November 6, 2017 § Leave a comment
Energy resiliency, especially in relatively isolated communities, can largely be achieved by local production and distribution. In the mid to low latitudes, solar intensity will favor solar electricity. And it is getting cheaper by the day. A recent winning tender for utility scale solar in India came in at around 3.6 cents per kWh. That is cheaper than many coal plants, certainly any newly constructed ones.
To really take advantage of solar electricity, note the fact that the electricity is output as DC. Conversion to AC, transmission, and then reconverting to DC at each device such as LED lights, computers and cell phones, is wasteful. Furthermore, useful equipment, such as fans and compressors, use less electricity for the same output, when running on DC. A DC powered “brushless motor” fan consumes between 40% and 70% less energy than one running on AC. Compressors are the workhorse of those two other common household appliances: refrigerators and air conditioners. However, these last two are currently not mass manufactured in DC use mode; they ought to be. Curiously, the latest refrigerators do use DC in the critical components, even though the input power is AC. DC fans are well on their way in India; a trade partnership could have them delivered here. For rural communities, DC powered well pumps exist, with dozens of manufacturers in India.
A possible architecture in a community could have the following features:
- Small solar farms attached to each development, commercial or residential. Since people love trees around the homes (especially in low to mid latitudes), and solar panels prefer absence thereof, rooftop solar is contraindicated. Furthermore, on-ground solar is lower cost to install and maintain, and can take advantage of tracking of the sun.
- DC microgrids to conduct the power to the users. For long distance transmission, AC is preferred. That is pretty much why Edison lost out to Westinghouse about a century ago. But for the short distance of a microgrid, DC works just fine. Preferably, the homes and establishments ought to be wired for both DC and AC, as are data centers today. The DC wiring would feed the current DC devices. Eventually, homes ought to convert to all DC devices. In the meantime, the AC portion would be fed from one single DC/AC converter at each home junction box, at relatively high efficiency. All this is compatible with grid power, which should increasingly be deemphasized. Again, in this instance we are discussing moderately or totally remote communities. A military base would qualify as well, for additional reasons of energy security.
- Community waste to biogas is simple to execute (landfills, animal waste or water treatment plants). The biogas can be used as fuel for many purposes, but also for generators with DC output.
In short, solar electricity, combined with a DC microgrid could serve the purpose of resiliency. At the same time, the proper use of the attributes of DC power could also cause less energy to be used for the same utility. This checks both the resiliency and energy efficiency boxes. Resiliency may be viewed as a measure to adapt to climate change. This approach, to a degree, simultaneously addresses mitigation.
September 8, 2017 § 1 Comment
A recent story discusses the impact of Hurricane Harvey on the availability of some common plastics. It points out that the hurricane has shut down production on the Gulf Coast sufficiently to impact availability of these materials well into November. They refer to derivatives of ethylene, in particular, polyethylene and PVC.
We have previously discussed in this forum, and in my 2015 book, the concentration of ethylene crackers in the Gulf area. The main point made then was the distance of the crackers from many of the ethane sources associated with shale gas. This distance has caused ethane pricing to be extremely low in consideration of its calorific value. In the book, I note that LyondellBasell grew substantially because they owned two crackers in the Midwest, and profited handsomely from the low local prices. More recently, ethane from Texas sources has fed plant expansion in existing plants near Houston. These are barely on stream. Then Harvey hit and shut many of these down. Incidentally, gasoline and diesel production also was impacted. This is evidenced by (Arab Embargo caused) 1970’s style lines at gas stations in Dallas.
The impact of Harvey on ethylene production underlines the risk associated with large concentrations of oil and gas refining, or any chemical industry for that matter, in storm prone areas. Distributed production of fuels and chemicals is a good idea for a variety of reasons. One is exemplified in the Harvey ethylene and gasoline situation. Another, more germane, is the location of conversion plants close to the raw material source. In the limit, pipelines are eliminated. Today, shale oil from the Permian is being hampered by lack of pipeline capacity. The spread between WTI and Brent is once again rearing its ugly head. It was squeezed when oil export was allowed.
