It’s gas, not renewables, that is pushing up electricity prices, report finds by Peter Martin, July 14, 2017,
The future of energy in Australia Coal has dominated the National Energy Market, but the closure of Hazelwood power station heralds a potential transition to renewables.
From July 1, Sydney prices climbed 15 to 20 per cent, Adelaide prices 16 to 20 per cent, and Canberra prices 19 per cent. Melbourne prices rise on January 1. After introduction of the carbon tax in 2012, prices jumped 19.3 per cent in Sydney and 23 per cent in Melbourne.
“When the rises flow through, retail prices will be the highest ever in real as well as nominal terms,” writes Australian National University specialist Hugh Saddler in a report to be released on Thursday by the Australia Institute.
Graphing the price movements for South Australia, the state with the highest proportion of wind energy, against its reliance on wind energy, Dr Saddler finds “absolutely no relationship between the two”.
South Australian wholesale prices have moved both down and up as the share of wind power grew to 45 per cent. Ahead of the latest increase, real prices in South Australia were lower than they were a decade earlier when the share of wind generators was only 5 per cent.
“More detailed analysis shows that market wholesale prices are consistently lower when there is a high level of wind generation, than when there is little wind. Over the past four or five years in the South Australia wholesale market, volume weighted prices received by wind generators have been around 20 to 30 per cent lower than volume weighted average prices for the market as a whole.”
“Higher wholesale electricity prices, and hence higher retail prices are almost entirely caused by higher gas prices,” Dr Saddler concludes.
“A similar, though less stark effect is seen in the other mainland national energy market states. This is not a malfunction of the market, but precisely how it was expected to operate.”
“The launch of the market in 1998 was followed by a rush of construction of gas turbine power stations in Queensland, NSW and Victoria and even in Tasmania, accelerated in Queensland by a gas generation mandate policy introduced by the state Labor government.
“It was envisaged that both the much lower greenhouse gas emissions and the superior operational flexibility of these power stations compared with coal would make them ideally suited to supplying hour-to-hour and day-to-day variations in demand for electricity, while also reducing emissions, by using a then relatively low cost source of fuel.”
Gas is is used to augment other supplies at times of peak demand, meaning that although most electricity is supplied by coal, it is the price of gas-fired power that determines the final price when prices climb.
The price rose sharply from 2015 with the opening of three gas liquification plants at Gladstone in Queensland, allowing the bulk export of gas previously supplied only to the Australian market.
“It seems that the decision to allow so much of the gas resources of eastern Australia to be exported was made without considering the likely effects on the electricity market,” Dr Saddler writes. “Household and business consumers of electricity are now paying the price.”
In June Prime Minister Malcolm Turnbull announced plans to impose export controls to try and guarantee supply and hold back prices. [Ha, fat chance of that. Emphasis added]
As Fracking Firms Struggle To Stay Afloat, Big Banks Turn Their Backs, Fracking companies in Britain admit they are “suffering” and struggling to secure finance by Richard Anderson, July 14, 2017, Mint Press News
Fracking companies in Britain privately admit they are “suffering” and struggling to secure finance, according to government documents obtained via freedom of information.
In a meeting last May with then-business minister Anna Soubry, the Onshore Energy Services Group (OESG) said raising the money needed to develop a wide-scale fracking infrastructure was proving difficult.
“Industry are finding it a challenge to get support from British banks… all funding, therefore, comes from overseas and self-growth,” the group said, according to the government’s minutes of the meeting.
“British banks are saying the companies are too small.”
The documents were released just weeks after leading UK shale explorer Cuadrilla posted multi million pound losses for the third year running.
The trade association, which represents small and medium-sized oil and gas companies [SMEs] in Britain, also raised concerns that if fracking takes off, supply chain companies won’t be ready to provide the equipment needed to build the infrastructure to support the industry.
It told the government that “incremental gains” will be made in making individual fracking sites operational, but that the “social license will be more important when this industry scales up”.
In other words, getting public support will be key.
“We will go nowhere if [companies] are fought at each stage,” the group said.
