Grid Integration: Juggling Surplus Grid Power from Wind and Solar is Currently Expensive Any Way You Look at It

Grid Integration: Juggling Surplus Grid Power from Wind and Solar is Currently Expensive Any Way You Look at It

The cheapest way to deal with temporary excess grid power, particularly from solar, is simply to curtail it.  This delays payback for a solar project. This can be done with solar plants owned by utilities but not so easily with rooftop solar owned by people and business who sell their excess to the grid. Surplus power can also be exported but this is often at a loss – due to supply/demand and subsequent immediate pricing a utility might have to pay to export its power. Grid integration issues with renewables increase as more intermittent renewables - wind and solar - penetrate the grid. At around 20-25% penetration the issues exacerbate and get more expensive. This has happened in Germany and is now beginning to occur in earnest in California.

Even though utilities like PG&E in California have a hierarchy of preferred energy sources from efficiency to renewables to conventional sources they still have to balance the grid to prevent blackouts and brownouts. California utility-generated energy was 15% renewables in 2010 and increased to 27% now with nearly 80% of the increase being solar. That does not include about 4% from rooftop solar. The utility solar is what gets curtailed. There was 15% curtailment in 2015, 21% in 2016, and 31% in the first few months of 2017. Part of the increased curtailment is due to increased river flows to hydro plants as rains relieved the drought. More rooftop solar will increase the surpluses with which utilities must deal. The drop in price of solar power due mainly to better panel efficiency has made rooftop solar more affordable and that along with continued government subsidies encourages more people and businesses to install solar. Utility models in California reward energy efficiency which helps the utilities decouple energy sales from profits and pair efficiency and energy services with profits but this is partial as they still benefit from build-outs and sales. Currently, Californians pay 50% higher electricity costs than other states. If renewables mandates continue to go higher those costs will increase further. The state also has aggressive mandates for energy storage which helps to balance the grid but again cost is the main issue. California is a massive energy user and currently burns about an eighth of the natural gas burned in the U.S. No doubt the renewables push will continue but so too will the grid integration challenges. The system operator Cal-ISO noted that for the first two months of 2017 18% of sales involved negative pricing (ie. losses) while for the same period in 2014 it was 2.5%. Another issue in California is that the big solar farms and solar thermal plants are in the desert hundreds of miles from populated cities and power line congestion can be problematic during peak demand times. That is one argument in favor of redundancy, of building more gas plants close to the cities. Currently, there are disagreements about how much redundancy is needed as many gas plants run at low capacity due to solar availability and so the cost of building newer and better ones to replace old less efficient ones, though more useful, would add significantly to ratepayer costs and may not be necessary anyway.

To summarize, the current alternatives to dealing with excess grid power are:

1)      Curtail solar (and possibly some wind)

2)      Export power, most often at a loss – the importer benefits but often needs to curtail its own solar power to accommodate the imported power which reduces the cost benefit

3)      Curtail natural gas plant power output which can be wasteful/inefficient and hard on the plants

4)      Employ battery storage and other energy storage

5)      Convert to heat for some applicable process (this is popular in Germany)

6)      Power EVs – dynamic pricing could be an incentive to charging during high solar generation time – this would require many more EVs than currently and more charging infrastructure – if there were enough EVs the reverse could happen, that is vehicle-to-grid (V2G) where EVs sell power back to the grid at high prices during peak demand times, effectively acting as battery storage to balance the grid. This scenario, however, is far off – it is not likely for a decade or two.

References:

Energy Goes to Waste as State Power Glut Grows – by Ivan Penn, in LA Times, June 2017

Life Cycle CO2 Emissions: Pipeline Gas vs. LNG and the Climate Benefits of LNG Relative to Coal

Life Cycle CO2 Emissions: Pipeline Gas vs. LNG and the Climate Benefits of LNG Relative to Coal

This analysis comes mainly from a Wood Mackenzie report mainly addressing upstream CO2 emissions. Basically the conclusion is that average full life-cycle CO2 emissions for LNG are about 11-12.5 % higher than the avg. for pipeline gas. The analysis does not include so-called fugitive methane emissions from leaks but other analysis from the Pace Global/Centre for Liquefied Natural Gas paper includes total GHG analysis. The vast part of the increased emissions is fuel use – the fuel used in liquefaction being the highest, followed by the LNG burned in transport via LNG tankers. 

