High Prices Coming Down the Pipeline

 “Eventually, the politics of energy has to surrender to the physics of energy.” Randy Udall

Two pieces of news have come together in my mind recently. One is the Vermont Public Service Board approval of a new natural gas pipeline through Addison County. The other is a Wall Street Journal article about investments in shale gas production.

The PSB approval and pipeline story is straightforward. Vermont Gas, a subsidiary of Canadian Gaz Metro, is extending its pipeline from Chittenden County and the population center around Burlington southward through Addison County. Phase 2 of the project will have the pipeline cross the narrows of Lake Champlain and serve the Ticonderoga paper mill in New York. In theory, Phase 3 will bring natural gas to the city of Rutland around 2020.

There are objections to the pipeline by many residents of Addison County, generally on two grounds: First, that this will encourage the use of hydrofractured (“fracked”) gas, which is controversial due to its threat to ground water and the general environment near drilling sites. Second, that it will detour us from the pursuit of renewable energy and energy efficiency. A number of people simply don’t want a natural gas pipeline on or near their land.

The proponents of the pipeline argue that it will bring cheap energy to western Vermont, with the resulting economic benefits. Phase 2, they say, will bring far cleaner, cheaper energy to the Ticonderoga plant, with resulting environmental and economic benefits.

A sidebar on shale gas production:

So-called conventional oil and gas generally reside in underground sandstone formations, like sponges made of rock. The oil and gas are in the holes in the sponge (porosity) and the holes are connected to some extent (permeability) so that the oil and/or gas can flow through the sponge, much the same way that water can soak through from one end of a sponge to the other. These conventional deposits can be miles across and hundreds of feet thick.

Shale oil and shale gas deposits can be described the same way, but with different measurements. A shale deposit might have one one-thousandth the porosity and permeability of a sandstone deposit. A shale formation like the Bakken in the northern Midwest covers thousands of square miles but is only ten to maybe 150 feet thick. To imagine the scale, picture a layer of plastic wrap over a couple of football fields. This distribution means two things. One is that there is a lot less energy per horizontal acre in a shale field. The other is that the oil and gas won’t travel from one part of the field to another without a lot of help.

Horizontal drilling is the process of controlling the drill bit so that after going straight down it curves sideways and follows the thin shale formation. Drillers make a number of these horizontal boreholes out from a central drilling point in order to get access to a large area of shale.

Hydrofracturing is the process of injecting a mixture of water, chemicals, and then sand at extremely high pressures to blast open the cracks and pores in the shale. The sand is a “proppant”, keeping the blasted shale from collapsing back on itself. These two operations are an expensive proposition.

A horizontally drilled, hydrofractured well has a relatively short productive life. After a massive initial rush of production, output could drop by 40-50% in the first year. It might drop another 30-40% in the second year, and 20% or more in the third. The key to maintaining production levels is drilling intensity – quickly drilling more wells to replace declining ones. This is also an expensive proposition.

The Wall Street Journal Article (paywalled), as quoted in the ASPO-USA Peak Oil Review, casts doubt on the cheap energy claim by Vermont Gas. There has been a huge rush into shale gas drilling over the past decade. With that rush came a huge rush of natural gas, driving the price down to the historic lows of the past few years. Those low prices, bottoming out below $2 per thousand cubic feet (Mcf), were below the cost of production. Shale gas exploration companies lost tens of billions annually. As far as I can tell each company’s strategy was to hold on to the mineral leases and produce at a loss until their competitors went out of business. Then the remaining companies could clean up as supply declined and gas prices rose. The industry has been running on continued injections of investor cash.

Recently the investors have been getting cold feet. Here’s the key quotation from the WSJ article:

    “Since 2008, deep-pocketed foreign investors have subsidized the U.S. energy boom, as oil and gas companies spent far more money on leasing and drilling than they made selling crude and natural gas. But the rivers of foreign cash are running dry for U.S. drillers. In 2013, international companies spent $3.4 billion for stakes in U.S. shale-rock formations, less than half of what they invested in 2012 and a tenth of their spending in 2011, according to data from IHS Herold, a research and consulting firm. It is a sign of leaner times for the cash-hungry companies that have revived American energy output. The value of deals involving U.S. energy producers plunged 48% this year from 2012, to $47 billion, the first annual decline since 2008. So U.S. oil and gas producers have started to slash spending.”

