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U.S. Petrochemical Industry Future - Upstream - Crude Oil - Logic Versus Faith and Hope

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I believe the U.S. long term crude oil situation is worst than most think.

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U.S. Petrochemical Industry Future - Upstream - Crude Oil - Logic Versus Faith and Hope

  1. 1. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 1 of 66 In 2005, total U.S. crude oil production had fallen from a high in 1970 to a low in 2008 that had not been seen since 1950. By the week of September 2005, the average price of all grades of gasoline had risen to about $3.12 a gallon from an average price for all grades from about $1.25 a gallon during the week of June 1995, which was the highest weekly price for that year. American drivers were starting to reduce their driving mileage by this time. The total miles driven according to the Federal Highway Administration (FEA) topped out at 3.03 trillion miles in 2008. The next year, 2009, it dropped to 2.96 trillion miles. Miles driven had not decreased from one year to the next since 1980 according to FEA figures. By the week of June 2008, the average price of all grades of gasoline had hit an all-time high of about $4.16 a gallon. Refinery percent utilization dropped to 74.6 in September 2008. That was the lowest percent utilization since April 1985. Since then percent utilization has climbed to a level of 90.4 in September 2016. Starting in 2006 in the Bakken play with the discovery of Parshall Oil Field by EOG Resources, tight oil (also known as shale oil) has been an increasingly larger share of U.S. total crude oil production. The Bakken boom has propelled North Dakota into the top ranks of oil-producing states. As recently as 2007, North Dakota ranked 8th among the states in oil production. In 2008, the state overtook Wyoming and New Mexico; in 2009 it out produced Louisiana and Oklahoma. North Dakota surpassed California in oil production in December 2011, and then in March 2012 overtook Alaska to become the number two oil-producing state in the country, exceeded only by Texas. Petrohawk drilled the first “unconventional” well in the Eagle Ford play in 2008. In the first six months of 2013, production skyrocketed to almost 600,000 barrels per day. However, there was a problem. RBN Energy, an organization that has a daily blog about energy issues and provides analysis of such issues published the following on February 20, 2013: Published by: Sandy Fielden Last week (February 2013) EOG Resources told analysts that most Eagle Ford oil production should be classified as condensate rather than crude oil. They backed up their assertion with a chart of production quantity and API quality indicating 70 percent of production is condensate. Current forecasts indicate that translates to condensate production of over 500Mb/d in South Texas during 2013. It was after that announcement that I started reading articles about companies considering building condensate splitters all over southeastern Texas. Then later, I start reading about industry pressuring Congress to repeal the law which banned the export of crude oil. This law was originally imposed by the Energy Policy and Conservation Act of 1975 as a response to the 1973 oil crisis. The House finally passed a bill to repeal the ban of crude oil exports in October 2015.
  2. 2. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 2 of 66 The tight oil-shale gas boom, promoted by Federal Reserve easy money, started a euphoria that created the biggest delusion since the Roman times of Augustus. America is going to be energy independent! This delusion helped Obama win a second term. Obama jumped on this bandwagon saying in his 2012 state of the union address the following. We have a supply of natural gas that can last America nearly 100 years… And my administration will take every possible action to safely develop this energy. Experts believe this will support more than 600,000 jobs by the end of the decade. If tight oil wasn’t going to do the trick, than it would be natural gas. (we’ll talk about natural gas in the next report). Whatever! Don’t worry, the experts said so. The experts were the Energy Information Administration (EIA), their buddies the International Energy Agency (IEA), and all the U.S. oil and gas wildcatters scrambling to get money to finance their generally net loss operations. All were talking about supply, and still are. They all forgot about demand. When price is too high, demand adjusts to reduce price. And that is what started happening mid-2014. The WTI price dropped from $105.79 in June to $47.22 in January 2015. From Wikipedia, the free encyclopedia The 2010s oil glut is a serious surplus of crude oil that started in 2014–2015 and accelerated in 2016, with multiple causes. They include general oversupply as US