NPS updates oil and gas rights rules

The U.S. National Park Service has adopted a final rule updating its regulations governing the exercise of non-federal oil and gas rights. The NPS states that the rule improves its ability to protect park resources, values, and visitors from potential impacts associated with nonfederal oil and gas operations located within National Park Service units outside Alaska.

At issue are non-federal oil and gas rights within national park system units.  According to the NPS, these arise where the United States does not own the oil and gas interest, either because:

• The United States acquired the property from a grantor that did not own the oil and gas interest; or
• The United States acquired the property from a grantor that reserved the oil and gas interest from the conveyance.

Currently, 12 park system units are home to 534 non-federal oil and gas operations:

• Alibates Flint Quarries National Monument, Texas (5 operations)
• Aztec Ruins National Monument, New Mexico (4 operations)
• Big Cypress National Preserve, Florida (20 operations)
• Big Thicket National Preserve, Texas (39 operations)
• Big South Fork National River and Recreation Area, Tennessee/Kentucky (152 operations)
• Cumberland Gap National Historical Park, Tennessee (2 operations)
• Cuyahoga Valley National Park, Ohio (90 operations)
• Gauley River National Recreation Area, West Virginia (28 operations)
• Lake Meredith National Recreation Area, Texas (174 operations)
• New River Gorge National River, West Virginia (1 operation)
• Obed Wild and Scenic River, Tennessee (5 operations)
• Padre Island National Seashore, Texas (14 operations)

NPS has stated an expectation that future non-federal oil and gas operations within park boundaries could occur in up to 30 additional System units, based on "the presence of split estates, exploration and production occurring on adjacent or nearby lands, and likely increases in energy prices."

While the NPS promulgated regulations in 1978 governing the exercise of non-federal oil and gas rights, it had not updated these rules since then.  The final rule issued in November 2016 thus represents the first change in over 37 years.  Its changes include a broadening of scope, to cover all non-federal oil and gas operations within the boundary of a system unit outside of Alaska.
 This rule is effective December 5, 2016.

Canada NEB starts Energy East pipeline review

Canada's National Energy Board has ruled that the applications are complete for the Energy East Pipeline Project and a related gas project.  This determination starts the NEB's review process, under which the Board must issue its recommendations to the Minister of Natural Resources within 21 months.

The National Energy Board is an independent federal regulator of several parts of Canada's energy industry, including the regulation of pipelines, energy development and trade in the Canadian public interest.

As envisioned by proponents TransCanada and Energy East Pipeline Ltd., Energy East would be a 4,500-kilometer pipeline that will transport approximately 1.1 million barrels of crude oil per day from Alberta and Saskatchewan to the refineries of Eastern Canada and a marine terminal in New Brunswick.  Some existing natural gas pipeline would be converted to oil transportation pipeline, while other facilities would be newly built.  The project is motivated in part by a relative surplus of Western Canadian crude production, with relatively few ways to ship that crude to refineries or ports.

The related Eastern Mainline Project entails about 279 kilometers of new gas pipeline and related components, designed to let TransCanada continue to supply gas after the proposed transfer of certain Canadian Mainline facilities to Energy East Pipeline Ltd. for conversion to crude oil service.

On June 16, 2016, the National Energy Board announced its determination that due to the interconnections between the applications, the Energy East and Eastern Mainline projects are more effectively assessed within a single hearing process, with one record, reviewed by one Panel of Board Members.   It also deemed the applications complete to proceed to assessment and a public hearing, starting the 21-month review process.

The Panel must submit a report to the Minister of Natural Resources recommending whether or not the projects should proceed, or on what conditions. This report is due no later than March 16, 2018.  According to the NEB, the process will include hearings, panel sessions, and assessments of the upstream greenhouse gas emissions associated with the project.

Climate and energy in 2016 State of the Union

President Obama delivered his final State of the Union address on January 12, 2016.  The White House has posted his remarks as prepared for delivery to Congress.  Climate change, and related energy and environmental issues, formed a prominent theme in this year's speech.

The White House.

Climate change first surfaced in the 2016 State of the Union as part of one of four "big questions" President Obama posed for the nation.

Second, how do we make technology work for us, and not against us -- especially when it comes to solving urgent challenges like climate change?