Russell Scott @RussellScott1
Fracking firms ‘struggling’ & feel ‘beaten up’ say the OESG in a meeting with DBEIS ministers. + struggling with finance from british banks
11:33 AM – 6 Jul 2017
The OESG also expressed concern about delays in drilling exploratory wells, and the knock-on effects: “Operators are struggling, [it’s] taking so long for them to get off the ground that SMEs are suffering.”
The meeting’s minutes, obtained by fracking researcher Russell Scott, suggests that Barclays London refused an industry player’s loan request, forcing them to approach Barclays Kenya — at a higher interest rate.
Barclays in London said it was unable to comment on specific loan requests, not least because the name of the individual company asking for finance is unknown.
The bank is in the process of selling its stake in fracking company Third Energy, simply saying that this investment is no longer part of its “core business strategy”.
It has released a specific statement on fracking, emphasizing that if done properly, the process poses minimal risks.
However, the bank’s Environmental and Social Risk Briefing, which outlines its overall approach to lending, says “significant environmental concerns have emerged regarding the hydraulic fracturing of shale rock”, highlighting in particular heavy water use and the possibility of methane leaks.
UK Finance, formerly the British Bankers Association and the body that represents the UK banking sector, declined to comment on banks’ policies on lending to the fracking industry.
Energy expert Professor Paul Stevens, Distinguished Fellow at the Chatham House think tank, said that financing is key to fracking in the UK: “This is a very important point. It’s why the US has had a shale revolution, because the banks were willing and happy to lend to frackers.
“The US revolution was based on Mama and Papa companies that were extremely reliant on access to credit.
“Without access to finance, fracking is simply not going to happen in the UK.”
However, he said it was the public’s view on fracking that would ultimately decide its fate.
OESG members were “absolutely right” to focus on public opposition, he said.
“Irrespective of the pros and cons of fracking, and I’ve never been convinced it’s as bad as the NGOs say, they have convinced the world [that fracking is dangerous], and nothing is going to change that.
“The shale industry is never going to take off because of public opposition”.
When contacted by Energydesk to discuss the views expressed by its members at its meeting with Anna Soubry, the OESG said it was unable to respond in time.
The meeting was held on 15 May 2016. The members of the OESG present were Remsol, Clear Solutions International, Moorhouse Drilling and Completions, Ground Gas Solutions, atg UV Technology, PR Marriott Drilling, Zetland Group and FBG. [Emphasis added]
Fracking firms struggling to raise money from UK banks amid environment protests, ‘Fracking is a failed industry in the UK. The sooner our Government acknowledges that and throws its weight behind the booming renewable energy sector, the better for us all,’ says Greenpeace by Ian Johnston, July 14, 2017, The Guardian
Companies hoping to take part in the Government’s promised fracking “revolution” have been “finding it a challenge” to get finance from British banks.
According to minutes of a meeting between the industry and a Government minister, some firms were “struggling” or “suffering”.
They added that some conventional oil and gas projects had been “affected by protests as well”, according to the civil servant’s notes.
Environmental campaigners said the account of the meeting, obtained under freedom of information laws by an activist, showed that fracking was a “failed industry in the UK” and called for the Government to help the “booming renewable energy sector” instead.
While the meeting took place in May last year, one financial expert said banks’ reluctance to invest in fracking was likely because of public’s generally negative view of the controversial process, suggesting this may still be a problem.
Environmentalists are mainly opposed to fracking because it opens up a new source of fossil fuels, but there have also been concerns about earthquakes and pollution of groundwater and the air. Fracking involves sending a mixture of water and chemicals down a well at high pressure to fracture shale rock and release gas or oil contained inside. A study this week showed that treated wastewater from fracking plants in the US still contained significant levels of radioactive material.
The minutes showed that medium-sized companies with perhaps 200 employees – mostly involved in the oil and gas supply chain who want to get into the shale gas sector – were finding things difficult.
“Operators are struggling – taking so long for them to get off the ground that SMEs are suffering,” the document said.
“Traditionally 10 to 15 wells are drilled a year and this year only four were drilled. Noted conventional oil and gas work has been affected by protests as well.
“Industry are finding it a challenge to get support from British banks … all funding therefore comes from overseas and self-growth.
