168 thoughts to “Texas Update- January 2017”

    2. Saudi Aramco’s oil reserves confirmed by external audit: sources

      Jan 27, 2017
      http://www.reuters.com/article/saudi-aramco-reserves-idUSL5N1FH2YM

      The first independent audit of Saudi Aramco’s oil reserves has confirmed the state oil company’s own figures, sources familiar with the situation said, ahead of its planned share market listing next year.
      The listing, expected to be the world’s biggest initial public offering (IPO), is a centerpiece of a Saudi Arabian government plan to transform the country by enticing investment and diversifying the economy away from oil.
      Based on a figure of 265 billion barrels, Aramco’s fields contain about 15 percent of the world’s proven reserves. Any finding that the reserves are significantly above or below that could affect the company’s market value in the listing.
      “The independent audit produced no surprises,” a source familiar with the situation said on Friday. “Aramco’s reserves have always been reported internally in line with international practice.”
      Aramco had asked two U.S. oil reserve auditing specialists to review its deposits.
      These are Gaffney, Cline and Associates, part of Baker Hughes and Dallas-based DeGolyer and MacNaughton. DeGolyer and MacNaughton completed its audit last year, two of the sources said.
      Aramco and DeGolyer could not be reached for immediate comment on Friday. Gaffney Cline also could not be reached for immediate comment.
      Saudi Arabia’s proven oil reserves have been listed at about 265 billion barrels in oil industry reference publications such as the BP Statistical Review of World Energy for many years.
      Aramco said its crude oil and condensate reserves were 261.1 billion barrels in its 2015 annual report.
      The reserves audit produced figures “definitely not below” those published by Aramco, a second source familiar with the matter said, while a third source said the auditing firm’s estimate was higher than Aramco’s own.
      The IPO plan is being championed by Deputy Crown Prince Mohammed bin Salman, who oversees energy and economic policy in the world’s top oil-exporting country.
      Prince Mohammed has said he expects the IPO, which will offer up to five percent of the company, to value Aramco at a minimum of $2 trillion.
      Senior oil industry figures have welcomed the Aramco IPO for casting more light on Saudi Arabia’s oil reserves. Many of the world’s biggest sovereign reserves holders have not changed their numbers for years.
      The head of Russian oil company Rosneft Igor Sechin said last year the Aramco listing would give transparency over reserves data which had not been updated for 30 years.

      1. So they report about 250-260 billion barrels of reserves during 30 years with no real new discovery and now and external independent audit confirm 265 billion barrels. What does it mean?

        1. A cynic would say: he who pays the Piper calls the tune.

          Seriously, I would wait for confirmation from other sources; and would like to see details on key fields.

          As such, there were numerous cases when reserve estimates for giant and very large fields were significantly revised upwards compared with initial estimates made 30-40 years ago. These include Prudhoe Bay, Samotlor, and many others. But I do not know fields whose reserves remained unchanged over decades, despite high production volumes.

          1. Yep, we do need to check the actual report. Pdvsa got a consultant to sign off on their reserves estimate in 2007 even though it was wrong.

        2. They probably have a spreadsheet with a list of the proven reserves in each region or something. At the bottom of the list there is a sum.

          The auditor checked to see it the sum was correct.

          Then the auditor would have checked to see who entered the value on each row, and what the source was. An important part of any audit is confirming that only those with proper authorization modify the data.

          A very energetic auditor would have gone back and checked to make sure the number entered in the spreadsheet is the same as the number in the source document.

          If all that checks you pass the audit. I seriously doubt any auditor would attempt to check the scientific validity or the geological accuracy of the source data.

          A naive image of auditing is that auditors check to see if the data is correct. In reality, auditors are there to make sure that proper procedures were used when the reports were compiled.

          1. Reserve audits are a bit more comprehensive. I’ve prepared packages for reserve audits, these have to include structure, lithology, gross pay, net pay, cross sections, interpreted well logs, fluid analysis, backup for recovery estimates, data on operating costs, facility descriptions, contractual arrangement summaries, as well as a run showing the reservoir will be commercial until reserves are recovered. Some packages include well production curves, reservoir pressures graphs and maps, core descriptions, reservoir model runs, and the reservoir model input deck.

            I’ve seen large field reserve audit packages take up to 500 gigabytes.

      2. At some point, the reserves do not matter. If SA really can produce 4 billion bbl/yr for 65 years, who cares?

        If you are an investor, looking at SA, you need at least a 20% discounted rate of return. So, $1,000 paid to you 20 years in the future has a NPV value of $26. So, I am not going to look out more than 20 years.

        Okay, for valuation, I will use 4 billion bbl/yr for 20 years – 80 billion bbl total. Suppose that you, as an investor, believes that the payment to YOU will be $10 for every barrel of oil that SA produces over the 20 years. Okay, $40 billion/yr, $800 billion in total. That income stream, discounted at 20% is worth today NPV $195 billion.

        With a price of oil that dipped below $30 twice in the last 10 years, does anybody really think that there is any way that they could pull off a major IPO even if they [supposedly] guaranteed you a $10/bbl payment over the next 20 years?

        Of course, they could produce an offering that projects $10/bbl to the “investor” class, but, only offer 10% of that interest to the public. The math would be the same, but the IPO would be looking for $19.5 billion.

        I absolutely, totally, without reservation do not agree with Nathaniel. But, [I think that he said that he was a math wiz] I would be curious of how much he would pay for such a “promised” revenue stream. I ask that, because I believe that he thinks, IIRC, that Exxon et al will be bankrupt by 2030. I inserted et al because, if Exxon is bankrupt, so is everyone else, in my opinion.

        I reserve the right to claim an age related handicap if I hit some wrong numbers on my HP calculator and do not have the figures correct. Apologies to Nathaniel if I misrepresented his prior thinking.

        1. What really matters is the kind of reserves.

          Is this estimates based on the good old “drill and pump”, or do you have to fire all modern methods of fluid injections etc. to squeeze out this amount?

          In the second case you won’t see much money, only oil.

        2. I’m not entirely sure how you were representing my prior thinking. 🙂

          Part of my thesis regarding ExxonMobil going bankrupt is that, long-term, demand reduction will exceed depletion rates, causing permanent low prices. Part of it is that demand will be rebalanced only when aircraft kerosene becomes the marginal product, which is a total demand of less than a third of current demand.

          But the final part of it is that ExxonMobil, like most of the IOCs, is NOT anywhere NEAR being the low-cost producer, and so will have to shut down as prices and volumes drop. Saudi Arabia actually is the low-cost producer so it’s in a somewhat different position.

          The IOCs used up their cheap Texas oil back in the 1950s when Hubbert’s original peak happened, and they’ve never got access to another field that cheap. Saudi Arabia still hasn’t used up their cheap oil.

          I would never invest in a Saudi revenue stream because it’s only as good as the government backing it and the risk of the government being overthrown and the new government revoking the contracts is *extremely* high.

          But, suppose that the revenue stream was coming from a more stable location, like, say, Abu Dhabi. Well, you still have to match it up with the demand model to figure out what it’s worth…

          P.S. In that description, I actually left out several parts of my thesis regarding ExxonMobil declaring bankruptcy; I only covered upstream operations. Another part is the necessary massive downsizing of refinery capacity, which will take place amid crushed refinery margins as capacity and price drop. Another part is the insistence on continuing to issue dividends in excess of current earnings, financed by debt.

          A final part is that at some point investors will get spooked by the debt-financed dividends and quarterly losses; there will be a series of debt rating downgrades, Exxon will be forced to slash the dividend, interest rates on new debt will rise, it will be impossible to issue equity without massively diluting the stockholders, and this will spiral into an inability to get financing. *That’s* when they declare bankruptcy.

  4. The EIA’s Monthly Energy Review just came out. They have November US production down 115,000 barrels per day in November and still down 19,000 barrels per day in December from October. November and December are estimates and, I thought, was based on the weekly production data. But this cannot be the case because the weekly data was considerably higher in November and December.

    1. And here is the weekly data for comparison. The weekly data is through week ending January 20, 2017. So the last three points are in 2017 and are not reflected in the Monthly Energy Review Data.

  5. Baker Hughes rig count for the week ended Jan. 27 is out.

    The US drilling rig count increased by 18 to 712 active units.
    The overall count has climbed 308 units (+76%) since the drilling rebound began after the week ended May 27, when it bottomed at 404 rigs.

    US oil-directed rigs added 15 units this week and now total 566, an increase of 250 (+79%) since the week ended May 27. Gas-directed rigs rose 3 units to 145, up 64 since Aug. 26.

    Onshore rigs jumped 19 units to 689. Three rigs halted operations offshore Louisiana, shrinking the overall US offshore count to 21.

    The number of horizontal rigs increased by 20 to 579 units this week, and is up 265 (+84%) since May 27.

    The Permian oil rig count jumped 10 units to 291, up 159 (+120%) since April 29.

    Eagle Ford added 6 oil rigs to now total 49, a 23-unit rise since June 10 (+88%).

    The Bakken gained 2 units to 37, up 15 (+68%) since June 3.

    Cana Woodford climbed 4 units to 49 oil rigs, up 25 (+104%) since June 24.

    DJ-Niobrara fell 3 units to 20, up 8 (+67%) since June 24.

    The overall rise continues to reflect a rebound in rigs targeting crude oil, drilling horizontally, and based in the Permian basin, and, to a lesser extent, other LTO plays. Permian now accounts for 53% of total U.S. active oil rigs.

    1. Can we assume based on this continuing increase of rigs that more drillers are finding profits at $50-ish WTI?

      1. Hess 2016 earnings at $43 WTI are not a good leading indicator of profits at $50 WTI.

        Hess has an enterprise value of $23 billion, yet estimates future cash flows, undiscounted, of just $33 billion in their 2015 10K, which excludes interest expense. Hess had to chop undiscounted future estimated production costs by $14 billion from 2014, to get to that $33 billion figure, Discounted at 10%, those cash flow’s present value are under $8 billion.