After announcing a "moonshot" medical research effort to cure cancer to be led by Vice President Joe Biden, President Obama said, "We need the same level of commitment when it comes to developing clean energy sources."

He then spent several minutes addressing climate change directly.  First, he noted effective consensus that climate change is a topic worth tackling:

Look, if anybody still wants to dispute the science around climate change, have at it. You will be pretty lonely, because you’ll be debating our military, most of America’s business leaders, the majority of the American people, almost the entire scientific community, and 200 nations around the world who agree it’s a problem and intend to solve it.

He then touted the economic and environmental effects of investment in renewable and distributed generation and energy storage:

But even if -- even if the planet wasn’t at stake, even if 2014 wasn’t the warmest year on record -- until 2015 turned out to be even hotter -- why would we want to pass up the chance for American businesses to produce and sell the energy of the future?

Listen, seven years ago, we made the single biggest investment in clean energy in our history. Here are the results. In fields from Iowa to Texas, wind power is now cheaper than dirtier, conventional power. On rooftops from Arizona to New York, solar is saving Americans tens of millions of dollars a year on their energy bills, and employs more Americans than coal -- in jobs that pay better than average. We’re taking steps to give homeowners the freedom to generate and store their own energy -- something, by the way, that environmentalists and Tea Partiers have teamed up to support. And meanwhile, we’ve cut our imports of foreign oil by nearly 60 percent, and cut carbon pollution more than any other country on Earth.

Gas under two bucks a gallon ain’t bad, either.

President Obama then called for changes to transition to clean energy sources:

Now we’ve got to accelerate the transition away from old, dirtier energy sources. Rather than subsidize the past, we should invest in the future -- especially in communities that rely on fossil fuels. We do them no favor when we don't show them where the trends are going. That’s why I’m going to push to change the way we manage our oil and coal resources, so that they better reflect the costs they impose on taxpayers and our planet. And that way, we put money back into those communities, and put tens of thousands of Americans to work building a 21st century transportation system.

Now, none of this is going to happen overnight. And, yes, there are plenty of entrenched interests who want to protect the status quo. But the jobs we’ll create, the money we’ll save, the planet we’ll preserve -- that is the kind of future our kids and our grandkids deserve. And it's within our grasp.

Climate change is just one of many issues where our security is linked to the rest of the world.

His final reference to climate change came while discussing international engagement, and "seeing our foreign assistance as a part of our national security":

When we lead nearly 200 nations to the most ambitious agreement in history to fight climate change, yes, that helps vulnerable countries, but it also protects our kids.

Climate, energy, and environmental issues thus featured prominently in the 2016 State of the Union speech.  Over the coming year, these themes -- domestic and international action on climate change, investment in renewable energy and distributed generation, transition away from oil and coal -- will likely continue to play out at the federal level.

Report: New England electric sector will face gas supply deficit

A recently released report on the adequacy of New England’s natural gas pipeline infrastructure has identified the potential for shortfalls in gas supply to electric generators through 2020.  The November 20, 2014 report, Assessment of New England’s Natural Gas Pipeline Capacity to Satisfy Short and Near-Term Electric Generation Needs: Phase II, was prepared by consulting group ICF International for regional electric grid operator ISO New England Inc.  It found “a high probability that the electric sector will have a gas supply deficit on 24 to 34 day per winter by 2019/20.”

The Phase II report follows on a 2011/12 “Phase I” study by ICF of the adequacy of the natural gas pipeline infrastructure in New England to serve the combined needs of the core natural gas market and the regional electric generation fleet.  In the years since the Phase I study, existing natural gas and electric power systems have experienced significant changes, with further changes projected.  ISO-NE also identified the need to extend the power sector gas supply adequacy analysis beyond the peak winter and summer demand day, to examine supply adequacy throughout the peak winter demand period (December 1 through February 28).