The knee-jerk reaction would be to build more pipelines, fast. The more thoughtful action would be to permit and build small refineries proximal to the production. Shale oil is light, and mostly sweet (low sulfur). It can be refined in “simple” refineries; essentially distillation columns. The complications of cracking are not in play. Once financed, these can be built in two to three years, not very different from the time scale to enable pipelines. Fewer pipelines are better for local property owners, and for the environment. Local jobs will be created, and the prosperity will be distributed.
Shale oil, because it is light, always has associated gas. Expect a ramp up in gas production, possibly without enough pipeline capacity. Distributed conversion of this gas into chemicals such as methanol would be an alternative to pipelines. In some cases, new technology will be required, because small scale production of fuels and chemicals is disadvantaged by absence of economies of scale. A national network of manufacturing institutes (NNMI), a federal initiative, has one in this space, known as RAPID. The objective is process intensification, a means by which small scale processes can be economic.
The oil price scenario is playing out now. Shale oil caused the plummet in oil prices, beginning in late 2014. That 50% drop has substantially remained, almost three years later, with some ups and downs. The Saudis gambled on the demise of shale oil if the prices stayed low. Sure enough, according to the Economist, there were a hundred bankruptcies, and default on USD 70 billion in debt. But the industry is still alive, and fairly well. Part of the reason is the entrée of the big players such as ExxonMobil and Shell, into the Permian. The other reason is innovation to reduce the breakeven cost of production. Initially, the cost reduction came from service company discounts and operational efficiencies. Following a thinning out of service companies, those prices will rise. The key parameter is cost per barrel. The improvement can come either in reduced cost or increased production. Expect the latter to be the main player, through innovations increasing the percentage of oil in place recovered.
My crystal ball says that innovation will reduce breakeven costs below USD 40 per barrel and the industry will thrive. But oil prices will continue to stay low, in the consumer-friendly range USD 40 to 65 per barrel. If all of this comes to pass, expect US oil production to go up 3 million barrels per day by 2020 or so. That is a good 30% over current production. Associated gas will flow as well. Now is the time to challenge the orthodoxy in fuels and chemicals processing.
July 31, 2017 § Leave a comment
The proposed Atlantic Coast Pipeline (ACP) will be a deterrent to hydraulic fracturing in North Carolina, if completed. A recent report in the News and Observer discusses the merits of the ACP. Importantly, inexpensive natural gas from the north will create a disincentive to produce it in our state.
Shale gas has been singularly responsible for pulling this country out of the recession during the early part of this decade. The fact that our gas is up to a third in price to elsewhere in the world, has caused a manufacturing renaissance. That means jobs. More than half of the over $ 150 billion newly invested capital in chemical manufacturing has come from foreign companies, who are unable to compete by producing in their home countries. However, we here in North Carolina, have not seen the impact of that investment. In large part that is because we lack the natural gas. We could get it from production in our state, or we could have it piped down from up north. That second option is where the ATP comes in. It is certainly the better of the two options.
Could we safely produce shale gas in NC? In my view, yes, provided our state rules and regulations are followed. But, ought we to do so? I think not, based on a couple of factors. One is that NC deposits are not believed to be highly prospective. It will be hard to get responsible oil and gas operators interested when better pickings are available elsewhere. The second is that I expect natural gas prices to remain depressed for several years. This is bad for producers, but great for consumers.
In the NC portion, the pipeline diameter will be 36 inches, with a capacity of 1.5 billion cubic feet (bcf) per day. That is roughly how much a single liquefied natural gas (LNG) facility would use. So, clearly, there is no intent to use this as a lever for an LNG plant for export. This is all to the good, because I don’t consider east facing coastal LNG exports to be a good bet, especially with low oil prices out several years. The intended purposes are electricity production, consumer use through current distribution schemes, and other uses not yet planned. This last is enabled by the fact that this is an “open access” pipeline. The unspoken for capacity is another criticism leveled by some. On the other hand, it represents an opportunity.