        By the end of the second week of March, all will have reported 2016 FY earnings and PV10. We shall see.

        BTW, please remember that diluting existing shareholders does decrease losses per share.

            1. Banks are now using PV9 due to low interest rates.

              There was a time where PV10 could be used as method for valuing production. Clearly, given current equity values in relation to PV10, it is no longer being utilized.

              However, banks continue to be required to use this method for valuing reserves for collateral purposes. Banks do not use SEC oil and gas values (which are trailing) but typically use the forward strips, with local adjustments for the specific project.

              In the past, we have had engineering performed in order to have a bank advise us what they would loan on our reserves.

              My point, as it has been for now over two years, is that almost none of the LTO companies are in a position to have only bank debt, unless they pay down debt via shareholder dilution, which many have done.

              For example, to pick on CLR yet again, this morning the company market cap is $18.5 billion. This is despite a PV10 slightly in excess of long term debt, about one billion, and almost no cash on the balance sheet, at $50.28 WTI in 2015. And, as I have said probably 100+ times, the 2015 PV10 was achieved only by cutting estimated future production costs from $26 billion to $10 billion year over year, 2014-2015.

            2. I doubt many here care about this, but to go over again:

              Public oil and gas companies are required to estimate future production, future production costs, future development costs, future income taxes and the resulting future cash flow.

              The resulting future cash flow number is then discounted by 10%, which results in PV10.

              I understand discounted future cash flows may not be easy to visualize, but maybe by showing undiscounted numbers, straight out of an SEC 10K, I can illustrate how drastic the oil and gas price crash affects these companies financially.

              Below is for Continental Resources.

              As of 12/31/2014, CLR estimated the following:

              Future oil production: 866,360,000 BO
              Future gas production: 2,908,386,000 mcf

              Future BOE production: 1,351,091,000 BOE

              Future oil and gas income: $90,867,459,000
              Future production costs: ($25,799,221,000)
              Future development costs: ($12,842,174,000)
              Future income taxes: ($13,800,737,000)
              Future net cash flow: $38,425,327,000

              As of 12/31/2015, CLR estimated the following:

              Future oil production: 700,514,000 BO
              Future gas production: 3,151,786,000 mcf

              Future BOE: 1,225,811,000 BOE

              Future oil and gas income: $36,551,672,000
              Future production costs: ($10,869,493,000)
              Future development costs: ($6,935,958,000)
              Future income taxes: ($3,717,612,000)
              Future net cash flows: $15,028,609,000

              Is it really reasonable to believe that, in just one year, CLR found a way to produce only 9% less BOE while cutting more than half (almost $21 billion) in production and development costs?

              If this was limited to one company, maybe no big deal. But this is industry wide from 2014 to 2015. I am awaiting 2016 10K to see how much more assumptions were cut.

              Just as no one has challenged me on my simple 36 and 60 month payout (or lack of payout) calculations, no one has challenged me on the net future cash flow/PV10 issues. But, no one is paying attention either apparently, given the current equity valuations of these companies. Hopefully that is because the “smart money” knows oil is headed much higher very soon?

            3. shallow sand,

              Investment banks’ analysts normally do not use future cash flow numbers calculated by oil companies themselves.
              They are use their own models with own assumptions on production volumes, prices, costs, capex, etc.

            4. AlexS.

              So the investment banks think companies are showing higher future costs than will be realized? Or maybe greatly understating future production?

              It has to be that and/or higher oil prices?

              Considering how much companies have slashed estimates of future costs, I have to assume the reason companies are trading at a very high multiple to SEC future cash flows is because it is assumed oil and gas prices will be much higher than the futures contacts are presently trading.

            5. Shallow, I care and I agree. Further, I don’t for one nano-second believe that banks have better INTEL on shale oil economics than shale oil operators themselves, most certainly not costs, be it CAPEX or OPEX. If they had a better handle on costs, they’d be jumping at the opportunity to default these bad loans and operate that junk themselves.

              Banks are using OPM also; they are chasing miniscule yields with no fear of failure. Every night before beddie-bye time both Grantor and Grantee get on their knees and pray for higher oil prices. That’s their only hope.

              I remain baffled by how few people analyzing the US LTO industry and willing to make predictions about the future, know so little about rudimentary well economics.

            6. Hi Mike,

              I agree. It seems the lack of profits should make this obvious to investment banks. I remain mystified that LTO wells continue to be drilled at $50/b.

              You and Shallow Sand seem to lack any rational explanations for the behavior of these LTO companies, with the exception that the CEOs are crooks essentially stealing people’s money until it all comes crashing down.

              Neither of you has said this explicitly that I remember, but the implication is fairly obvious.

            7. shallow sand,

              Discounted future net cash flows as presented in SEC fillings are calculated using standard rules and should not be viewed as projections.

              From CLR 2015 10K:

              “The standardized measure of discounted future net cash flows presented in the following table was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices, the costs in effect at December 31 of each year and a 10% discount factor. The Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.”

              Analysts are using their in-house oil price forecasts and are free to use their own assumptions on costs, taxes, interest rates, capex, etc.

              The accuracy of analysts’ forecasts may be good, mediocre, bad or very bad. My point is that they are not using future cash flow numbers from company fillings.

            8. Hi Dennis,

              If we would pin blame just on “crooked” LTO CEO’s we would miss bigger picture. There is more to it.
              Entire press coverage of Shale is simple: ignore economics, keep repeating the Shale narrative.
              There are no past or present analysis to engage in debate centered on economic evidence in any public forum. The main issue here is that so called “shale revolution tech” has morphed from one element of a larger business toolkit into a quasi-ideological/religious “movement” based on inherent virtues that the “non-tech” world lacks. Public is convinced itself that shale is the leader of progress and economic growth, and that “industry disruption” is virtuous regardless of actual impacts.
              There is no critical or objective thinking from anyone in the press, banks, oil industry itself (and forget about political body), but just cheerleading from the “Shale/US sideline”.

            9. AlexS. I understand your point. However, SEC estimates of future cash flows, if anything, are on the rosy side, at least from my limited personal experience in comparing them to actual financials, particular with regard to expense forecasts.

              I would really like to see the reserve reports themselves. One could then plug in different scenarios on pricing, expenses, etc.

              In any event, when a company has a standard measure PV10 of $6.8 billion, that does not include interest expense on $7 billion of debt, had to cut future production and development costs by $21 billion just to get that PV10 number, and yet is trading at a $18 billion market cap, it would seem at least someone besides us few would notice.

              SEC filings are supposed to be accurate.

            10. shallow sand,

              There is a lot of misinformation in shale companies’ presentations, but in case of discounted future cash flows reported in 10K fillings, all questions should be addressed to SEC, as oil companies are using SEC rules.

              Historical numbers in SEC filling are supposed to be accurate, but even there companies are using a lot of “innovative accounting”, particularly with regard to various non-cash items.

              Therefore, company financials for the past periods should be carefully analyzed; and future cash flow numbers under SEC rules are useless, in my view.

            11. Alex, I don’t recall the sec mandating how the OPEX line was to be estimated. I never allowed using a fixed cost per barrel in our internal reserve estimates. So I tended to have sec filing done with the same approach we had derived for our operations. This way the figures matched fairly well.

            12. Fernando,

              When I mentioned “innovative” accounting,
              I did primarily mean various non-cash items (such as write-downs, etc.), not cash operating costs.

  6. I think this is the future until supplies really do decline. This seems to me to be the dilemma facing the oil industry. It would appear that any increase in production just drops prices. Seems to me that all the political and investor talk about increasing production just hurts the industry, unless the goal is to attract investment money and loans without worrying if the funded companies can make any money.

    Oil prices fall as U.S. drillers add rigs | Reuters: “Oil prices slipped on Friday, extending losses after data suggested drilling is ramping up in the United States, prompting investor concern about how effective OPEC and other producers will be at supporting prices by cutting supplies.”

    1. Oil books biggest on-day loss in over a week – MarketWatch: “A report from the Energy Information Administration released Wednesday showed a weekly increase in crude supplies, along with a fourth-straight weekly jump in gasoline inventories on the back of sharply lower demand for the fuel. Total domestic crude production for the week also edged higher.

      Looking ahead for WTI oil on a technical basis, monthly momentum indicators show the ‘to be overbought as we near the end of this month, threatening a move to a long-term downtrend,’ said Darin Newsom, DTN senior analyst.”

    2. There are still at least 18 months to go before the pipeline of projects started in the high price period dries up. The are many large projects offshore Africa and Brazil due, plus smaller, but not insignificant, ones in the North Sea, also Kashegan Ph. II and Khurais expansion. GoM looks like the first area to have really slowed to a crawl – I don’t know of anything now until Stampede next year, but several projects are still ramping up.
      Russian projects ramp up over many years, I think this is mostly because of the nature of the fields but also partly because of pipeline limits (i.e. they can only increase flow as other fields decline to make room) although there was some news last year that a couple of major bottlenecks had been removed. Nevertheless there were a lot of big projects last year that are still on the rise and will have impact for a few years, but only smaller new ones this year and next. A couple of bigger ones in 2020 but again they take time to reach plateau. There has been commentary that they have increased in-fill drilling in their older fields to maintain production – that has to cease to be effective some time I guess.
      With the dearth of new conventional discoveries companies are stuck with the older and expensive projects that were at the back of the cue even with oil at $100 (including a lot of Tar Sands, which at the moment has political issues added on top of economics although a couple of smaller projects that were half finished have been restarted), or they try and find a way to make money and book reserves in Iraq and Iran, or they jump into the Permian, which seems to be the preferred option at the moment.
      So far there is not a lot of news indicating new FIDs for large projects – Chevron announced some pre-FEEDS in the GoM (that probably means plateau production is 8 years away), there is FEED on Liza, the one good recent oil find and that was always going to be fast tracked, I don’t think even Mad Dog is fully sanctioned although work is progressing. Also there seems an effort now, at least in the IOCs and larger independents, to pay down some debt – or at least not take so much on – in preference to take on huge development commitments, that could change with a really big price increase, but not so much with smaller increments.
      It’s early days in the reporting cycle but I think the supply cliff sometime in 2018/19 is looking likely to be steeper than I thought last year.