                              -- (The Wall Street Journal, Jan 2)

Remember that the key to low prices is continued high production and the key to continued high production is drilling intensity. The key to drilling intensity is investment, and that is going away, dropping by a factor of ten in just two years. Investment will only come back when the price of natural gas rises enough to make shale production profitable. Industry analysts argue endlessly about what the breakeven price of shale gas is for various fields, but my general takeaway is that it could mean a doubling of wholesale prices.

Back in Vermont, the residents and businesses of Chittenden, Addison, and Rutland Counties are being promised a bounty of cheap natural gas. The geology of shale gas dictates the economics, and the economics, via investor flight, indicates that this is a false promise. Just about the time that consumers find themselves hooked up to the pipeline and paying for their new appliances the price will start heading for a profitable range. The politics of energy will surrender to the physics of energy before Rutland ever sees a cubic foot of natural gas.

On Dealing With Uncertainty, and a Threshold

My crystal ball is out being repaired. It’s been in the shop for most of my life – starter problems, I think, or maybe the bearings. I share this problem with most of the people who analyze the fossil fuel industry. There are so many factors, so many hands on the steering wheel, that it is essentially impossible to predict price and supply except in long term generalities. Nobody can time the market.

We have been on an undulating production plateau for oil since roughly 2005. World production for all oil-like liquids has been hovering around 84 million barrels a day. Price volatility has stalled the development of new oil fields, resulting in what some commentators refer to as the “practical peak” in oil production. What they mean is that while the world economy wallows in depression, the production of our aging oil fields will continue to decline. This won’t affect prices because of lowered demand, so the new, more expensive to develop oil fields won’t get tapped. When the world economy starts to crawl out of its present collapse, oil demand will increase, bumping up against declining supply. Steeply increasing oil prices will kill the recovery, oil demand, and oil development. Repeat until Amish.

Similar problems afflict natural gas production. Coal energy production has been flat since 2001.

There is a similar problem with global heating due to the combustion of these same fossil fuels. The scientific consensus is that it is upon us and that it is dangerous, but nobody can say with absolute certainty how soon or how abruptly it will happen. Will it be a slow evolution or will it hit a threshold and accelerate wildly? Experts differ.

I have been pondering these dual and balancing uncertainties, fossil fuel depletion and global heating, and I’d like to advocate for immediate, accelerated action.

I like skydiving as an analogy. It has both the elements of risk and inevitability. Imagine that you are a careless skydiver. You jump out of a plane at some undetermined altitude, right into a bank of clouds. You have neglected to wear your altimeter, so you have no way of knowing your distance to the ground. You haven’t checked the weather, so you don’t know how close to the ground the cloud cover goes. There you are, falling blindly through the gray mist. You know the ground is down there, and that you will inevitably be making contact with it at some speed at some time. When do you pull your ripcord? You can’t wait till you break out of the clouds and see the ground. The clouds might be too low, and your chute wouldn’t have time to open. When faced with utter uncertainty and when delay may result in death, the only answer is immediate action. You may spend some time inconveniently floating down through the clouds, but no matter.

Some, especially those who work for fossil fuel companies, advocate a go-slow approach on energy and climate issues. Further study is needed before we act, they say. When you are falling and have no idea when you might go splat, that is no time to convene a committee to study the issue. It is time to pull the ripcord.

There is one strand of that ripcord I’d like to discuss. As a renewable energy consultant and installer, I am always doing calculations, including calculations about the economics of renewable energy installations. This morning I was working up a price quote for a potential customer. I subtracted the Vermont incentive and the federal tax credit, did an idle mental rule of thumb calculation, and had a sudden start.