“They have looked at equity but don’t want to dilute the companies. British banks are saying the companies are too small. For example, Barclays London said no so approached Barclays Kenya and paid a premium for this. Other financing issues concerned potential work in Russia and Iran.”
The Conservative manifesto spoke of hoping to create a fracking “revolution” in the UK, with hopes of similar economic effects produced by the boom in the US. However it added that this would only happen “if we maintain public confidence in the process, if we uphold our rigorous environmental protections, and if we ensure the proceeds of the wealth generated by shale energy are shared with the communities affected”.
Anna Soubry, the then business minister who attended the meeting with industry body Onshore Energy Service Group (OESG) and several firms, opened the discussion by saying she was a “big fan of shale”, according to the document.
Professor Paul Stevens, an energy expert at the Chatham House think tank, told Greenpeace Energydesk, that fracking’s poor image was a problem.
“Without access to finance, fracking is simply not going to happen in the UK,” he said. [Emphasis added]
Shale gas is not a revolution. It’s just another play with a somewhat higher cost structure but larger resource base than conventional gas.
The marginal cost of shale gas production is $4/mmBtu despite popular but incorrect narratives that it is lower. The average spot price of gas has been $3.77 since shale gas became the sustaining factor in U.S. supply (2009-2017). Medium-term prices should logically average about $4/mmBtu.
A crucial consideration going forward, however, will be the availability of capital. Credit markets have been willing to support unprofitable shale gas drilling since the 2008 Financial Collapse. If that support continues, medium-term prices for gas may be lower, perhaps in the $3.25/mmBtu range. The average spot price for the last 7 months has been $3.13.
Gas supply models over the last 50 years have been consistently wrong. Over that period, experts all agreed that existing conditions of abundance or scarcity would define the foreseeable future. That led to billions of dollars of wasted investment on LNG import facilities.
Today, most experts assume that gas abundance and low price will define the next several decades because of shale gas. This had led to massive investment in LNG export facilities. Both the assumption and its investment corollary should be carefully examined through the lens of history.
The Lens of History
The last 40 years have been characterized by two periods of normal gas supply, and two periods of gas-resource scarcity. Supply was tight from 1980 through 1986, and gas prices averaged $5.57/mmBtu (all values in this report are in April 2017 dollars) (Figure 1). Normal supply was restored from 1987 through 1999, and gas prices averaged $3.24/mmBtu.
Scarcity returned from 2000 through 2008, and prices averaged $7.72/mmBtu. Shale gas production began with the Barnett Shale in the 1990s. Development of other shale gas plays culminating in the giant Marcellus completed the return to normal supply. Prices since 2009 have averaged $3.77/mmBtu.
Because prices fell about 50 percent with growth of shale gas production, many assume that shale gas is low-cost. That is only true compared with the preceding period of high prices that resulted from resource scarcity, but not compared with conventional gas prices during periods of normal supply.
The 40-year average gas price since 1976 has been $4.70/mmBtu. Excluding periods of resource scarcity, it has been $3.40. The average cost of conventional gas from 1987-2000 was $3.42/mmBtu. During the period of shale gas supply dominance (2009-2017), prices have averaged $3.77 (Figure 2).
Gas Supply Models Consistently Wrong and LNG The Wrong Solution
The lesson from history is that U.S. gas supply is highly uncertain. Normal supply characterized 60 percent of the period since 1976, but scarcity characterized the remaining 40 percent. During each episode of either normal or tight supply, experts agreed that existing conditions would define the long-term. They were consistently wrong.
Cheap, regulated natural gas was abundant in the 1950s and 1960s, and most analysts believed that this would be the case for decades. Abundance and low price led to demand growth of 283 percent (45 bcf/d) between 1950 and 1972 (Figure 3).
Figure 3. U.S. Gas Models Have Been Consistently Wrong For 50 Years. Source: EIA, U.S. Dept. of Labor Statistics and Labyrinth Consulting Services, Inc.
Supply could not keep pace and there were acute shortages of gas during the winter of 1970. By 1977, shortages had grown to crisis proportions. Few saw this coming partly because of incorrect reserve estimates.