      1. “Russian projects ramp up over many years, I think this is mostly because of the nature of the fields but also partly because of pipeline limits (i.e. they can only increase flow as other fields decline to make room) although there was some news last year that a couple of major bottlenecks had been removed. ”

        There were no major bottlenecks, as pipelines are generally built in advance to be able to transport oil from new fields. That was the case of the ESPO pipeline system which is now exporting east-Siberian crude to the Asia-Pacific markets.

        This month, Transneft officially commissioned the Zapolyarye – Purpe and Kuyumba – Tayshet oil trunk pipelines. These projects are linking new fields in the Yamal-Nenets Autonomous District and Krasnoyarsk Region with resource potential standing at 2 billion tons of crude to the Russian system of oil trunk pipelines.
        Some of these fields have started commercial production in late 2016, others are due on stream in the next few years.

        http://www.en.transneft.ru/newsPress/view/id/14357

        A map of the Russian oil pipelines (which includes 2 new projects) can be seen here:
        http://www.en.transneft.ru/pipelines/

        You are right that most of new projects are ramping up gradually, reaching plateau output levels 3-4 years after the flow of first oil.

        Energy News posted a good chart for new Russian oil projects in the previous oil thread: http://peakoilbarrel.com/opec-december-production-data/#comment-593199

        The original source is BofA Merrill Lynch

        1. Alex, I did some planning and analysis work for Eastern Siberia, and we concluded the project óptimum was to drill development wells three years before the pipeline was completed. I believe the óptimum drilling schedule had an increasing number of rigs over time, which held flat after central plant and pipeline start up. Is this what they did???

      2. ExxonMobil country manager says Liza to flow at 100,000 b/d

        http://www.ogj.com/articles/2017/01/liza-to-flow-at-100-000-b-d-exxonmobil-official-says.html

        ExxonMobil Corp.’s giant Liza discovery offshore Guyana will have an average production of 100,000 b/d of oil when it begins flowing in 2020 according to the company’s Country Manager Jeff Simons. It also expects to produce 165 MMscfd of natural gas that will be mainly used for reinjection into the wells.
        Simmons said the company will use a floating production, storage, and offloading (FPSO) unit to produce the oil and would then export it, and raised the possibility of it being refined in nearby Trinidad and Tobago.
        He told that the company planned to drill 17 production wells with subsea tiebacks to the FPSO and that ExxonMobil was confident it could meet the early start up deadline because of its use of “cutting edge” technology.
        Simmons said no decision had been taken as of yet on whether ExxonMobil would use one or two drillships during the development stage.

        Asked if he thought that the company’s production out of the Starbroke block could increase with additional discoveries in the offing, Simmons was careful to point out that there was no certainty in exploration and pointed to the Skipjack prospect, which he said was a geological lookalike to Liza and turned up a dry hole.
        “Before drilling Liza our partner left us and we were looking for a new partner because we were not prepared to take the risk alone. Luckily we got Hess and Nexen and luckily we drilled Liza 1 before we drilled Shipjack, which, if you look at them, they look like a mirror image, and one was a massive find while the other failed. So I hope we will find more oil but I can only speak to what we know is there.” Simmons told the conference.
        Earlier this month ExxonMobil and its partners announced its Payara-1 well offshore Guyana as its second discovery on the Stabroek block. The Payara-1 well targeted similar aged reservoirs that were proven successful in the Liza discovery.
        The well encountered more than 95 ft of high-quality, oil-bearing sandstone reservoirs. It was drilled to 18,080 ft in 6,660 ft of water. The Payara field discovery is about 10 miles northwest of the Liza discovery.
        ExxonMobil also announced that in addition to the Payara discovery, appraisal drilling at Liza-3 identified an additional high-quality, deeper reservoir directly below Liza field, which is estimated to contain between 100-150 million boe.

        1. 100,000 is not a big production flow if they really have 1.4 Gb reserve – typically that would support 150,000 or more – wonder if they are thinking of a second production vessel later on.

          (p.s. That should be ‘queue’ not ‘cue’ above.)

          1. I think they could add a second FPSO, especially if they find more oil.

          2. Seems to me they are hedging, taking into account reservoir risk, timing to first production, rising oil prices over time, host country ability to absorb the cash flow, etc.

            Also, remember they stated they would be reinjecting gas. Those high pressure compressors are a bitch to install safely on an FPSO.

      3. I’ve found one Brazilian project that’s starting now (It’s in the subsalt field of Lapa, in the Santos basin, 100kb/day), does anyone remember what the others are?

        2016-Dec-20 Brazil’s state-run oil company Petroleo Brasileiro SA has started to pump oil and natural gas from the subsalt field of Lapa, in the Santos basin, the company said in a securities filing on Tuesday.
        Petrobras said its production vessel in the Lapa field, the FPSO Caraguatatuba, has the capacity to process 100,000 oil barrels per day. The company operates the area in partnership with BG E&P Brasil Ltda, a subsidiary of Royal Dutch Shell plc , and Repsol Sinopec Brasil SA.
        http://www.reuters.com/article/petrobras-production-idUSE4N19C02Q

        1. 2016 (I think 100 kbpd or 150 for each except the Libra pilot)
          Cepu Carioca
          Lapa – Santos (Cidade de Caroguatatuba)
          Libra Extended Well Test (EWT)
          Lula Alto (FPSO Cidade de Maricá),
          Lula Central (FPSO Cidade de Saquarema)

          2017 (I think all 150 kbpd)
          Lula/Iracema Norte Area (FPSO Cidade de Itaguaí)
          Lula/Iracema Sul Area (FPSO Cidade de Mangaratiba),
          Tartaruga Verde / Mestica

          No guarantees though, I might have missed something, things change each quarter with Petrobras and I don’t know Portuguese, though Google translate is pretty good with it.

          http://www.petrobras.com.br/en/about-us/strategy/business-and-management-plan/

      4. Hmmm. OK, supply cliff in 2018/19… but we don’t get the demand cliff until circa 2023….

        OK, we’ve got one more run-up in oil prices. One. 2020.

    3. “unless the goal is to attract investment money and loans without worrying if the funded companies can make any money.”
      Wasn’t that Aubrey McClendon’s goal?

  7. Gasoline prices may fall for another month as demand heads to 5-year low – MarketWatch: “U.S. demand for gasoline is on track to mark its lowest monthly level in five years, taking prices for the fuel down with it.

    For the first three weeks of this year, gasoline demand has stood at just 8.19 million barrels a day, or about 7.7% below the same period last year, said Tom Kloza, global head of energy analysis at the Oil Price Information Service.”

    “Nation has more than 30 days of gas supply, largest since 1995: OPIS.”

  8. Lots of good graphs in this article.

    Oil And Petroleum Product Inventories Worse Than Last Year | Oil News: “We examine the EIA data this past week, and it is interesting what a difference a year makes, psychologically speaking, as we have more inventories in across the board, yet we are almost double the price versus this time last year in $53 a barrel versus $26 a barrel. There is a lot of Fantasy Land thinking going on in financial markets right now.”

  9. I haven’t looked at this, but I just read some article summaries. Some people feel BP has consistently, year after year, underestimated renewable energy and EVs and that they have continued to do so in 2017.

    What I noted in the articles was that demand will slow because of more fuel efficient vehicles, but that a rising middle class in Asia would drive demand. There will be enough oil to meet the demand. By the early 2030s, most of the petroleum will be used for fabrics and plastics rather than fuel. The fastest-growing energy source will be renewables.

    BP Energy Outlook | Energy economics | BP Global

    2. Guy, you’re just delusional.

      I happened to be looking at Mary Tylrr Moore snippets the other day on youtube after she died. Right column listings were snippets of other shows of that era. One was thirtysomething.

      Clicked it and the character was talking about advertising cars and whether it was satisfying for liberals like themselves and how it would be better if it was for and I quote “electric cars and renewable energy”. Jaw drop.

      What was that show? 1980s? It’s been talked about for decades. It’s silliness. It’s not going to happen.

      1. It’s not going to happen.

        The only way it is not going to happen is if Trump et al. manage to destroy the planet before it does. In which case it won’t matter!

  10. Six of the eight top oil-pumping states hit recession

    America’s economy is looking solid overall these days, but depressed prices for domestic oil production tipped six of the eight biggest oil-pumping states into recession last year, according to a new report.

    As oil prices dipped as low as $27 a barrel at one point early last year before recovering, recession came to Alaska, Louisiana, New Mexico, North Dakota, Oklahoma and Wyoming, according to the S&P Global Ratings report.

    The report, illustrating the damaging effects of the global commodity’s slide on American energy, found that Texas and Montana barely avoided recession with slight increases in growth.

    Seven of the eight states ranked in the bottom 10 in job creation, with only Texas, at No. 23, escaping that dubious distinction. Employment opportunities, state budgets and economic growth have contracted, accordingly.

    photo Recession_zpsi6uuwge0.jpg

    1. It’s for this reason that Colorado has expanded its economy beyond extraction industries, and why it has to weigh land and water use for gas and oil against other needs like housing, agriculture, tourism, and so on. North Dakota’s boom and bust is something Colorado doesn’t need to emulate. There is drilling in the state, but oil and gas aren’t the primary drivers of the Colorado economy anymore.