Due to the economic slump and increased production there is a worldwide glut of photovoltaic (solar electric) modules. The price has dropped by about two dollars per watt over the past couple of years. $8.50 per installed watt used to be the off-the-cuff number for a residential scale solar. Now it is down to around $6.50 per installed watt. Subtract the Vermont incentive of $1.75/watt and the 30% federal tax credit and it comes to $3.33/watt. Now, consider that in Vermont this watt of solar will generate about 1.2 kilowatt-hours per year, or about 30 kilowatt-hours in its module’s 25 year warranted life span. $3.33 divided by 30 equals a levelized cost of 11 cents per kilowatt-hour, almost exactly what I would pay today. (What I would pay, but I don’t, because my solar array feeds more back to the utility than I use.) The economics are more complicated than that, but as of now, in Vermont, residential solar electricity is roughly at parity with the electrons we buy at retail. We have reached a long sought threshold.

25 years may seem like a long payback, but that is a 4% return, rising with the cost of electricity, guaranteed as long as the sun rises, and covered under your homeowners insurance. It is a half a percent better for business owners, who can depreciate their solar assets.

H.446, now called Act 45, offers even more with a feed-in tariff that will probably land between 25 and 30 cents per kilowatt-hour. The Public Service Board, the utility lawyers, and the renewable energy and consumer advocates are still making the sausage on how that will play out. Still, the absolute baseline cost for net-metered customers is viable. It can only get better as retail electricity costs go up.

Solar hot water offers a better return than solar electricity, and energy efficiency better than that. Interest rates are low. So what are you waiting for? Pull the fossil fuel ripcord.

Shale Play

I just read an interesting interview from The Oil Drum with Matt Simmons, the president of Simmons & Company, Int’l, a firm that finances international oil and gas exploration. Simmons has given a number of prescient warnings about fossil fuel supply and price hikes. One thing he discusses is so-called shale gas. I’d like to discuss shale gas, its implications for our everyday lives, and the realities of the situation.

First, understand that an underground oil or natural gas deposit is not like a buried fuel tank. The resource isn’t in a big open pool. It’s more like an underground sponge, the sponge itself being rock and the pores filled with oil and/or natural gas. The bigger the pores in this sponge the more oil it contains per cubic whatever. The better connected the pores, the higher the permeability, and the more easily the oil or natural gas will flow through it to a drilled well.

The most commonly exploited oil and gas containing rock is sandstone. Here’s your insider term of art for the day: The unit of permeability of oil bearing rock is the Darcy. (Jane Austen would approve) An easy flowing sandstone formation in the Middle East might have a permeability between 1 and 5 Darcies. By comparison, a shale formation in the U.S. might have a permeability of 0.5 milliDarcies, or thousandths of a Darcy. Tough to pump gas through that. This used to be a huge barrier to exploiting shale gas.

The other barrier was the thinness of the shale layers. The Bakken Shale formation that underlies the north-central U.S. and southern Canada is about 200,000 square miles in size, but only 10 to 150 feet thick. Imagine a sponge about 1/16” thick and the size of two football fields and you’ll get an idea of the proportion. Drilling standard vertical wells into this was essentially useless. A few feet of the well would be exposed to nearly impermeable shale, yielding no commercial quantities of natural gas.

The two interlocking solutions to this problem are horizontal drilling and hydrofracturing. The drillers have figured out how to steer the drill bit so that they can drill down to the shale and then sideways through the thin shale layer, exposing more of the well to the gas bearing rock. Then they open up cracks in the shale by pumping a mixture of water and sand into the well under extremely high pressure, forcing apart the rock and propping the cracks open with the sand. The increased permeability means that the natural gas comes flowing out of the well at a commercially viable rate.

Here's an animation of horizontal drilling, minus the hydrofracturing:

There are problems with this. It is expensive. The price for a thousand cubic feet of gas has to be up around $6 or $7 for the drillers to break even. Right now, due mostly to the economic downturn, it is floating around half that. Also, the wells are short lived. Where a traditional gas well might produce at a viable flow rate for years, a horizontally drilled and “fracked” shale well might only last months. Then the well has to be capped, the area remediated, the equipment transported to a new site, perhaps only a mile or two away, and the whole process started again. Each well is a big faucet on a small bucket.

Here I’ll quote a section of the interview by Steve Andrews of ASPO-USA (Association for the Study of Peak Oil) with Matt Simmons, from the April 20 Peak Oil Review:

Q: My last question: have you been surprised by the gas industry’s growth in shale gas?