I believe that the state ought to attract capital to build chemical plants using this gas. A good candidate would be ammonia plants. We still import (from other states and abroad) all our ammonia fertilizer. Together with our world class phosphate mine in Aurora, ammonium phosphate production and export could be feasible. Chemical plants of this sort principally employ two-year degree personnel. Our nationally acclaimed community college system could feed into that. And skilled jobs in the eastern part of the state would be welcomed.
The referenced N&O story mentions some push-back. One critic claims that Marcellus gas is depleting, implying that in a few years the ACP will run below capacity and not meet our needs. The Marcellus is one of the largest gas fields in the world, and these are early days in the exploitation. Furthermore, the Utica field may be larger yet, and the access is straightforward because it is directly underlying the Marcellus. There is considerable clamor to permit more LNG plants for gas export. Nobody is suggesting there will not be enough gas. As noted above, each of these LNG plants uses about the same amount of gas as the ACP. Which would you rather have, gas exports creating jobs elsewhere, or an Atlantic Coast Pipeline creating jobs in North Carolina?
Finally, for those folks who think hydraulic fracturing is a disease we ought not to contract in North Carolina, the ACP is the perfect inoculation.
June 27, 2017 § 2 Comments
In a recent story, Secretary Perry offered up the national imperative: “pave the path toward U.S. energy dominance”. President Trump has also used the rhetoric of dominance. In most settings, the word stands for a position of control. In energy, it could mean control of price and unfettered availability for domestic consumption. Perry especially cited oil, gas and coal, so we will restrict our discussion to the first two and consider where matters stand today, to appreciate possible new directions by the administration to achieve these goals.
First some editorial comment. Dominance is rarely desirable. The folks dominated hate you and will extract their pound of flesh somewhere. Energy independence is the next one down the line. This too is not desirable, because interdependence, especially with friendlies, is of value. Besides, as discussed below in the case of oil, it is more economically favorable than independence. Finally, there is energy security. This one is a solid yes. It translates into cost effective energy available when needed by the nation.
Shale gas has created a situation for the US that is not far from dominance, but not by design. The abundance, enabled by the technology of hydraulic fracturing, has caused the price in the US to be under USD 3 per MM BTU for years, and likely to remain under USD 5 several years out. The US is now an exporter of Liquefied Natural Gas (LNG) rather than an importer. This has led to a worldwide drop in gas price. A price controlling cartel led by Russia failed to materialize solely due to the US shale gas phenomenon. The US price continues to be half to a third of most places in the world. Domestic industries relying on natural gas are having a renaissance, compared to their competitors abroad. Effectively, US shale gas is controlling the world price, despite gas being a regional commodity. This walks and talks like dominance, albeit unintentional.
Prior to 2015, oil price was controlled by the OPEC cartel to be in the vicinity of USD 100 per barrel. The influx of shale oil caused the price of oil to plummet to about USD 50 within six months, beginning in late 2014. It has stayed down there since. The Saudis are credited with playing the high stakes gambit of not cutting production to prop up the price, with the intent of mortally wounding shale oil in the US. A hundred bankruptcies and default on USD 70 billion in debt notwithstanding, the industry is strong as ever. The resiliency was in part due to technical and operational innovation, and in part due to the presence of ready buyers. ExxonMobil, Shell, Chevron and ConocoPhillips have firm new footprints with an avowed intent of major investment, at the expense of costly forays, such as into the Arctic. A parenthetical point here is that the Trump reversal of the Obama era Arctic freeze (on new lease sales) has no net effect; the investment will not go there.
Shale oil can turn on (or off) a dime. A new well takes weeks to come on line, as opposed to years on offshore platforms. This response time allows shale oil to ride the waves of price fluctuation. Continued innovation will drop the breakeven well below USD 40 per barrel, and is already there for many prospects. Expect oil price to remain in the range USD 40 to 65 for years, with minor excursions. I predicted this very range in my 2015 book, and nothing has changed. We can safely conclude that shale oil is keeping the price of oil down in the range mentioned, despite OPEC desires. In effect, therefore, US shale oil is now the determinant of the world oil price. Not exactly dominance, but certainly a high degree of control.