If one were to do a strictly upstream comparison then LNG would be even higher in emissions and as the paper states could even be comparable to Canadian tar sands projects in terms of ‘emissions intensity’ or ‘emissions per barrel of oil equivalent.’ However, this is misleading. Such analyses take into account the high energy density of crude oil. Even so, the typical LNG project would be at the low end of any tar sands project so still significantly below the average tar sands project. Pipeline gas life cycle emissions would be half of the lowest emitting tar sands project and typically less than 20% of the avg. tar sands project. The graph given could be manipulated by anti-gas interests to show (quite erroneously) that LNG emissions are comparable to tar sands emissions. In that sense I am not sure why the authors chose to compare with tar sands projects. Life-cycle emissions for avg. global LNG are still around 62% of what they would be for a modern coal plant and about 33% of what they would be for the average global coal plant so there is still a very clear climate benefit. Downstream emissions for LNG would typically be about 5% less than for pipeline gas since pipeline gas typically does not strip and vent CO2 as LNG processing does, so that the CO2 in the pipeline gas stream (global avg. of about 5%) comes out in combustion at the gas-burning plant. 

It should perhaps be noted that CO2 in pipeline gas from the main U.S. shale gas fields is quite variable but for the biggest gas play, the Marcellus Shale, is typically lower than 1% and as low as 0.1%. Haynesville Shale gas can be up to about 5% CO2 but most U.S. shale gas plays seem to be below about 2.5%. Thus, U.S. current LNG exports from Sabine Pass are likely to have significantly less CO2 than the global avg. and those from the small Cove Point LNG export terminal under construction will be very low since they will be mostly or entirely from the Marcellus. Thus CO2 from stripping and venting for LNG or venting at combustion for pipeline gas for Marcellus gas would be less than 20% of the global average. Thus the gas quality of the Marcellus in terms of CO2 content is very good and far exceeds the global average. That means Marcellus gas is about 3.2-4.5% less in life cycle CO2 emissions than typical global avg. gas which would put U.S. LNG predominantly from the Marcellus at 58% life cycle emissions of a modern coal plant rather than the 62% quoted above. The Wood Mackenzie report does not appear to have used any U.S. LNG since it is relatively new on the scene.

The report does break down the emissions into component processes. LNG burned in shipping is typically about three times gas burned for compression to move it through the pipeline. In terms of life-cycle emissions that is about 0.4% for compression and 1.2% for shipping. Shipping varies according to distance traveled. Liquefaction contributes about 6.6% to life-cycle emissions, typically burning 7-9% of the feed gas. Regasification emits only about 5% of what liquefaction emits so is negligible in comparison, far less than a tenth of a percent of life cycle emissions.

The Wood Mackenzie paper also mentions that if carbon pricing exceeds about $30 per tonne then CCS for LNG projects could become economically viable. Currently, only 2 of 64 global LNG projects utilize CCS and the reasons they do are both carbon pricing and very high CO2 content in the gas relative to other projects. The two projects are Statoil’s long-time Snohvit project in the Norwegian North Sea and Chevron’s Gorgon project in Western Australia which is set to become the largest CCS project in the world with 3.4 to 4 million tonnes of CO2 per year to be captured and sequestered. This is over five times the amount at Snohvit.

The bottom line of the Wood MacKenzie report is the same as the bottom line here: life cycle emissions from natural gas are typically less than half of modern efficient coal plants and a third of emissions from the average global coal plant which is neither efficient nor modern. The quite detailed Pace Global report available from the Centre for Liquefied Natural Gas referenced below compares total life cycle GHG emissions between coal and LNG. This includes fugitive methane estimates. The conclusion is similar or actually even more in favor of LNG relative to coal – that the highest emitting LNG scenario emits about half of the GHGs of the lowest emitting coal life cycle emissions. In some places the GHGs emitted from just mining and transporting coal are as much as the life cycle GHG emissions from LNG projects and significantly more than pipeline gas projects.

References:

Upstream Carbon Emissions: LNG vs. Pipeline Gas – by Wood Mackenzie, April 2017

Composition Variety Complicates Processing Plans for U.S. Shale Gas – by Keith Bullin and Peter Krouskop, Bryan Research and Engineering, Inc. (2008)

LNG and Coal Life Cycle Assessment of Greenhouse Gas Emissions – prepared for Center for Liquefied Natural Gas – by Pace Global, Oct. 2015

The Potential of Regional Natural Gas Power Plant Build-out to Relieve Appalachian Gas Gluts, Present and Future

The Potential of Regional Natural Gas Power Plant Build-Out to Relieve Appalachian Gas Gluts, Present and Future

This post stems mainly from a recent webinar I attended on the subject, referenced below. The panel discussion included a PJM Power Market executive, Michael E. Bryson, VP of operations, a utilities legal consultant, Richard A. Drom, and a natural gas and energy market analyst, Matthew Hoza of BTU Analytics. The discussion was introduced and moderated by Marcellus correspondent Jamison Cocklin.