    1. What caught my eye.

      “Chevron announced plans last month to curtail spending on drilling and other projects for a fourth straight year, a stark contrast to U.S. shale explorers who are responding to the uptick in crude prices with ambitious expansion plans.”

      “Despite the belt-tightening, Chevron is on pace to spend about $2 billion on shareholder dividends each quarter. That equates to about $1 million an hour. Bigger rival Exxon Mobil Corp. is set to disburse about $3.1 billion per quarter in payouts.”

      Now the last quote suggests that even though Chevron may be on the decline, its stock might be worth buying if you can earn enough in dividends.

      I think, though, that the big companies do see the handwriting on the wall, and the little companies may just be in it to get what money they can now, whether or not they make a profit or have a sustainable future.

      I’m alarmed at what the Trump administration is doing with its National Security Council, but I still wonder if those gas and oil appointees know the future and are making appropriate plans even if the public isn’t told.

        2. I have a high opinion of Fernando’s professional skills.

          But there are a few people in the industry, people with professional standing comparable to Tillerson’s , who know, and have said so. The prez or chief exec at Total said so a couple of years ago. Guys like Simmons the oil banker said so earlier.

          ( My personal opinion is that Simmons had the bad luck to have something happen in the medical line, a minor stroke, or maybe a tumor, that caused him to “lose it” the last year or two of his life. This sort of thing is quite common, as anybody who knows a lot of old people will attest. )

          Even semi literate backwoods loggers get it, when you discuss it with them. Said one I know at the local store where the working guys eat the deli lunch, a few days back:
          (paraphrased)

          Every year the timber that’s left is sorrier stuff than what I cut the year before. It’s in smaller tracts, and harder to get it out, and won’t saw out ( meaning yield good quality lumber) like it used to. And it’s going to get worse instead of better.

          And these working guys can and do understand that even when they are barely staying afloat, at the rates they’re getting paid when times are tough, they have to hang in there hoping for better times. If they give up, they won’t have assets enough left to get re established when things turn around.

          The little guys who used to run the independent hardware stores know all about price wars, and are quick to tell you how fast the big box stores that stocked just the fastest moving items put them out of business,and then raised the prices on those items.

          Everybody who bothers to THINK understands that peak oil is a when question. But Fernando’s right, calling the people chimps. Most people would rather DIE than think.

          1. OFM:

            Your comment about lumber reminded me of the words of a contractor in 2000 when I built my shop. He said they were building now with the wood that they used to throw away. That really rang true to me when I saw the roof trusses compared to the ones in my house (built in 1979). I was shocked at the difference. After the shop was completely framed I walked around it and saw that, besides thr trusses, not a single stud in the walls was square on all four sides. The average tree must have been no large than 18″ in diameter based on the annular rings.

    2. Exxon’s Profit Miss Shows No One Immune From Market Ravages

      https://www.bloomberg.com/news/articles/2017-01-31/exxon-misses-estimates-as-recovery-from-slump-proves-elusive

      Exxon Mobil Corp.’s biggest profit miss in at least a decade is the starkest sign yet that major oil explorers remain mired in the deepest market slump in a generation.
      After resisting the industry trend of discounting the value of oil and natural gas fields that turned into money-losers amid the 2 1/2-year market slump, Exxon capitulated on Tuesday and took a $2 billion hit on the value of some Rocky Mountain gas.
      Exxon Mobil Corp.’s biggest profit miss in at least a decade is the starkest sign yet that major oil explorers remain mired in the deepest market slump in a generation.
      After resisting the industry trend of discounting the value of oil and natural gas fields that turned into money-losers amid the 2 1/2-year market slump, Exxon capitulated on Tuesday and took a $2 billion hit on the value of some Rocky Mountain gas.
      Exxon’s $2 billion writedown slashed fourth-quarter profit to $1.68 billion, or 41 cents a share, compared with $2.78 billion, or 67 cents, a year earlier, the Irving, Texas-based oil producer said in a statement on Tuesday. The per-share result was more than 40 percent lower than the average estimate of 21 analysts in a Bloomberg survey, the widest gap since at least 2006.
      In his first month on the job, Chairman and Chief Executive Officer Darren Woods is looking to deepwater drilling in South America and West Africa, gas exports in the South Pacific and shale riches in the Permian Basin beneath Texas and New Mexico to bolster reserves and improve Exxon’s production and profit outlook.

  12. Trial Balloon for a Coup? – Medium: “Finally, I want to highlight a story that many people haven’t noticed. On Wednesday, Reuters reported (in great detail) how 19.5% of Rosneft, Russia’s state oil company, has been sold to parties unknown. This was done through a dizzying array of shell companies, so that the most that can be said with certainty now is that the money ‘paying’ for it was originally loaned out to the shell layers by VTB (the government’s official bank), even though it’s highly unclear who, if anyone, would be paying that loan back; and the recipients have been traced as far as some Cayman Islands shell companies.

    Why is this interesting? Because the much-maligned Steele Dossier (the one with the golden showers in it) included the statement that Putin had offered Trump 19% of Rosneft if he became president and removed sanctions. The reason this is so interesting is that the dossier said this in July, and the sale didn’t happen until early December. And 19.5% sounds an awful lot like ‘19% plus a brokerage commission.'”

      1. So what? Hillary was getting her slush funds from the Saudis and Qataris through the Clinton foundation. What’s the difference?

        It’s good to have good relations with the Russians, they have thousands of nuclear weapons!! Why actively undermine a nuclear power? It’s the US which executed a coup in the Ukraine to attack Russia indirectly, its the US which has blown up multiple countries in the Middle East, not Russia.

    2. The source of the funds for $8 billion out of $10.2 billion total have been identified. What’s left in the dark is the source for $2.2 billion. I can’t stand Trump, but I seriously doubt they offered him Rosneft shares hidden in a matrioshka based in Cayman Islands. Trump is bad enough as it is, but we are seeing an incredible amount of trash talk.

  13. Mexico production declined again in December. It is now at about 10% year on year, and with a pretty steady drop month to month through 2016, losing about 240 kbpd over the year (December to December). Average annual was down about 5% from 2015 to 2016, . They added two oil rigs in December but dropped 17 over the year (minimum 15 in June). No reason to think the fall won’t continue and might accelerate, they have a replacement for the Abkatun rig that burnt in 2019 and another possible in 2020/2021 if it gets fast tracked, but nothing major before, although there has been talk of shale.

      1. Brazil need to bring on 2 or 3 FPSOs every year to replace the 10 to 15% decline rate they have in the deep and ultra deep production. I think they can achieve that and more through at least 2019 with FPSOs currently under construction. After that they might have problems because of recent delays in FIDs (from corruption and debt problems), even though they use cloned designs for mot of the vessels which therefore have a short construction time.

        Longer term Petrobras would need to develop Libra to maintain their production, as they aren’t finding much else now (or even looking) – I think I remember something from Total saying that Libra looked pretty difficult and expensive, but might have that wrong. Statoil and Shell have possible projects as well that could come on in 2022 or so.

        Petrobras also occasionally have major accidents and prolonged downtime which could take out a chunk of production, but overall I’d say Brazil should continue to increase for 3 more years.

        1. Is that quoted 10-15% decline rate with or without new ultra deep drilling semi local to the flowing well?

          1. I don’t fully know what you mean. I was talking about overall decline rates for online (mature) FPSOs. In general the FPSOs and subsea systems have a number of well slots and associated risers earmarked – some for oil, some water. I think they just drill the wells until they are all taken and then move on. As the FPSOs are mostly clones the riser numbers are fixed but they can to adjust template design from one to the next.

    2. Mexico’s average C+C production in 2016 was 2,154 kb/d, down 113 kb/d (5%) from 2015.
      This was still above Pemex’ guidance of 2,130 kb/d

      C+C+NGLs output averaged 2,458 kb/d, down 133 kb/d (5.1%) year-on-year.

      Mexico’s monthly oil production, 2014-16 (kb/d)
      source: Pemex

      1. Production declines have sharply accelerated in the second half of the year to -10.5% year-on-year in December 2016 for crude and condensate and -9.6% for C+C+NGLs.

        December 2016 C+C production was 2,035 kb/d, down 240 kb/d from December 2015.
        C+C+NGLs output was 2,330 kb/d, down 248 kb/d y-o-y.

        Pemex guidance for C+C production in 2017 is 1,944 kb/d, 4.5% below actual 2016 output.

        According to the OPEC-non-OPEC deal, Mexico has agreed to cut output in 1H2017 by 100 kb/d from October levels, to 2,003 kb/d. This is well within natural decline rates.

        Year-on-year change in Mexico’s petroleum liquids production

        1. Does anybody know Mexico’s current level of C+C consumption? Energy Export Databrowser looks to have Mexico close to 2 million barrels a day consumption as of 2015.

          1. Survivalist,

            It is impossible to find separate statistics for C+C demand. Normally, reported numbers are for total liquids demand. According to the IEA, in 2016 Mexico’s demand was below 2 mb/d and will decline 15 kb/d to 1.9 mb/d in 2017.

            The chart below from the IEA Oil Market Report shows that Mexico’s demand was actually declining at least from 2015.

            1. Mexico will remain net exporter of crude oil and refined products at least for the next several years.

              Mexico’s net exports of crude oil and refined products (kb/d)
              source:Pemex

            2. They import about 3 bcf per day of natural gas so overall they are around neutral.

            3. We are discussing oil.
              But yes, imported gas is replacing oil products in power generation.

              From the IEA OMR:
              “The Mexican Secretaria de Energia cited October power sector oil demand down by around 15% compared to the year earlier, with a compensatory sharp gain in natural gas use.”