Where does that leave this administration with respect to assuring “dominance”? Just don’t mess up a good thing. President Obama removed the oil export ban in December, 2015; this had been long overdue. This was crucial for the US energy economy because US light sweet shale oil was not best suited for US refineries. The discounted heavy oil from Canada, Mexico and Venezuela was preferred. The lift of the ban allowed export of shale oil, thus removing a domestic glut, and an associated oil price discount of WTI versus Brent. The steady state situation of high price shale oil export and low cost heavy oil import is a net positive for the economy. Buy low, sell high.
More recently, gas pipelines to Mexico are being augmented. This is a welcome development for the natural gas industry, still shackled by extremely low prices. Mexico, in turn, can key on oil, both offshore and onshore, rather than shale gas. Their conventional oil is increasingly getting heavier, and the US market is important. In return they are buying light shale oil from the US. All of this is important for the health of US energy production and US jobs. This administration ought to avoid doing anything to upset this relationship, such as rhetoric on the inadequacies of NAFTA. Pipelines are long term capital items. Capital investment is dissuaded by uncertainty.
With the unwitting control of price on both oil and natural gas, some may see us in a dominant position. But, more importantly, we can look forward to a North American self-sufficiency on oil and gas by about 2020. That assures energy security and should be the modified fossil energy goal for this administration, rather than dominance.
May 29, 2017 § 1 Comment
The Trump administration’s decision to sell half the holdings in the Strategic Petroleum Reserve (SPR) is the right step. The SPR was created following the Arab Oil Embargo in the early seventies. It is currently near capacity at about 685 million barrels. The intent had been primarily to guard against a disruption of imports.
The President of the US has the authority to add to, or subtract from, the Reserve without Congressional approval. But the stated reason for this draw down, revenue for the treasury, is debatable, not the least because this is not a piggy bank; withdrawals must serve a strategic purpose. Also, such a massive draw down is likely not in the spirit of the authority given, so Congressional approval may be prudent.
Not debatable is that the US is increasingly importing less oil and it is progressively traveling shorter distances to get to the US. Domestic oil is light and sweet. It is, by and large, not desirable to most of the domestic refineries, which make better profits from discounted heavy oil from Canada, Mexico and Venezuela. Consequently, imports from these neighbors combined with some export of domestic crude is a benefit to the nation. Certainly, light oil from the Middle East and Nigeria, is scarcely required. Our navy does not need to police the Strait of Hormuz, at least not for oil or gas supply reasons (ample shale gas has rendered import of LNG passé). Supply disruptions are much less likely from the close neighbors. About the only real risk is Venezuelan unrest. This combination of reasons justifies a smaller SPR.
But the best reason for a smaller SPR is the rapid response ability of shale oil production. Conventional offshore wells will produce oil 4 or more years after a decision to drill. For shale wells, that figure is a few weeks if the lease is on hand. This nimbleness of shale oil production is a reason why the industry has weathered the saw tooth price behavior of oil. Furthermore, a threatened shale oil industry, run largely by entrepreneurial independent producers, has responded with innovation to drive down the cost to produce. These reasons have conspired to defeat the Saudi gambit of leaving oil price down to freeze out shale oil.
In another twist, unique to shale oil, thousands of wells are drilled but not stimulated, known as DUC (drilled and uncompleted) wells. They wait for better prices. Around 5000 of these exist today. A DUC well can be stimulated and produced in a week in response to even short duration shifts in the price of oil. In fact, their very existence is a bearish influence on commodity traders. These act as buffers and a surrogate for the SPR. In fact, given the short time to production of even regular shale oil wells, all of shale oil still in the ground is the SPR. In my view the SPR could serve its purpose by being only a third of the current 685 million barrels.
I have previously opined that, in the face of the SPR not being needed at current levels, it could be accessed to exert political will or influence. A friendly, strategic, net importing nation could be provided the necessary technology to create the reserve (usually in salt caverns). Oil could be supplied from the SPR to fill this country’s new reserve. India, for example, could be enabled with a strategic reserve of 200 million barrels, more than enough for their purposes. The US would be paid for this in one form or the other. At today’s oil price, just north of USD 50, we even net a profit; the average acquisition cost of our SPR is close to USD 30. We get our treasury funds, and we potentially slow down India/Iran coziness in energy.