Experts agreed that scarcity would be the case for decades and that imported LNG was the only solution. Four LNG import terminals were built between 1971 and 1980. Limited gas supply led to a golden age of nuclear and coal-fired power plants that largely re-balanced the electricity market. Government subsidies and tax credits provided incentives to evaluate shale gas and coal-bed methane as alternative sources of natural gas.
The 1980s and 1990s were a period of great stability in natural gas prices. Increased pipeline imports from Canada gave the false impression that, once again, there was cheap and abundant natural gas for decades to come. All LNG plants were closed and some were used for gas storage.
Amendments to the Clean Air Act in 1990 caused many power plants to switch to natural gas to replace coal. Demand for natural gas increased 40 percent (15 bcf/d) but production did not keep pace with demand growth despite increased gas-directed drilling.
Canadian and U.S. gas production peaked in 2001 and by 2003, LNG import terminals were re-opened and capacity was expanded. More than 42 additional import facilities were proposed between 2001-2006. Seven were built. Experts agreed that LNG import was, once again, the only solution to the gas-supply problem.
The first long-lateral horizontal wells were drilled in the Barnett Shale in 2003. By late 2006, shale gas production in the Barnett, Fayetteville and other shale gas plays exceeded 4 bcf/d and confounded not only the U.S. LNG import market but also the global LNG industry that had planned on the U.S. being the market of last resort.
In every supply cycle, major investments in LNG were either undertaken or abandoned. Total installed LNG import capacity reached 18.7 bcf/d but imports averaged only 1.3 bcf/d from 2000-2008 and never exceeded 2.1 bcf/d. That’s an average utilization of 7 percent and a maximum of 11 percent. The original cost for the terminals was approximately $18 billion. How could industry analysts, company executives and investors get things so wrong?
Now, experts agree that, because of production from shale, gas will be abundant and cheap forever. LNG exports began in early 2016, and the U.S. became a net exporter of gas in April 2017. Seven previously failed import facilities are being converted for LNG export at an anticipated cost of approximately $48 billion. Three other export terminals have been approved by the Department of Energy (Figure 4) and applications for a total of 42 export terminals and capacity expansions have been approved.
The total of approved export applications amounts to more than 54 bcf/d—75 percent of U.S. dry gas production. Daily U.S. dry gas production in 2016 was 72 bcf/d. Are we repeating the mistakes of LNG import in reverse?
The Natural Gas Act (1938) states that the Department of Energy should approve an application unless “the proposed exportation or importation will not be consistent with the public interest.” It is, therefore, not a question of whether or not to regulate but rather, how to regulate in the public interest.
Approving LNG export applications for 75 percent of U.S. production does not seem to be in the public interest from either a supply security or gas price standpoint. [And how, just ask Australia! BC, are you paying attention?]
Shale Gas Marginal Cost
Shale gas producers have been making exaggerated claims about low-cost supply for so long that markets now believe them. Sell-side analysts routinely gush about sub-$3 break-even prices despite corporate income statements and balance sheets that show otherwise.
Marcellus leaders Cabot, Range and Antero spent an average of $1.43 for every dollar they earned in 2016; Chesapeake had negative earnings for the year—it couldn’t even pay for operating expenses out of revenues before capital expenditures and other costs.
The bearish scenario will be disastrous for producers whose share prices have fallen nearly 30 percent already in 2017 (Figure 7). Although investors have been willing to fund the unprofitable efforts of these companies for many years, I suspect that their patience is wearing about as thin as it has lately for tight oil.
Figure 7. Natural Gas Equity Shares Have Fallen 29 percent Since January 2017. Source: Google Finance and Labyrinth Consulting Services, Inc.
Some analysts incorrectly believe that shale gas producers have already pushed costs so low through technology and efficiency innovation that sub-$3 gas prices will become the new normal. Although it is true that costs have fallen substantially, than because of deflationary pricing by the service industry and less because of technology and innovation.
In fact, the technology that enables unconventional oil and gas production resulted in a 4-fold increase in oil and gas drilling costs from 2003 to 2014 (Figure 8). Depressed demand since 2014 has resulted in a 45 percent reduction in drilling costs and this accounts for most savings.