            4. Another factor for lower oil demand in 2017 is retail price liberalization.

              From the January OMR (released today for non-subscribers):

              “Having fallen relatively sharply in 2016 (-60 kb/d to 1.9 mb/d), a further decline in Mexican demand of around 25 kb/d is foreseen in 2017, pulled down by higher retail prices. As part of the government’s efforts to liberalise road transport prices, the cost of gasoline rose by between 14%-to-20% and diesel by 16% effective from the start of 2017, with further potential adjustments to come. With higher prices likely to weigh heavily on Mexican road transport fuel demand, the net forecast decline for 2017 has been magnified since last month’s Report. The forecast decline would have been even larger were it not for the fact that the already steep declines experienced in Mexican power sector oil use has left little scope for a similar fall in 2017. The latest monthly data show a decline of 55 kb/d y-o-y in November to 1.9 mb/d, not far above October’s near 20-year low.”

  14. MOSCOW, January 31. /TASS/. Domanik Oil AS, the joint venture owned by Russia’s Rosneft – 51%, and Norway’s Statoil – 49%, started drilling the first well as part of an exploration program to study tight hydrocarbon reserves of Domanik sediments in Russia’s Samara region, Rosneft said in a press release on Tuesday.

    “During the pilot phase planned for 2016-2019, Domanik Oil AS intends to drill and test at least three horizontal exploration wells, as well as to conduct advanced studies at the license areas of Samaraneftegaz, Rosneft subsidiary,” the report said. The plan is to use the most efficient development technologies, including multistage hydraulic fracturing.

    Domanik sediments in Volga-Ural oil and gas province are low-permeable cherty limestone sediments classified as hard-to-recover hydrocarbons with large hydrocarbon potential, Rosneft said.
    http://tass.com/economy/928089

    1. A lot of people over the past few years have maintained that only American oil companies would be able to make tight oil work. Others have maintained that tight oil in a lot of countries,such as the UK, would never be developed.

      It’s sort of stupid to argue that the rest of the world lacks the talent and expertise to get tight oil out of the ground, if the price is high enough to make it profitable. State owned oil companies are probably a little less efficient, true, but they will still get the job done, unless the economy crashes hard.

      And unless we do manage the transition away from oil, people who have fought allowing the oil industry into their neighborhoods will eventually find themselves offering the industry INCENTIVES to move in, when they find themselves doing without liquid fuel.

      1. I’m not sure who said only American oil companies can do it. What the USA makes more competitively is the jewelry. That’s the equipment going in the well that allows multistage fracturing and completions.

        I believe Statoil has some USA operations, so for something like this they’ll just get two-three American employees (but they don’t have to be Americans) and a few others. The hardware for test wells can be made outside the USA if needed. If the wells pan out and the Domanik is viable, the Russians will reverse engineer the jewelry. When I think of it, they ought to test the tight zones in Orenburg as well.

        1. OFM, FL

          The first unconventional well in the UK is slated to be spud in a few months’ time.
          Site preparation has already started.

          China unconventional has been hampered by several issues, including most favorable locations not offered in the open market, favored companies given preferential status, as well as logistics and geology.
          Argentina seems to be making halting progress in the Vaca Muerta formation, but economics – aka low pricing – is an inhibiting factor.
          Russia seems poised to expand its shale program, but economics and politics has been dampening the pace.

          One – potentially – very large factor encouraging all this is the near term development history in the various US shale basins.

          Although any mention of the myriad technological innovations in unconventional production, particularly regarding completions, is derisively scorned by some posters on this site, the fact remains that continuous improvements are being consistently introduced.
          The current uptick in rig deployment with WTI at $53 or so should be evidence of that.

          1. 2016 10K will be out soon, next 30 days for most.

            We can plug in $53 WTI and current gas prices and get some idea of how much better economics have gotten.

            As to well productivity over time, just look at shaleprofile.com. The Permian shows evidence of improvement, not seeing much in the other major LTO basins.

            Public shale are considered growth stocks by Wall Street. Increasing production is paramount.

            1. Shallow
              When companies rushed in to the Eagle Ford after 2010, valuations per acre ranged about $10,000 per for many transactions (EOG got in first, under the radar, leasing about a half million acres for $300/$500 per. Huge economic advantage for them).

              Many of these Permian deals have valuations in the $40 to $60 thousand per acre range which seems insanely high.
              Yet, numerous companies have taken the plunge.
              We’ll all get to see, in years to come, how this plays out.

              In a somewhat related aspect, I’ve not seen an updated graphic from Rune on the cash flow from major Bakken operators.
              I’ve always felt that single frame told a very powerful tale, but not so much pessimistic as one might think.

    1. Any comments to this? Seems reasonable that Exxon will increase production in Permian given their recent acquisitions.

      “Exxon says it can more than double output in Permian Basin.Oil company voices confidence in outlook for North American shale production. ExxonMobil, the world’s largest listed oil company, has said it will be able to more than double its output in the Permian Basin region of the US and maintain it at that level for decades, in a vote of confidence in the outlook for North American shale production. The company told analysts on Tuesday morning that it could add 350,000 barrels of oil equivalent per day from the Permian region of Texas and New Mexico, thanks to the $6.6bn acquisition of companies from the Bass family announced in January. Its current output in the region is 140,000 b/d.”

      1. The quote was that they’d take a decade to get to plateau. That is not particularly impressive, like adding one decent sized tie back each year. A few years back they’d be adding that amount from a couple of offshore projects each year. In comparison they dropped 127 kboepd from existing production over the year (mostly gas though).

      2. Given their recent financial losses and their Permian acquisition, would it be reasonable to assume that they would paint the best possible picture of the Permian?

  16. Although CoreLabs is always bullish on oil prices, I enjoy reading the Macro view on their conference calls:

    “David Demshur

    Great. Thanks, Gwen. I’d like to take a look at our current macro views followed by comments on our three financial tenets.

    Core believes that the worldwide crude oil markets are currently undersupplied as indicated by several consecutive months of declining worldwide crude oil inventories. And we believe the projected December draw will be the fifth consecutive month in a row. Projected OPEC cuts of 1.344 million barrels of oil per day and other cooperating countries pledging to cut another 600,000 barrels of oil per day will lead to extended worldwide inventory declines and a continuing rally in oil prices and energy prices in 2017.

    As Core has continually stated, the Middle East was producing oil at unstable levels, and we are sure that some of these cuts will more than welcome by several Middle Eastern producing countries. All that Core did was listened to the reservoirs and not rhetoric. Also importantly, U.S. crude production peaked at 9.7 million barrels a day in March of 2015 and then declined approximately 1.3 million barrels a day into December of 2016. At that time, Core calculated a U.S. net decline curve rate of 11% per annum.

    U.S. crude supplies have increased on a net basis for October and November in response to increased activity levels, largely in the Permian Basin. However, conflicting data sets and completion statistics, especially in the large crude supply increase reported by EIA in October, especially from the Bakken, make calculations and projections for U.S. land production too difficult and uncertain to offer at this time.

    In 2016, production gains in the Gulf of Mexico were disappointing. Originally projected by Core Lab to add 200,000 barrels of production per day during 2016, the production added was essentially flat to up slightly year-over-year, owing to larger than expected activity declines and less production addition from legacy deepwater projects.

    2017 is off to a better start as BP’s Thunder Horse South complex completed ahead of schedule and under budget is set to add 40,000 barrels of new 2017 production. Globally, Core estimates that the net decline curve rate is currently approximately 3.3%. Applying the 3.3% net decline curve rate to the worldwide crude oil production of approximately 85 million barrels a day means that the planet will need to produce an additional 2.8 million barrels of new oil by this date next year to maintain current worldwide productive capacity totals.

    With limited long-term sustainable spare production capacity coupled with the aforementioned production cuts, Core believes worldwide producers will not be able to offset the estimated 3.3% net production decline curve rate in 2017, leading to a further decline in global crude oil production. Also, weighing on future production capacity is the fact that operators discovered less than 4 billion barrels of new oil in 2016, while the globe consumed over 55 billion barrels. Therefore Core believes crude markets more than rationalized in late 2016 and price stability followed by price increases, some occurring as we speak, are returning to the energy complex. Remember, the immutable laws of physics and thermodynamics mean that the crude oil production decline curve always wins and it never sleeps.

    On the demand side of the crude oil market, new IEA estimates have increased worldwide demand in 2017 by approximately 1.4 million barrels of oil per day over the 1.3 added in 2016. The U.S. is now using approximately 10 million barrels of gasoline per day and 20 million barrels of total demand of hydrocarbon near record levels. Recent Chinese imports coupled with strong demand out of the India are near all-time highs. In addition, China the world’s largest energy consumer is probably in terminal decline as year-over-year production has dropped more than 400,000 barrels a day to 3.8 million barrels a day in 2016 that is near a six-year production low.

    Other countries posting significant 2016 production decline, which will continue into 2017 include Mexico, Venezuela, Colombia, Angola, Kazakhstan and Oman amongst others. As projected by Core in early 2016, the third quarter of 2016 marked the bottom of the V-shaped recovery which is now underway. This recovery should continue to strengthen with higher commodity prices and subsequent activity levels as 2017 progresses.”

      1. Kazakhstan’s C+C production has been increasing since the start-up of Kashagan

        Kazakstan monthly C+C production (kb/d)
        source: State Statistical Committee of Kazakhstan

        1. The country’s government projects further growth in the next 5 years

    2. RE: CJ posted comment from Core Labs

      I am not sure about that guy anymore. He was wrong before, and he is obviously misstating something today.

      “Also importantly, U.S. crude production peaked at 9.7 million barrels a day in March of 2015 and then declined approximately 1.3 million barrels a day into December of 2016.”

      Alex [thanks Alex], notes in a post below that November US crude production coming “into December” averaged 8.904 million barrels a day. An error of at least 44% [.4/.9 – (900,000 bbl/day being the actual decline, not 1,300,000 bbl/day)].