May 23, 2017 § Leave a comment
In a surprising decision, the US Senate voted to let stand the Obama era regulation curtailing methane related emissions from the oil and gas value chain. Much of the reaction has related to the political implications of the failure of a Trump supported reversal of an Obama administration action. My take is that, for once, the Senate acted in bipartisan fashion. Several senators on either side of the aisle were on the fence. In the end, Senator McCain’s statement probably best explains the action of the fence sitters. He released a statement:
“While I am concerned that the BLM rule may be onerous, passage of the resolution would have prevented the federal government, under any administration, from issuing a rule that is ‘similar’”
The key point he was making was that allowing the rule to stand still allowed it to be amended, whereas removing it would prevent any ‘similar’ rule from being attempted in the future. The current Secretary of the Interior was already on record as willing to encourage voluntary methane reduction by operators. So, the senator’s direction will very likely be followed. Besides, as discussed below, much of the mitigation of fugitive methane simply makes economic sense to the operators.
The rule was largely modeled on an existing rule in Colorado, and widely supported by the residents and the oil and gas operators there, who are credited with participating in the details. The federal action was, at least in part, premised on the fact that other states had not followed suit. Interestingly, the senator from Colorado ended up voting to remove the rule. Hmmm.
Two Democrats, Heidi Heitkamp of North Dakota and Joe Manchin III of West Virginia, had considered voting for repeal for similar reasons as Senator McCain, that it was not comfortable as written. Apparently, they were persuaded that changes would be forthcoming. The rule applies only to Bureau of Land Management (BLM) lands. But as a practical matter, if operators are going to act to limit emissions on BLM leases, transferring the technology to other leases would be simple, unless economically onerous.
The Environmental Defense Fund (EDF) is leading an effort on quantifying the nature of the problem and the means to solve it. The Department of Energy’s ARPA E unit launched the MONITOR program to create better means for detecting fugitive methane economically. Both these efforts are described in some measure in chapter 2 of my book: Sustainable Shale Oil and Gas: Analytical Chemistry, Geochemistry and Biochemistry Methods. The chapter also describes the principal findings of an EDF funded effort to quantify the distribution of fugitive emissions along the entire value chain from the well to the city gate and somewhat beyond. The data are a bit old now, but the takeaways are illustrative, nevertheless. Over 82% of the losses occur at under 20% of installations. Mitigation measures are advantaged by this concentration. They also conclude that 45% of the emissions can be captured with then current technologies in economic fashion. This could be accomplished by a net additional expenditure of USD 0.01 per thousand cubic feet (mcf) of gas produced. Even at the currently low natural gas prices in the vicinity of USD 3 per mcf, this is certainly economical. Of particular note is that they do take into account a credit for the sale of the natural gas captured. While reasonable, this is not realistic for leaks in the midstream pipeline infrastructure. Detection is also more problematic in the midstream. But some of the MONITOR projects do address that area as well.
There is a tendency to confuse methane releases with emissions from the flaring of natural gas. Both represent economic loss, but the first is more harmful to the environment because methane is about 25 times worse than carbon dioxide in the global warming impact. Many states have regulations covering the various sources of fugitive methane, including coal mining and agriculture. Colorado has a comprehensive one directed to oil and gas production. North Dakota has regulations requiring flaring to be curtailed. The vast bulk of flaring is of gas associated with oil production, whereas the majority of methane releases are in the natural gas production and distribution infrastructure. In the US, gas production is more economically challenged than oil because the market price is lower (gas has regional pricing, unlike oil). This makes investment in mitigation more challenging. But, as the numbers quoted above show, much of this is still economical. Several technologies are in development, some currently available, to attack the problem of flared associated gas. Some of these are also described in the book referenced above.