The conclusion from the webinar was that while new power plants will certainly help by soaking up some demand, LNG exports abroad and to Mexico will take up most of it. BTU analyst Matt Hoza predicted 5 years of modest gas excess with possible spikes during cold winters. Prices are not expected to match Henry Hub any time soon but should remain on average as they are, reasonably close. Since the U.S. has some of the lowest cost natural gas it is inevitable that LNG exports will continue and expand offering some guarantee of reducing gluts as more facilities come online.

The webinar offered insights from the gas producer perspective, the infrastructure perspective, the utility perspective, and the regulatory/legal perspective. Power plants will be most helpful in the North-Eastern PA area where infrastructure constraints, delays, and permit denials have been higher. The Western Appalachian area has seen some new takeaway capacity and will see more in the near-term and mid-term. Gas power plants built close to shale production areas offer superior economics to any other fuel source, good fuel security and good fuel assurance. Gas on gas competition is also possible as the economics of replacing outdated inefficient gas plants with new efficient combined-cycle plants can also be compelling. Fuel assurance, fuel security, fuel diversity, grid reliability, grid flexibility, and grid resiliency are all issues addressed by power generators. 

A recent PJM study of grid reliability indicates that grid reliability can be assured in the PJM market area (13 states and 21% of U.S. GDP) with 86% gas and likely more. Since current levels in the market area are at 33% gas generation these leaves plenty of room to economically replace aging coal and gas plants with new efficient ones. The area of growth of gas generation is Appalachia and the Atlantic Seaboard. PJM expects 5-10,000 MW of new gas generation to come on in the next 3 years. Fuel assurance/security may eventually become an issue for gas as reserves wind down but gas is expected to be available at good prices for much or all of the life of these plants. At some point there would likely be higher gas prices as core areas become drilled up but that would also likely activate non-core areas as well as other regional plays, both horizontal and vertical.

As takeaway capacity increases from the Western Appalachian Basin with Rover and other pipelines, growth of about 6 BCF/day is predicted from current production there which is about 13.5 BCF/day. In contrast, the Eastern Appalachian Basin area of Northeastern Pennsylvania currently produces about 9 BCF/day with growth expected to be about 2 BCF/day. This area is more constrained by lack of takeaway capacity. New gas power plants in that region help producers. Cabot selling direct helps them. Dominion’s Cove Point LNG export terminal (export capacity ~750 MMCF/day) will also help stimulate demand there through Transco Zone 5.

Nationally about 14.5 BCF/day of new demand is forecasted. 2.5 BCF/day of that is expected to be from power burn so about 17.2%. LNG exports from Sabine Pass are expected to approach an avg. of about 2 BCF/day later this year. I think 8-10 BCF/day is a reasonable prediction for LNG exports from the U.S. by the next 5 years or so. I don’t think it will get much higher than that as domestic reserves need to be assured. Pipeline exports to Mexico are also expected to add a few BCF/day as new pipes are laid. There is still a chance that Appalachian gas prices will become depressed again – though probably nothing near the lows of the last few years – due to warm winters, cool summers, pipeline delays, and LNG build-out delays.

Drilling productivity from rig efficiencies, better targeting and placement, longer laterals, closer frac stages, more proppant per stage, etc. is expected to gain slightly or modestly. Keeping gas prices reasonably low and keeping them from spiking in winter may actually help gas producers by preventing ‘fuel switching’ from gas burn to coal burn where applicable. Appalachia is also home to coal and coal plants.

Other things noted in the webinar include: the assessment that overall renewables have replaced gas demand by about 4 BCF/day and are not expected to be a barrier to gas build-out. The momentum toward efficiency and decarbonization of the grid is expected to continue. The PJM exec also noted that carbon capture and sequestration (CCS) for coal plants has thus far been an economic failure. Although there have been a few technical successes with CCS it is not expected to make much of a dent in the near future. 

References:

Webinar: Super Power: Will New Gas-Fired Power Plants Solve the Appalachian Shale Gas Glut?
May 4, 2017

Natural Gas Exports Can Solve U.S. Energy Glut – by Shelley Goldberg, in BloombergView, May 5, 2017