      1. I think he’s on to something with OPEC being stretched before the cuts though, and nobody else has mentioned that before.

      2. clueless,

        Yes, this guy was wrong. According to the EIA, U.S. C+C production declined 1,060 kb/d from the peak in April 2015 to the low in September 2016.

        Following a 2-months growth, output in November 2016 was 723 kb/d lower than in April 2015.

  17. ExxonMobil lost $301 million in its US upstream operations in Q4 2016 and $2.1 billion for FY 2016 in its US upstream operations, compared to a 2015 FY loss of $1.1 billion in its US operations.

    The loss does not include a $2.1 billion impairment taken on the write down of US assets, which, if included, results in a loss of $4.2 billion in its US upstream segment in 2016.

  18. EIA’s monthly oil production statistics for November 2016 are out.
    The “final” number is 8,904 kb/d, much higher than preliminary estimate in the Monthly Energy Statistics (released on 1/1/2017): 8,692; higher than projected in January Short-Term Energy Outlook: 8,856 kb/d and higher than in weekly production statistics for November.

    The “final” monthly numbers can still be revised, but they are generally much more reliable than the MER data.

    According to statistics released today, U.S. C+C output in November was 105 kb/d higher that in October and 344 kb/d higher than in September
    Weekly numbers also show continued growth in 4Q2016 and in January 2017

    1. And doesn’t this rise in production lead to continuing low oil prices?

      1. Maybe I am not smart enough to figure out why scaled down activity level in the shale oil industry would lead to the higher production level reported in recent months. There are some lag time issues when hiring rigs and frac spread jobs to when production rise, not? Or more likely, I am smart enough and natural declines will become a major problem going forward. If this is the case, I suspect some companies have been speculating on when to sell their crude awaiting higher prices and somehow scaling up sales from storage or increased completion activities the last few months when WTI reached 50.

        1. Drilling and completion activity in the U.S. has been on the rise since June 2016

        2. With regard to storage, it is not a factor with production levels. There are gauges on every wellhead to measure production. The states require this, among others, since they collect severance taxes on production. They could care less about whether it gets sold or not.

          1. In Texas oil is measured in stock tanks, on lease. On-lease storage is often limited and rarely exceeds 30 days of capacity for a 100 BOPD well. Oil cannot leave the leased premise without being sold to a mid-stream purchaser via truck or pipeline LACT and accounted for, to the gallon. Oil is typically sold on a weighted monthly average and is only subject to State severance tax once it is sold.

            1. Thanks for the info Mike. I am proof positive that you are never too old to learn something.

              I tried to post this yesterday, but something was not working.

            2. I always learn something from you as well, sir. Its always good to get one’s head out of internet links and think for oneself.

              Take for instance the EIA’s goodie-two-shoe comparison of Eagle Ford shale thickness and multi-stacked shalely carbonates in the Permian described downhole. Each of those horizons in the Permian require different, separate wells which cost (using full cost accounting methods for leasehold and infrastructure costs, and given the size of the frac’ing going on out there) upwards of $8.5 to $9.0M each. In the case of the Wolfcamp, some part of the vertical section can be used to plugback, or deepen, to a different horizon, and frac again, but doing that is still going to require 75% of the original well cost.

              Every year the EIA gets more giddy about LTO resources in America and keeps uppin’ its reserve ante. People slurp it up like free beer. Costs matter, prices matter, debt matters and the financial state of the US shale oil industry really matters.

              Rigs are pouring out yards now because of a.) a 5 dollar bump in prices and b.) Trump is going to fix everything, including a very wobbly shale industry. Its a world oil market, however, not an American oil market. More shale oil, lower prices. Another run for glory by those shale oil dudes, using borrowed money, or swapping credit for equity, is going to bury them deeper than they are now. If that is possible.

            4. http://www.custodytransferlact.com/pipeline-lact

              You will of course please forgive my rants but POB has become nothing more than Facebook posts about what the EIA says, or Rystad says, about this and that. A news reporting site. I can read my own news. I miss here, gone forever, I know, when people could think for themselves, beyond next week.

              Just about all of our country’s energy future, and much of the worlds oil price future, is now based on unconventional shale oil production in America. Save for cheaper gasoline, its a complete economic failure thus far. If folks want gasoline to stay cheap, they need to get their heads out of the sand as to how this stuff is going to get paid for. The shale oil industry can’t do it own it’s own.

              Mike

    2. It is important to note that the largest contribution to growth in the U.S. C+C production between September and November 2016 was from the GoM: +175 kb/d (of 337 kb/d total).

      Production in Alaska increased by 61 kb/d.

      Growth in the Lower 48 states ex-GoM was relatively modest at 101 kb/d.

      North Dakota was up 65 kb/d, but this was due to the surprisingly strong growth in October, while November saw a slight decline.

      C+C output in Texas increased by 43 kb/d, exclusively due to growth in the Permian.

    3. The EIA expects growth in the U.S. C+C production to resume in 2017, but at a relatively slow rate, and primarily driven by the Permian:

      Major U.S. tight oil-producing states expected to drive production gains through 2018

      JANUARY 31, 2017
      http://www.eia.gov/todayinenergy/detail.php?id=29752

      In EIA’s January Short-Term Energy Outlook, U.S. crude oil production is forecast to increase from an average of 8.9 million barrels per day (b/d) in 2016 to an average of 9.3 million b/d in 2018, primarily as a result of gains in the major U.S. tight oil-producing states: Texas, North Dakota, Oklahoma, and New Mexico.
      Although overall U.S. oil production has been declining since mid-2015, production has continued to increase in the Permian region. In 2016, Permian production averaged 2.0 million b/d, a 5% increase from the level in 2015. EIA expects this trend to continue, with Permian production projected to average 2.3 million b/d in 2017 and 2.5 million b/d in 2018.
      Compared with the Permian region, the Eagle Ford region has fewer overall drilling opportunities in core areas. The Eagle Ford region has a significantly smaller geographic area than the Permian region, and the region’s target producing zones are only about 200–300 feet thick, compared to the thousands of feet within the Permian. As with most shale and tight oil regions, the Eagle Ford region has wells with high initial production rates, but faster than average production rate declines. Because of these production rates, drilling fewer new wells has a more immediate effect on production. As low oil prices slowed the pace of drilling, production in the Eagle Ford region has declined since March 2015, with average annual production at 1.6 million b/d in 2015 and 1.3 million b/d in 2016.
      Although declines in Eagle Ford production are expected to continue through the first half of 2017, EIA expects production in that region will begin increasing in the third quarter of 2017 and will continue to increase through 2018 as higher oil prices encourage more drilling activity. With the combination of the Permian’s continued growth and renewed production in the Eagle Ford, Texas is expected to continue to be the largest-producing state through 2018.
      The Bakken and Three Forks formations drive crude oil production in North Dakota, which has been in decline since 2015 in response to lower prices. Unlike in Texas, producers in North Dakota have additional infrastructure constraints involved in transporting their products to market. During the winter, production costs increase as operators must deal with below-freezing temperatures and heavy snowfall. However, as in the Eagle Ford, new drilling is expected to increase, enabling overall Bakken production to stay at least flat through 2018.

      1. The November production total is the highest offshore GOM production since 2010 (1.68 mmbopd now vs. a couple months over 1.7 mmbopd in 2010) and in 2010 shelf production was about 300 kbopd. Now shelf production is probably about half that, meaning deepwater production is over 1.5 mmbopd, which is probably a record high level.

        1. BOEM issued a production update including most of November yesterday and have flow up 20,000 to 1.6 mmbpd, still below August’s 1.61. I looked at the fields which have recent additions as new leases or tie-backs (see below) and it’s difficult to know where EIA are getting the other increase from. For the leases shown production actually dropped, despite Coelacanth and Phoenix/Tornado coming on line. The drop was mostly from Tubular Bells, which seems to be in fast and steady decline, Lucius, which is cutting a lot of water on two leases, Rigel (a couple of wells off line), and Dantzler, which went fully off line. There wasn’t much notable ramp up on anyone field, but note Stones didn’t report for November and I just assumed constant flow from October, in fact it may have had a large increase (up to 30 kbpd if it got to nameplate).

          I think Heidlberg will add some plus Coelacanth (which only produced a bit in October and then went offline again), and Julia should add another well sometime. But future ramp up is not going to be as high as I expected from this year’s start-ups. In next year’s figures Thunder Horse South and Jack stage II should add some. Jack St. Malo hasn’t fully reported so I didn’t show it.

          I only showed one lease on Caesar/Tonga which was a recent start-up, the actual production is high (at least 100 kbpd) but not all leases have reported to November.

          I may have missed some production in the named fields. Following in BOEM by lease number can be quite difficult. For instance half of Lucius production comes from a lease previously owned by ExxonMobil for Hadrian North and not listed on the BOEM site except hidden away in one pdf. Lucius actually exceeded nameplate through October but dropped down – as above I think this is well reduction as water breaks through, but there may have been availability issues or top side limits as the water systems are started.

          1. George,
            To determine the production totals through the BOEM website do you have to do it in a bottoms up approach? That is, a field by field (or lease by lease) approach, and then you just sum them all?
            The 1.68 mmbopd I mentioned above was from EIA data. BSEE data was released 2 days later, and that total came to about 1.66 mmbopd. In both cases, it is just a single total production number.

            1. You are right – I screwed up, somehow got Excel to divide by 31 instead of 30 for November, so should be 1.655 mmbpd.

              I was mainly interested in what future production there might be in the next few months, which was why I was looking at the individual leases. If BOEM have assumed Stones production November is close to nameplate then there isn’t that much ramp up, but a few fields seem to have been partially shut in, however that is always going to be the case somewhere.