Fugitive emissions of methane from various industrial sources, including coal mining and oil and gas production, must be targeted for economic and environmental reasons. But the regulations must be guided by the economic availability of detection and amelioration schemes.
April 11, 2017 § 1 Comment
Here we go again. Presidents making decisions that are largely symbolic in the face of economic realities. The latest is a report that President Trump will shortly issue an executive order to promote oil and gas exploration and production in the Arctic and Atlantic.
I had previously written that President Obama’s 11th hour decision to ban future sales of leases in the Arctic would have no net effect on the industry in the foreseeable future. His ban on the Atlantic coastal waters was more interesting, in that it stopped at approximately the North Carolina border with Virginia. Interesting, because previous exploration had shown potential in the North Carolina waters, more so than Virginia. I think some exploration is likely as a hedge, but actual development will await the sorting out of the true impact of shale oil, as discussed below.
The industry has gone through a secular change. Predicting oil price has proven even more tenuous than in the past. When conventional oil (as opposed to the more recent shale oil) was the only product, oil price prediction entailed understanding the development pipeline, usually years in duration, while factoring in political instability in the oil producing nations. Further assisting the crystal ballers was OPEC, which manipulated prices to remain in the vicinity of USD 100 per barrel. Since about 2015 all that has gone out of the window. Shale oil in the US caused a halving and it has been seesawing around USD 45 ever since. What the future bears depends on the source. In the past, there had always been the outlier analyst predicting USD 200 or some such. But the consensus was in the low one hundred region. Now we have polar opposite predictions regarding supply and demand from the likes of Goldman Sachs and Morgan Stanley. Sort of the definition of uncertainty. Not the best climate for long term investment. More on that below.
Sustained low prices decimated the ranks of the shale oil producers, resulting in 100 bankruptcies and default on USD 70 bln in debt. But a new force has emerged. Major oil players with deep pockets, such as ExxonMobil and Royal Dutch Shell, have taken large positions. More importantly, those two plus Chevron are committing to USD 7 bln investment in 2017 (some estimates are up to 10 bln.) in shale plays, primarily in the Permian Basin. This is a giant leap from before, when the emphasis was on offshore development. This comes shortly after the Shell announcement of withdrawal from the Arctic “for the foreseeable future”. This withdrawal is from continued development of existing leases. That would appear to indicate a disinterest in any more leases in auctions, enabled by the reported President Trump order. In fairness, that does not necessarily follow. Even if they are backing off on development offshore, new leases will still be bought as hedges. This is evident from the recent robust lease sales in the Gulf of Mexico. This is in the relatively benign environment of the Outer Continental Shelf (OCS). But an Alaska lease is a horse of a different color. The costs and environmental risks are much higher and the time to first oil (forget gas; that is even more in the doldrums of price than oil) is double that in the OCS.
Uncertainty, with concomitant higher discount rates, particularly hurts long term plays. By contrast, shale oil plays are short term in the extreme. Due to the steep decline rates, new wells must be drilled to keep up the production. These wells take a couple of weeks, not years. When the prices drop, drilling can be curtailed and then picked up at the drop of the proverbial hat. This flexibility is a key to the resilience that shale oil has shown to saw tooth prices. Furthermore, breakeven costs have dropped dramatically. At first these were due to steep service company discounts, which in turn caused bankruptcies among the smaller players. The big boys will inevitably raise prices, especially now with the reduced competition. But the industry is seeing genuine technology advances dropping costs even in the face of the upcoming service price increases. These advances will continue. A Shell spokesman recently stated that they were profitable in the Permian at USD 40 and that “newer wells” were profitable at USD 20. There is little doubt the industry is “high grading” their prospects: mostly just the most productive areas are being exploited. I think that is sustainable until additional technology driven cost reductions bring the lesser prospects back into play in roughly the three to five-year time frame.
The foregoing arguments underline the point that with oil companies likely struggling to pay their dividends in a low-price scenario, shale oil is a good bet. Expensive forays into the Arctic with long term payouts will be off the table in the foreseeable future. Presidential actions on leasing are mere tempests in the Arctic teapot.