Simmons: I’ve been surprised by the hype that assumes there’s been major growth in shale gas. I don’t think there has been any data of any reliability that proves we’ve actually had the growth in shale gas that we think we have.

Q: Some people here in the industry in Colorado are promoting it big time. They see it as a game changer. Couldn’t they be right?

Simmons: I’ve never seen the industry hype something crazier. Here are some numbers that I find enlightening. Of all the shale plays, the only one that we have significant production history on is the Barnett Shale. In the Haynesville, I think there are around 20 or 30 well-tests so far, and I don’t know that there are that many in the Marcellus. Consider these figures in the March 22 Barnett Shale Newsletter. It shows Barnett Shale total natural gas production by year, 1982 to 2008, all counties and fields in the Fort Worth Basin. In 2004—3890, then 4973, then 6542, then 9180, then finally 12104; and I thought, gee, we increased production X%, but then I realized that’s the number of wells! In 2008, we went to 4.8 Bcf a day, from 3.56 the year before—or up 1.24 Bcf/day. We’re looking for an increase of 8 Bcf, according to the EIA numbers, so the Barnett Shale did 1/6th of that.

Here’s another interesting set of numbers. All the big natural players have all now reported their results. The top 10 players increased their production in 2008 over 2007 to the tune of 685 mmcf/day. Unfortunately that was mostly offset by the top 10 gas decliners, led by ExxonMobil, BP, ConocoPhillips, Chevron, RoyalDutch/Shell, Marathon, Newfield, Hess, and they dropped 601 mmcf/day. So we netted out a plus 84 mmcf/day. Then you have about another 800 coming from about 40 individual reporting companies, but none of them are big enough—even if they tripled their production—to really make a difference. So that means that to match the growth that the EIA believes happened, then the residue—these hundreds and hundreds of mom-and-pop operators—would have to have grown their cumulative production twice as fast as the top 10, which obviously didn’t happen.

The EIA started reading the hype. And even though they probably have been puzzled that the number of gas wells completed went from 8,000 to 10,000 a year up to last year’s 33,000, and all we did was tread water for nine years. So right at the end of the year last year they started showing month-to-month growth year-over-year of 5%. Then in January they knocked their model up to 9%, so every month it was up 9%, year-over-year. They just knew, because they read the hype. We won’t have any real numbers until the states report what they collect, in the 3rd quarter of 2009. But I think we have the numbers in [from the companies] to say that we barely grew supply. Too bad we destroyed the industry.

Barnett Shale also has a production profile where peak initial production happens virtually when you come on stream, because of the way you frac the wells. By the end of the first year you’re down 70%.

Q: So you thing that the shale gas story is the most hyped story…

Simmons: It’s the most hyped play since Kashagan, which was later derisively called “Cash is gone.”

So what does this mean for you? For a while a lot of people were thinking that our natural gas troubles had been pushed out a few decades into the future by a glut of shale gas. 52% of American homes are heated by the stuff. Most of the peak period electricity that we use comes from natural gas fueled power plants. The retail price of electricity faithfully tracks the price of natural gas. It seems that happy days are not here again on the retail electricity front. The price will stay depressed for a while, but once the economy starts to pick up the supply will tighten. There will be a lag while exploration and drilling try to catch up. As I noted in a previous post, there is roughly a two-decade lag between the discovery of conventional natural gas and its peak production.

The other important thing to consider is that companies are going after this stuff at all.

A few years ago there was a big hoo-ha over a well in the Gulf of Mexico called Jack #2, drilled in 7000 feet of water and through 28,000 feet of rock, which produced 6,000 barrels a day. A huge expense and brilliant technical feat to get 0.03% of our daily needs.

The shale plays are similar. Gas companies are spending big dollars on complex processes to extract expensive gas from marginal sources. It means that all the easy, cheap stuff is gone. It may be futile. In the end, geology trumps technology. Or, as Wendell Berry wrote, “Nature bats last.” So don’t bank on cheap natural gas or cheap electricity five years down the road, whatever the hype.