ICF’s Phase II report presents its updated findings given these changes.  Its conclusions include:

• Despite the likelihood of 450 MMcf/d of new interstate natural gas transportation capacity being added by the end of 2016, the New England market is likely to remain supply constrained through 2020.
• Updating projections for energy efficiency has a significant impact on projected gas consumption for electric generation. The studied cases reduced projection winter peak day gas consumption by as much as 550,000 Dth by 2019/20.  However, this was not sufficient to eliminate the projected winter peak day supply deficits.
• Future imports of liquefied natural gas (LNG) into the region are likely to be well below the rated capacity of the import terminals.  Neither the Northeast Gateway nor Neptune offshore import terminal has received any shipments since 2010, and neither was projected to receive any future LNG shipments in this study.
• The Maritimes & Northeast Pipeline from Eastern Canada into New England is expected to continue to flow at full capacity on a peak winter day. Eastern Canadian gas production is expected to decline overall from 2015 through 2020, even as the Deep Panuke field ramps up its production. Historically, the Canaport LNG terminal in St. John, New Brunswick, has been managed to keep the pipeline full on peak winter days (when New England gas demand and gas prices are highest). In the future, with fewer LNG shipments coming in, the pipeline will flow full on fewer winter days, reducing natural gas supplies into New England.
• The Winter Near-Peak analysis indicates that gas supply deficits may occur not just on peak days, but also on multiple high demand days throughout the winter. Based on projected gas supplies, local distribution company (LDC) demands for retail gas supply, and electric generator gas demands, there is a high probability that the electric sector will have a gas supply deficit on 24 to 34 day per winter by 2019/20.

With the Phase II report now in ISO New England's hands, the grid operator has an updated analysis of the adequacy of the region's natural gas pipeline infrastructure to meet all the demands on it through 2020.  ISO New England describes itself as playing three critical roles: grid operation, market administration, and power system planning.  From all three of these perspectives, projections of a high probability of gas supply deficit for the electric power sector are troubling.  ICF's findings thus may shape how ISO New England -- or state and federal regulators -- reforms the New England gas and electric markets.

ISO New England's Winter Reliability Program 2014-2015

Keeping the lights on is what electric grid operators do around the clock – but challenges in New England are leading its grid operator to prepare for a winter when the availability of affordable electricity may be challenged.  In preparation, ISO New England, Inc. has received federal approval for a new Winter Reliability Program for the 2014-2015 winter season.

Winter is coming.

ISO New England is the federally-designated regional transmission organization for almost all of New England.  In this role, it is responsible for planning and operating electricity markets to balance supply and demand in real time.   

The grid operator first turned to a Winter Reliability Program in 2013.  ISO New England projected that a limited supply of natural gas and the retirements of several major generating plants would lead to a shortage of about 2 million megawatt-hours of energy during the winter months.  To insure against this gap, the grid operator held a competitive process to procure up to 2.4 million megawatt-hours of energy for the winter season, from a combination of oil-fired generators, dual-fuel generators, and demand response assets.  In exchange for their commitment to provide power when called upon, the selected generators and demand response assets received payments regardless of whether they were actually needed.

In ISO-NE's eyes, the 2013-2014 Winter Reliability Program proved essential in maintaining reliability during the “polar vortex” and other unusually cold conditions.  After adjusting for resource unavailability, the final cost of the 2013/2014 program was approximately $66 million, which came in below the original estimates of about $75 million.

While last year’s program was intended to be a one-time solution to bridge a reliability gap, this summer ISO-NE and regional stakeholder body NEPOOL identified additional challenges for the coming winter.  Specifically, more severe pipeline constraints, difficulty replenishing oil inventories, and large-scale generator retirements continue to threaten the coming winter's reliability and expose consumers to the risk of price spikes.

As a result, ISO-NE asked the Federal Energy Regulatory Commission to approve another program to mitigate reliability concerns for the 2014-2015 winter.  The new program, which the FERC accepted last month, combines features of last year’s program with further modifications.  For example, the new demand-response component is much the same as in last year’s program, while permanent rules related to auditing dual-fuel generators and the partial elimination of higher-cost fuel requirements are based on similar features in last winter’s program.

On the other hand, the new program has been modified as a result of several market changes that will be in effect prior to winter 2014/2015 as well as the FERC's clarification of what generators must do to procure adequate fuel for their expected run times.  The new program also adds a liquefied natural gas (LNG) component to improve fuel neutrality, and changes the basis for compensation from upfront inventory to actual unused inventory at the end of the winter.  While participants in last year's program were paid on an as-bid basis, the new program provides compensation for the fuel inventory and demand response programs based on a set rate of $18 per barrel.  This $18 price is designed to represent the carrying costs, price risk, availability cost and liquidity risk of the last resource needed to meet a cumulative inventory of 3.5 million barrels of oil.