            2. One other field that did have a sizable increase in production between October and November was Atlantis. That field was down on production for a few months, in the 40 kbopd range, but was at about 120 kbopd in November.

      2. There has been significant hiring in Williston these past several weeks.
        I believe the number posted of open positions was over 1,000 for frac crew personnel, truck drivers, mechanics and technicians in various specialties.

    1. It’s old joke that goes something like: “Yeah, we are losing money on each unit we sell but we’ll make up for it in volume” 🙂

    2. It is interesting how low key their operations report for the GoM is. They only indicate continuing FEED and appraisal drilling for Shenandoah, which would suggest no FID this year. For Constellation it looks like a couple of well tie backs with first oil in late 2018 – this used to be Hopkins with BP and was initially touted as a fast track new hub. Horn Mountain Deep drilling is scheduled for first quarter, but looks again to be a couple of wells tie back. Presumably they need to source subsea kit for production so I don’t think it would be thus year (I could be wrong there though, they may have existing template slots they can use). And not much else – if Warrior and Phobos had been really big finds I’d have expected a bigger splash for them.

    2. So, it looks like we will find work drilling a gazillion wells, oil will be $150 a barrel, Texas will join OPEC, and Trump won’t want to invade Mexico after all.

    1. I can see Bakken and Niobrara hitting a plateau in a few months as EIA suggest, but it doesn’t look so easy for EFS to turn around quickly, they’re going to need to increase completions quite a lot.

      1. George,

        I agree that more completions in the EFS are needed.

        As you can see, the average horizontal well adds an UR of about 150 kbo. So, in the long haul, you need about 7 of these per day to keep production at 1.05M bo/d, which is just over 200 a month. In 2016, the number of completions was about half of that. As a result, you can see that in 2016 less than half of the decline was covered with new production.

        Of course, this is just a simple estimate, but I belief it to be in the right range.

  23. Shell results are out:

    http://www.shell.com/investors/financial-reporting/quarterly-results/2016/q4-2016.html#q4-2016-documents=true&iframe=L2ludmVzdG9ycy9maW5hbmNpYWwtcmVwb3J0aW5nL3F1YXJ0ZXJseS1yZXN1bHRzLzIwMTYvcTQtMjAxNi9qY3I6Y29udGVudC9wYXIvaWZyYW1lZGFwcC5zdGF0aWMvcTQtMjAxNi1yZXN1bHRzLXRhYmxlLmh0bWw=

    They made a profit as a group but upstream lost more money than last year, although in 4Q got into profit. The biggest news is around BG acquisition, and the continuing asset sales to pay for it (which are half done but on track according to the CEOs statement).

    “Upstream earnings excluding identified items were a loss of $2,704 million compared with a loss of $2,255 million in 2015. Identified items were a net charge of $970 million compared with a net charge of $6,578 million in 2015.
    “Compared with 2015, earnings excluding identified items were impacted by lower oil and gas prices, and increased depreciation mainly related to a step-up resulting from the BG acquisition. This was partly offset by increased production volumes mainly from BG assets. Earnings also benefited from lower operating expenses, which more than offset the impact of the consolidation of BG, and lower exploration expense.
    “Full year 2016 production was 2,784 thousand boe/d compared with 2,323 thousand boe/d in 2015. Liquids production increased by 24% and natural gas production increased by 15% compared with 2015.
    New field start-ups and the continuing ramp-up of existing fields, in particular the Corrib gas field in Ireland and Erha North ph2 in Nigeria, contributed some 69 thousand boe/d to production compared with 2015.”

    I think only ExxonMobil has so far reported a yearly profit for upstream operations in IOCs, or overall for independents.

    1. Oil and natural gas production records new record in Brazil in December
      Thursday, February 02, 2017
      In December 2016, Brazil had a record in both oil and natural gas production. Oil production totaled 2,730 million barrels per day, up from 2,671 million b/day produced in September 2016. This is an increase of 4.7% compared to the previous month, and Of 7.8%, compared to the same month in 2015.
      http://www.anp.gov.br/wwwanp/noticias/anp-e-p/3567-producao-de-petroleo-e-gas-natural-registra-recorde-no-brasil-em-dezembro

  24. In case anyone was about to read this article: Rex Tillerson and the Myths, Lies and Oil Wars to Come, don’t bother. The guy, that is the author of the article, believes oil is “abiotic”, that is, it pushes up from deep in the earth’s mantle. Here are two paragraphs from near the end of the article, bold mine.

    The implications of the deep Earth genesis of hydrocarbons were profound and forced me to change my previously-accepted belief. I read further the fascinating geophysical theories of the brilliant German scientist, Alfred Wegener, the true discoverer of what in the 1960s was dubbed Plate Tectonics. I came to realize that our world is, as the Dutch oil economist, Peter O’dell famously put it, “not running out of oil, but running into oil.” Everywhere, from offshore Brazil to Russia, to China, to the Middle East. I wrote what became one of my most read online articles, “Confessions of an Ex-Peak Oil Believer,” in 2007.

    Indeed I realized that the entire foundations of Western petroleum geology was a kind of religion. Rather than accept the Divine Birth, Peak Oil “church-goers” accepted the Divine Fossil Origins. No proof needed, only belief. To this day there exists not a single serious scientific paper proving the fossil genesis of hydrocarbons. It was posited in the 1760’s as an untested hypothesis, by Russian scientist Mikhail Lomonosov. It has served the American oil industry, especially of the family Rockefeller, to build an immense fortune based on a myth of oil scarcity.

    This guy has to be a blooming idiot.

      1. No, I did not mean to say that. I meant the author of this article believes in abiotic oil. I will correct my post to make that clear. But thanks for the heads up.

        2. Well, maybe best to start with the big whammy — methane on other planets. Odds pretty high those hydrocarbons are abiotic.

          As for all else, I think it was Jeffrey who noted that it doesn’t matter how it is created. It is still only found in given types of rock, and it is that which is getting scarce.

          1. Pffft. Every scientist knows that some *methane* is abiotic. Crude oil, however, is 100% fossil. Coal is also 100% fossil.

    2. I always thought oil was kindly given to the human kind by His Deity the Flying Spaghetti Monster. Was I wrong? Do I really have to trust a logical conjecture based on overwhelming observable evidence?
      I think we better have to look at alternative facts to explain the reality: from raw estimation, there are 50,000 barrels of oil formed every year, very far from the almost 35,000,000,000 we burn/transform every year. So at the current rate, on average 2000 years would be needed to allow human kind to consume oil during a single day!

  25. Concerning Exxon’s report.

    They are calling the reserves impairment a charge against XTO’s purchase with the reserves being nat gas and NGLs. Or at least that’s how one reporter laid it out.

  26. Trump loves pipelines. But he just accidentally froze a bunch of them – The Washington Post: “When Bay departs, the five-person commission, which already has two vacancies, will no longer have a quorum. No quorum means no approvals for contested issues including electric transmission lines, natural gas pipelines and utility plans. Any new member nominated by Trump must go through Senate confirmation, something that could take another four months.

    ‘This leaves FERC paralyzed for the time being,’ said Arvin R. Ganesan, vice president for federal policy at Advanced Energy Economy, a business advocacy group.”

      1. I’ve never understood the “too light for US refinery” rational. Can someone smarter than me explain how this works? It seems that refining a light crude (40-50 API) would require much less refining to get gasoline (50-55 API). Wouldn’t it just be more efficient for a couple of refineries near the shale oil patches to modify their process- instead of all this extra transporting, blending etc.???

        1. If a refinery has diesel customers, they aren’t going to want to occupy their time and effort with oil that has very little diesel in it, or kerosene.

          If they instead placed an order for conventional oil they could have output of gasoline, diesel and kerosene that their customers want. Probably some market share issues in there, too. If they go ahead and take 50 API oil and refine it and sell the gasoline, they are going to lose customers to refineries that chose to get oil of distillate containing API densities. Never a good idea to give customers away.

        2. Each refinery is set up a little different with different modules and different sized equipment. They can handle a range of oils but not every possibility. For instance distillation columns have a range of gas and liquid rates, if the oil gets lighter the vapour rate will increase, eventually the column can’t cope and would flood. It may be possible to handle this but only at the expense of reduced throughput. Also there are cracking operations to turn heavy components into lighter ones (some refineries don’t have these) and there has to be a balance of hydrogen and carbon over the refinery so these run optimally (that balance is changed as the API of the feed changes). Changing the process can be done – it’s a question of scale, timing and economics: shutting down for several months while a new distillation column is installed is not going to happen without a big incentive, but the are continuous upgrades (e.g. Exxon had a big revamp at Beaumont recently).. Most refineries are sited where the oil used to be (either produced or imported) e.g. on the Texas coast. I think there have been a couple of small ones built near the shale in ND, but its a huge investment and would probably need more than even the high reserve estimates of Bakken to justify a new main load refinery there, as it looks like there’s only 5 to 10 years left, 4 of which would be taken with the construction.

          p.s. that is just knowledge not smartness, and if you ask again in five years I’ll have probably forgotten it all.

      2. “Almost all” doesn’t make any sense. The price at the wellhead has been advertised as determined substantially by distance to the refinery.

        Then there is that curious little assay reality that Bakken oil’s North Dakota govt official API is 39.5. We questioned that during the days of vapor pressure challenge and exploding railcars, but that went nowhere.

        1. Price at the wellhead is set by oil properties and transportation costs. Oil properties we focus on are the product slate (what can be made with the stuff), the acidity, metal and sulfur content.

          Blending a very light crude with Alberta or Venezuelan extra heavy crude doesn’t produce an optimum blend (refiners call it a dumbbell crude, because it has too much light and asphalt component). Blending the light does help to make the extra heavy easy to transport.