Figure 8. The Cost of Drilling Oil and Gas Wells Fell 45 percent After The Oil-Price Collapse. Unconventional Plays Resulted in a 4-fold Increase in Drilling Costs. Source: U.S. Federal Reserve Bank, EIA and Labyrinth Consulting Services, Inc.
I have little doubt that there will be downward pressure on gas prices in the near term but do not see how sub-$3 prices can become the new normal. Producers have send-or-pay agreements with the pipelines that will carry new supply from the Marcellus and Utica plays. Some of these projects will probably deliver gas to Canada and LNG export markets having limited effect on domestic supply. Similarly, much future Permian basin gas will likely go to Mexico. New supply from the Marcellus and Utica plays will inevitably force gas from higher cost plays out of the market.
New volumes that enter the domestic market must first overcome the present supply deficit (Figure 9). Gas production fell more than 4 bcf/d from February 2016 to January 2017. EIA forecasts that production will increase 4.7 bcf/d in 2017 but only 1.9 bcf/d in 2018. EIA anticipates monthly average prices above $3.00 in 2018 ending the year at $3.66/mmBtu.
Figure 9. EIA Forecast: Supply Deficit & Prices Rising to $3.66 By December 2018. Source: EIA June 2017 STEO and Labyrinth Consulting Services, Inc.
This is only a forecast and certainly incorrect in its details but EIA’s domestic gas forecasts have been notionally reliable over the past several years. Increased consumption and exports should keep supplies relatively tight, and prices reasonably strong.
Broadcast The Boom Boom Boom and Make ‘Em All Dance To It
Since the early 2000s, producers and analysts have proclaimed that shale gas is a “game-changing,” end of history-type phenomenon. From now on, natural gas will be abundant and cheap. The United States was running out of natural gas before 2009 but now can afford to export to the world. We were lost but now are found.
In late March, Morgan Stanley analysts wrote that Haynesville Shale “break-evens now sit comfortably below $3/MMBtu” and Marcellus-Utica “break-evens range from $1.50 to $2.50/MMBtu.” Yet, with average gas prices above $3 for the last 7 months, none of that good news can be found in the balance sheets and income statements of the main producers in those plays.
Shale gas companies spent an average of $1.42 for every dollar they earned in the first quarter of 2017 (Figure 10). That average excludes Gulfport and Chesapeake whose capital expenditure-to-cash flow ratio was 10.7 and 5.4, respectively. Including those two operators, companies spent $2.12 for every dollar they earned. It doesn’t seem like even $3 gas is working very well.
Figure 10. Shale Gas Companies Spent $1.42 For Every Dollar Earned in Q1 2017 Excluding Gulfport and Chesapeake; $2.12 for Every Dollar Including Gulfport and Chesapeake. Source: Google Finance and Labyrinth Consulting Services, Inc.
Bernstein Research published a report in May (“Inventory a plenty in Appalachia- we estimate at least 20 years of drilling remain”) that predicted 19-37 years of Marcellus-Utica “inventory at a steady-state production profile of 36 Bcfd”—current production is about 24 bcf/d. I know of no other oil or gas field in the history of the world with a trajectory of increasing production for so long.
That’s because Bernstein has made a technically recoverable resource estimate with quite optimistic spacing assumptions.* The report does not tell us anything about gas volumes that are commercial to produce at a some gas price.
To place this and other sell-side reports in context, I re-visited the Bureau of Economic Geology’s (BEG) production forecast for the Barnett Shale published in 2013. The BEG study determined individual well reserves and economics for 15,000 Barnett wells at $4 gas prices.
Figure 11 shows that actual Barnett production (from Drilling Info) has fallen far short of the BEG forecast and will probably result in much-reduced ultimate recoveries. That is not because the BEG study was flawed but because gas prices have been lower than the $4/mmBtu price assumed in their forecast.
Figure 11. Comparison of Bureau of Economic Geology (BEG) Barnett Shale Production Forecast and Actual Barnett Production. Source: Bureau of Economic Geology, Drilling Info and Labyrinth Consulting Services, Inc.