The program also includes incentives for commissioning duel-fuel capacity: the ability to run on either oil or gas. Generators that have not operated on oil since at least December 1, 2011, and that demonstrate a plan for commissioning, or recommissioning a mothballed dual-fuel unit, by December 1, 2016, will be eligible for compensation to offset some of the associated costs.

The new program is moving forward.  On September 9, 2014, the FERC issued an order accepting the region’s proposed 2014/2015 Winter Reliability Program.  In the order, FERC requires ISO-NE to initiate a stakeholder process by January 1, 2015, to develop a proposal to address reliability concerns for the 2015/2016 winter and future winters, as necessary, to schedule meetings and submit progress reports, and to include certain analysis and recommendations in its Annual Markets Report.

For the proposed 2014/2015 program, the Analysis Group estimated costs for the separate components: the maximum cost of the demand response component would be about $2.4 million; the cost of the unused oil inventory and LNG contract volume components would be based on how much fuel remains unused, and assuming, at the high end, that 100% of the targeted amount of fuel is unused, the estimated cost would be $82.6 million; and the maximum cost for the dual-fuel commissioning program is estimated to be $12.9 million for units that commission by December 1, 2015.  The dual-fuel auditing provisions are estimated to cost a maximum, annually, of $7 million.

Consistent with the Commission’s order on the first winter program, the costs will be allocated to real-time load obligation, which is paid by load-serving entities, rather than to regional network load, which is paid by transmission owners.

Requests to Participate in the Oil Program, LNG Program, or Demand Response Program were due to ISO New England Customer Service by October 1, 2014. Dual Fuel Commissioning Requests are due by December 1, 2014

Federal report details U.S. natural gas market

Last week the Federal Energy Regulatory Commission's Office of Enforcement released its assessment of domestic natural gas, electric and other energy markets.  The 2012 State of the Markets report (14-page PDF) describes how changes in both supply and demand led to record low pricing for natural gas at the same time as record high demand for that fuel.

2012 saw significant increases in the production of natural gas from shale and other unconventional resources. Domestic natural gas production grew 5 percent, reaching a new all-time record. Improved drilling rig efficiency boosted production from the Marcellus shale in Pennsylvania, Texas’s Eagle Ford shale, and the Fayetteville shale in Arkansas.  Shale gas production rose from 22 percent of total U.S. natural gas production in 2011 to 38 percent by the end of 2012.

At the same time, total average daily natural gas demand reached a new record, growing 4 percent to 70 Bcf/d in 2012. This growth in demand occurred despite a 10 percent drop in residential and commercial demand for natural gas due to the warm winter. Growth in demand for natural gas for electric power generation surged, driven by the low price of gas and tougher environmental regulations on coal-fired power plants. Generators’ demand for natural gas grew 21 percent over 2011, reaching a record 25 Bcf/d and surpassing residential and commercial demand for the first time in history.  Natural gas replaced coal in many places; coal-fired generation fell to the lowest level in 30 years. Since natural gas is often the marginal fuel in electric generation, lower natural gas prices generally resulted in lower electric prices across the country.

The combination of these changes in supply and demand led U.S. natural gas prices to a ten-year low last year. The spot price at the Henry Hub trading point averaged $2.74/MMBtu for the year, down 31 percent from 2011. Spot prices at Henry Hub ranged from a low of $1.82/MMBtu to $3.77/MMBtu at the onset of the winter heating season.  Most of the country enjoyed low natural gas prices, although pipeline constraints led to much higher pricing in New England, particularly in the winter.

UAE opens first 100 MW solar project

The United Arab Emirates has recognized the start-up of its largest solar energy project to date.

The Shams 1 solar plant generates of electricity by concentrating solar thermal energy to vaporize a fluid into steam, which in turn spins a turbine.  Shams 1 can produce up to 100 megawatts of power, making the project the world's largest concentrating solar power projects.