          I’ve studied this topic for decades, together with colleagues who were real heavy hitters in their fields. What I found is that it’s not useful to generalize, nor are conditions static in time. When we prepare development plans for very large projects producing these “odd” crudes we do a lot of head scratching, consider multiple options, such as upgrading near the field, upgrading refineries to process the crude, blending to improve marketability, etc.

          I’d like to repeat the chosen solution has to consider the way the market evolves over time. I haven’t consulted in Canada for a few years, but I suspect they are eyeing that Bakken crude as a partial solution to their blending needs. The problem they face is that it makes the mother of dumbbells, and the Bakken won’t be producing at high rates in a couple of decades.

    2. Boomer,

      It all seems rather strange with the FERC and running out of commissioners. I had thought the narrative would have been “democratic commissioners resign to stop approvals”. Yet according the Bentek, today they rushed ahead and approved was seems like all outstanding applications, see story below. It seems like the FERC commissioners have been holding back approvals due to EPA interference. I would think even without Scott Pruitt’s approval, the EPA would be withdrawing their objections.
      How long does it take to appoint new commissioners? Do they have to be Senate approved? Once Trump gets his 3 men in place, I feel the FERC will have a much more rapid approval rate, for better or worse. Surely new appointments would not take more than a month, if there is a perceived need or urgent replacement.

      http://www.bentekenergy.com/

      Rover, Panhandle Backhaul, Trunkline Backhaul receive FERC certificate
      Friday, February 03, 2017 – 6:06 AM
      On February 2, FERC issued the final approval certificates for the Rover pipeline, Panhandle Backhaul Project, and Trunkline Backhaul Project. After much debate, and multiple requests from Rover and its shippers for an expedited approval, the final certificates were issued just one day before the quorum at FERC will be momentarily lost with Chairman Norman Bay’s resignation. Though receiving the final certificate is a huge milestone for the project, FERC denied Rover the blanket certificate they had requested that would allow the company to perform many of the project’s construction activities without the need to have case-specific approvals. FERC denied this request, citing the intentional demolition of a house eligible under the National Register of Historic Places as the reason, stating that Rover may reapply for the blanket certificate after 18 months of operation. Even with this approval, it is unlikely that Rover will be able to complete all of the tree felling necessary by the March 31 cut-off date, though it should allow them to make some progress this year. Look for more on this topic later Friday on the new Benport Spotlight series.

      These approvals are in addition to the Leech Express, Atlantic Sunrise and Northern Access pipelines, all in the last couple of weeks.

      The biggest problem I see, come late 2018, is finding the Nat Gas to fill the pipes. But time will tell on the one.

      1. The article says new commissioners do have to be Senate approved. So that’s why the delay.

  27. Russian oil and condensate production was down 96 kb/d month-on-month to 11.11 mb/d in January, following the OPEC – non-OPEC agreement to cut supply. Compared to October 2016 reference level, output in January declined by 119 kb/d, more than initially pledged by Russia’s energy ministry (50-100 kb/d).
    Russia aims to cut production by 200 kb/d (from October level) by the end of first quarter and reduce it by 300 kb/d in April or May.

    At the same time, Russia’s crude oil exports increased by 172 kb/d in January vs. December, although it was 89 kb/d lower than in October 2016.

    Russian crude and condensate production (kb/d)
    (7.33 barrels/ton conversion factor)
    Source: Russia’s energy ministry

    1. Soo almost 1 million bpd more production at 1/2 the price since summer 2014.

      1. The Russian ruble plunged in value with the sanctions. They sell oil in $. So, to give an example: Pre-sanctions, they sold a barrel of oil for $100, went to an international bank and converted the $100 to 200 rubles. Post-sanctions, they sold a barrel of oil for $50, went to an international bank and converted the $50 to 225 rubles. So, with respect to oil, they were no worse off.

        However, pre-sanctions paying for goods from the west, it took 200 rubles to purchase $100 of goods. Post sanctions, it took 450 rubles to purchase $100 of goods from the west.

        The numbers I used are arbitrary for illustrative purposes only.

        1. The ruble plunged mainly due to the decline in oil prices; sanctions are a secondary issue. The central bank decided not to burn international reserves and let the ruble sharply depreciate. That largely offset the negative impact of lower commodity prices on exporting undustries, as their revenues are mostly in dollars, and costs in rubles. (That also helped to substitute some of Russia’s imports with local production, but that’s another story). The impact of lower oil prices was also mitigated by Russia’s progressive oil tax system.

          The effect of the currency depreciation was partially erased in 2016, when the ruble has appreciated by 20% vs. the dollar. But Russian oil companies not only remained profitable and cash flow positive, but were also able to increase upstream capex in ruble terms, and hence, drilling activity.

          1. And, of course, you’re measuring things wiih a substance created whimsically via Quantitative Ease. How can it be surprising that conclusions are not clear?

            2. Not a gold bug.

              25% of GDP was created from nothingness via QE from 2009 to 2015. How can it be a meaningful measure?

              Maybe ergs.

    2. BTW you guys from Texas. You seeing robots or is this narrative bogus?

      1. The robots story seems to be bogus. I read one about the Iron Roughneck we use on offshore rigs, it was going around on Twitter. The author touted it as if it were a brand new technology. Also failed to understand the difference between a deep water rig and a 2000 hp land rig.

        I’m used to working in directional and horizontal well operations, and I’d rather have a slightly oversized rig with a top drive and a really good mud handling system, rather than spend the money on “robots”. These mba theoretical types don’t realize the roughnecks also have to rabbit pipe and do other chores when they aren’t tripping.

        1. Automation / robots may be invented by journalism as the latest manifestation of fake news.

          The problem being what ShallowSands and the guys here grope around for: How in hell is this oil flowing at a loss going on 3 yrs now? Cost cutting was the answer offered up by managements in various investor pitches, but there is never any concrete array of examples offered of what the cuts were — other than generic lower prices from suppliers.

          Of what? Proppant? So the frackers were allowing themselves to be gouged before? What sense does that make? What supplier was getting 40% more margin then than now, and why didn’t their stock do a X10? Bogus. There has been no technological miracle that lets it all happen at 1/2 2014 prices — as shown by those enormous GAAP reported losses filed each quarter.

          So robots are now the explanation du jour. Salary expense for roughnecks can be reduced to near zero because . . . robots, and presto, we have an explanation for how more oil can be produced at 1/2 the price,

          Except . . . no one is seeing robots. And if they *are* seen, the President will wipe them out.

          1. Yo watcher.
            The problem being what ShallowSands and the guys here grope around for: How in hell is this oil flowing at a loss going on 3 yrs now?

            I was reading an article in TechCrunch yesterday (https://techcrunch.com/2017/02/04/drain-the-swamp/)that led me to form a theory. The article talks about how Venture Capital firms depend on pension funds for a lot of their investment.

            From the article:
            More importantly, behind this seamless, polished exterior lies an ugly truth. These companies, and many more like them, are losing a lot more money than they’d like you to believe. Uber lost $1.2 billion in the first half of 2016. As a passenger, we only pay 41 percent of the actual cost of our trip! Free services, low prices, promotional codes… these consumer subsidies are all fueled by the venture capital industry.

            Sounds like shale, doesn’t it?

            My theory is that the guys who run these funds have a limited amount of time to vet their investments, and are essentially guessing. While we can see the insanity of Shale, they merely see one of a series of really bad choices with risks that are hard to measure. They have relationships with sales people, past histories of Energy companies making money, and no better choices. They can write off the loss as bad luck, because their fund is doing about as well as its competitors, or if they are a little more savvy, explain that they’re waiting for the market turn (which they may be…)

            So it’s a question of Oil being one of the trees in the investment forest. Those investors neither know or can comprehend the idea that while Uber disappearing is not a great loss for civilization, running out of affordable oil is.

            Oil investment, and the future of oil as a commodity are not linked in any tangible way in the marketplace, nor are any of the other high-risk investment vehicles to their respective markets.

            Hysteresis in the oil market is exacerbated because it is a subset of hysteresis in the investment market.

            Which is kind of similar to your mantra that money doesn’t mean anything anymore.

            -Lloyd

            1. Lloyd, you’re correct — in general — about how investment markets work.

              It gets worse, though: there’s a principal-agent problem. The individual stockholder or individual venture capitalist may bother to evaluate the companies and industries individually. But most of the money is in things like pension funds and mutual funds. And the managers of those… well, it’s not their money, is it? They get paid by *salary*. So they can mismanage the money, and as long as their mismanagement is “respectable” — i.e. lots other people screwed up the same way — they don’t get fired.

            2. Hi Nathanael.
              I think the most important takeaways for me from this insight were:
              1) Compound hysteresis around oil pricing makes prediction pretty much impossible.
              2) Peak Oil will probably be masked by investment cycle hysteresis.
              3) The investment sales cycle may have disastrous effects for humanity in the long run (eg. Hookers and Blow rather than due diligence.)

              -Lloyd

          2. “The problem being what ShallowSands and the guys here grope around for: How in hell is this oil flowing at a loss going on 3 yrs now? ”

            As long as investor money keeps coming in and the oilmen keep collecting their salaries, do they really care whether the investors lose their shirts?

            Financial bubbles ALWAYS work like this. It all seems quite obvious to me. Consider that nearly all of the coal companies have declared bankruptcy, some have declared bankruptcy *twice*, and they’re still operating, using funding from new “dumb money”.

            The “carbon bubble” will pop, but the question is when.

  29. Anyone seen data or charting on- EROEI vs time , for either individual countries or globally?

    1. Babbling a lot today. In general EROEI stuff isn’t much more than a guess. No one ever knows where to delineate. Do you count the fuel that powers the frack pump and that’s the end point, or do you count the fuel that hauled the pump to the site as well? How about the fuel for the production water trucks?

      It’s all arbitrary.

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