If Barnett production varies so much from the BEG’s scrupulous analysis and forecast, how can we have confidence in less rigorous analyst reports that call for decades of cheap, abundant shale-gas supply?
The Barnett and Fayetteville shale plays are dead at current prices because their core areas have been fully developed. Rig counts reflect this unavoidable reality (Figure 12). Considerable resources remain but not at sub-$4 gas prices. The Marcellus and Utica will inevitably meet the same fate–all fields do. Higher marginal cost of production outside the core will result in more supply but will also require higher gas prices to develop and produce.
Figure 12. Barnett & Fayetteville Have Much Higher Marginal Costs Than Marcellus, Utica or Haynesville: Barnett-Fayetteville Core Areas Are Fully Developed. Source: EIA, Baker Hughes and Labyrinth Consulting Services, Inc.
Few analysts seem to consider the economics of shale gas as a limiting factor to output and, therefore, to supply. Perhaps they actually believe the phony economics that lead to supposed break-even prices for the Marcellus and Utica in the $1.50 to $2.00 range.
Most analysts believe that gas prices will collapse in early 2018 as new Marcellus and Utica pipelines bring new supply to market. That may be for the short term but evidence suggests that gas prices will recover and remain fairly strong over the medium term. After one of the mildest winters in history, gas prices remain in the $3.00/mmBtu range and comparative inventories have fallen for 3 consecutive weeks.
Production growth, rig count data and company balance sheets all indicate that the marginal cost of shale gas production is about $4/mmBtu. Yet, most analysts say it isn’t so. Gas supply and price models have been consistently wrong for 5 decades. Yet, this time it will be different. LNG import terminals were investment fiascos but LNG export will be a great success.
All ruling theories falter and are replaced by new paradigms. It is unlikely that shale gas will be an exception.
There are wildcards that might prolong the shale gas phenomenon. Increased associated gas from tight oil plays particularly in the Permian basin might provide a few more years of proxy shale gas supply. Today, much of that gas is flared to avoid tie-in and processing expenses. Almost 40 percent of current Permian gas goes to Mexico, and it is reasonable that more future Permian gas will be exported than face gas-on-gas competition in other regions of the U.S. In addition, optimistic forecasts for Permian gas assume $60/barrel oil prices that now seem increasingly unlikely.
Credit markets are another wildcard. Investors have been willing to look past evidence that shale gas is unprofitable. This is based largely on the expectation that negative cash flow is normal during field development and that profits will come later. The problem with this is that shale gas decline rates average about 30 percent and capital expenditures never end.
The lens of history places shale gas in its proper perspective. The plays are not lower-cost than conventional gas plays. They are only low-cost compared with higher prices that resulted from depletion of conventional gas plays in the early 2000s.
Shale gas is not a revolution but it bought the U.S. a decade or so of normal supply before facing another period of gas scarcity.
The plays are large but finite, and price matters. The industry has abandoned the early shale gas plays—the Barnett and Fayetteville—because their core areas are fully developed, and the cost to develop marginal resources is higher than it is in the core areas of the Marcellus and Utica plays.
Those newer plays will follow the same pattern of growth, peak and slow decline as the Barnett and Fayetteville, as all plays have in the long history of the oil and gas industry. The idea that shale plays are somehow different defies the well-established laws of earth physics and depletion.
The shale gas story claims success based on resource size but not reserves. It emphasizes production volumes but not the cost of that production. Its champions focus on the technology that makes the plays possible but not the cost of that technology. Break-even prices are discussed rather than profits because the plays are not profitable. No smart investor puts his money in break-even projects anyway. When economics are addressed, analysts and industry exclude important expenses that we are told are sunk and can, therefore, be ignored.
The shale gas story is accepted because it paints a picture that fulfills aspirations of American energy independence, re-emerging political strength, and economic growth.
If the story is repeated enough, maybe it will become true.
Broadcast the boom, boom, boom and make ’em all dance to it.*
*Bernstein considers 100-acre spacing conservative. Assumed average-well EUR of 17 bcf suggests a much larger drainage area to me and, therefore, full development at a much lower well density than 100-acres per well.
*Lorde, “At The Louvre.”