Concentrating solar power, or CSP projects, use mirrors to heat a working fluid and ultimately to produce steam.  Shams 1 uses parabolic trough mirrors to focus the sun's energy on pipes full of a working fluid, while other concentrating solar projects focus mirrors on a central tower containing the working fluid.  That working fluid's heat is then exchanged into water, which vaporizes into superheated steam.  It is this steam that spins the turbine attached to an electric generator.  Concentrating solar thermal projects differ from those using photovoltaic technology, in which the sun's energy is converted into direct current electricity using specialized semiconductors.

Shams 1 was developed by Shams Power Company PJSC, a special purpose vehicle owned 60% by UAE-owned Masdar and 40% by the Total Abengoa Solar Emirates Investment Company, a vehicle in turn jointly owned by Total (50%) and Abengoa (50%).  These companies are said to have invested $600 million in building Shams 1.

With its commissioning, Shams 1 becomes the first utility-scale renewable power project in the UAE.  Other first and "biggests" include the largest financing transaction for a solar power project (US$600 million) the largest operating single pure concentrating solar plant in the world. 

UAE is blessed with energy resources.  For years, interest has focused on its oil and gas production.  Shams 1 is a small step toward resource diversification.  Will UAE continue to invest in alternative and renewable energy?

Marcellus shale gas drilling slows

Natural gas drilling activity has declined in parts of the Marcellus Shale formation under Pennsylvania and other eastern states, largely as a result of low gas prices.  These prices in turn are largely the result of significant increases in the available supply of recoverable natural gas made possible by horizontal drilling techniques and hydraulic fracturing or fracking.  As a consequence, many natural gas producers are focusing on areas of shale rich in both gas and natural gas liquids.

The Marcellus Shale, a layer of ancient marine sediment rich in organic material and extending beneath Pennsylvania, Ohio, West Virginia, New York, and Maryland, is believed to be one of the world's largest natural gas fields.  In 2008, drilling activity in the Marcellus Shale began to increase significantly, as these newer drilling techniques and increases in the price of other fuels like oil made the shale gas economically feasible to recover.  (Compare this map of Marcellus shale drilling activity in Pennsylvania from 7/25/2008 to this map of permits issued as of March 9, 2012.)  As of this spring, Pennsylvania alone had issued 11,772 permits for vertical and horizontal gas wells in the Marcellus formation.

One result of the expansion of shale gas production is a significant decrease in the price of natural gas.  Since 2008, natural gas prices at the Henry Hub in Louisiana (where gas as a commodity is typically priced) have fallen from over $12 per million British thermal units (MMBtu) to as low as $2 per MMBtu.  Other factors have played a role in this price decline, such as a mild winter with lower-than-expected heating demand and the overall economic slowdown, but the increase in supply due to shale gas production is viewed as a major cause of the price decline.

Now, one of the effects of the price decline is a decrease in natural gas drilling activity.  This decrease is particularly marked in areas where the shale produces "dry gas", or natural gas that is primarily methane and is low in so-called natural gas liquids.  Natural gas liquids -- hydrocarbons other than methane that are extracted when natural gas is processed in a natural gas treatment facility -- include ethane, propane, and butanes.  These natural gas liquids are important feedstocks for the production of many chemicals and plastics, and add value to the natural gas produced from "wet" shales.

Where shale gas contains significant amounts of natural gas liquids, production appears steady or increasing, while gas producers in areas with lower amounts of natural gas liquids are now saying that they are having a hard time making money off gas alone.  If this trend continues, areas of dry gas like much of the known portions of the Marcellus Shale may continue to see a slowdown in drilling activity while producers focus on areas rich in natural gas liquids.

EnergyOcean International 2012

This week I am attending EnergyOcean International 2012, the ninth annual conference for the offshore renewable energy sector.

This morning's keynote address was delivered by Tommy Beaudreau, Director of the Bureau of Ocean Energy Management. Director Beaudreau gave an overview of BOEM and how its Office of Renewable Energy Programs fits in with other responsibilities like offshore oil and gas leasing and regulation.

Upcoming presentations include a discussion of global offshore renewable energy development, marine spatial planning, best practices for managing interactions between wildlife and offshore projects, an update on what's happening with wave and tidal energy, and a review of successful project finance strategies.