due 240 days after the NOPR issues.
FERC also started a proceeding under section 206 of the Federal Power Act (FPA) to ensure that the scheduling practices of Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) correlate with any revisions to the natural gas scheduling practices ultimately adopted by FERC in the NOPR proceeding. Ninety days after FERC adopts a final rule, each ISO and RTO must either propose tariff changes to adjust certain of their schedules or show why changes are not necessary.
Finally, FERC instituted a proceeding under section 5 of the Natural Gas Act (NGA) to ensure that interstate natural gas pipelines are providing notice of offers to purchase released pipeline capacity. Stakeholders say that it would be beneficial to be able to post offers to purchase pipeline capacity when needed, for example to transport natural gas to a gas-fired electric generator. Such offers would inform potential releasing shippers of interest in taking a prearranged release of capacity and the terms offered. FERC’s regulations already require pipelines to provide, on an internet website, notice of offers to release or purchase capacity and the terms of such offers but compliance has been spotty. Accordingly, FERC is requiring all interstate pipelines to submit filings within 60 days that revise their respective tariffs to provide for the required postings of offers or otherwise demonstrate that they are in full compliance with the regulations.
EPA’s Environmental Appeals Board has rejected the Sierra Club’s attempt to require certain greenhouse gas (GHG) limits in a preconstruction permit for a new natural gas power plant, in one of the first EAB decisions to address this issue. In re: La Paloma Energy Center, LLC, PSD Appeal No. 13-10 (EAB Mar. 14, 2014). In La Paloma, EPA Region 6 issued a prevention of significant deterioration permit allowing construction of a natural gas-fired power plant in Texas. In rejecting Sierra Club’s challenges, the Board indicated that it generally will defer to the permitting authority on technical issues relating to GHG limits, but that it reserves the authority to reject insufficiently explained determinations and expects permitting authorities to provide clear justifications for rejecting more stringent GHG limits proposed by those who comment on permits.
Notably, the Board suggested that in some cases it may be appropriate to require such power plants to include supplemental solar power generation as a Best Available Control Technology (BACT) to reduce GHG emissions, which could result in future natural gas plants being required to install supplemental solar power systems (or other alternative energy sources), even where the permit applicant did not suggest or envision the use of such systems. Indeed, the Board suggested that it may well be improper for a permit applicant to “purposefully avoid use of solar hybrid technology in its proposed design to circumvent BACT analysis” of such technology. If the use of such technology was required by a future BACT determination, it could be subject to challenges in court.
The Sierra Club raised two challenges to the permit, both of which the Board rejected. First, the Sierra Club claimed that the Region erred in allowing the permittee to select between three different turbine models, each of which had a different limit on GHG emissions, and instead should have imposed the lowest GHG emission limit, based on the emissions that would be generated from the most efficient model. The Board rejected this argument, finding that the BACT analysis required a comparison of “general types or categories of control technologies,” not a comparison between “specific equipment models.” Moreover, the Board found that the difference in emission rates of the three proposed turbine models were “marginal,” and so the models could be treated as equivalent for BACT purposes.
In its second challenge, the Sierra Club argued that the Region should have required as BACT that the plant use a supplemental solar thermal system to reduce its GHG emissions. The Board rejected this argument, finding that such a proposal would “redefine the source” because of site-specific constraints on the facility – namely, a lack of space for sufficient solar panels. However, the Board criticized the region for not taking a sufficiently “hard look” at whether supplemental solar power would be viable, and made clear that an applicant’s decision not to propose supplemental solar power generation does not automatically mean that such a system is excluded from BACT analysis. The Board made clear that permitting authorities should provide “a clear and full explanation of any decision to reject comments suggesting the use of a solar component at a proposed facility on the grounds that it would require redefinition of the source.”