and Canadian shale oil production reached critical volumes, geopolitical rivalries amongst oil-producing nations, falling demand across commodities markets due to the deceleration of the Chinese economy, and possible restraint of long-term demand as environmental concerns steer an increasing share of energy consumption away from fossil fuels. It should be obvious that the present-day world economy cannot operate for long at the $100+ crude oil price. The WTI price made a run above $100 in 2008 and the economy collapsed. The WTI made several more runs above $100 from 2011 to 2014 with the help of more easy money and near zero short term interest rate, but the economy collapsed again and has been running at decreasing speed ever since. None of this makes any difference to the tight oil-shale gas industry. It’s all about finding more supply, and talking about how increasingly efficient the industry is becoming all the while accumulating more debt. As long as the banks and private-equity funds will keep giving them the money, the drilling craze will continue. Now the latest fad is the Wolfamp play in the Permian Basin. Wolfcamp is one of six formations in the Permian Basin in West Texas. Crude oil production has been on going in the Permian Basin since the 1930s. Horizontal drilling and hydraulic fracking has allowed some of the old plays in the Permian Basin to be redeveloped. The USGS recently announced 20 billion barrels of “undiscovered” technically recoverable crude oil in the Wolfcamp play. However, the USGS makes
  3. 3. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 3 of 66 clear that the 20 billion barrels have a roughly 50% probability of existing and are not necessarily economically recoverable. After that announcement, Art Berman pointed out that the USGS assumed that recovery would cost about $1.4 trillion dollars, and he estimated that to be about $500 billion more than the production would be worth at $45 a barrel. Nevertheless, that was enough to get some of the wildcatters jumping into the area head first and the various financiers throwing more money their way. First it was the Bakken, then it was Eagle Ford, and now it is back to the old Permian Basin. David Blackmon of Forbes magazine on September 6, 2016 wrote: The reality for the Eagle Ford region is that, during the boom period beginning in 2009 and extending well into 2014, the great preponderance of drilling obligations were met, and the great majority of existing leases are now held by ongoing production…Thus, while this period of low commodity prices continues, operators are not going to be anxious to engage in additional drilling such leases. (That applies to all plays eventually.) In the Permian we see a different story. The region is so vast – roughly the size of the state of South Carolina – and there are so many recently-discovered play areas that many leases at this point are not in the status of being held by production. So a good number of the rigs that are currently active are drilling mainly in order to satisfy this lease condition, not necessarily because the wells are especially attractive to drill at current prices. Were it not for such obligations, it is likely that the Permian rig count would be lower than its current number, though still significantly healthier than we see in other major play areas due to superior economics. I guess superior economics is losing $500 billion at $45 per barrel. Don’t worry; it’s the bank’s money! How does the bank get the money? The Federal Reserve prints it, but for how much longer? However, all the players, including the Saudis, think that the price will eventually be back to $100. If that ever happens again, world demand will collapse again and force the price back down probably permanently below $50. This is a game of perseverance, and few will ultimately survive. Let’s focus again on supply because there is no problem servicing any level of demand, right? Since 2011, the Energy Information Administration has been trying to convince whoever wants to read their propaganda that the U.S. has enough tight oil reserves to satisfy demand for many years to come. And if demand increases, then they will just increase their estimate of reserves with no logical reason for the increase. They have a computer program that proves everything is just fine. We have all heard the saying, “garbage in, garbage out”, or in this case overly optimistic data in, then ridiculously optimistic forecasts out.
  4. 4. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 4 of 66 In February 2013, one of the many independent analysts trying to bring sensibility and accurate statistics to the shale oil-gas craze, J. David Hughes, published “Drill, Baby, Drill” (a play on the Republican moto of the day) through the Post Carbon Institute web site. The report was a critical analysis of shale gas and shale oil (tight oil) and the potential of a shale revolution. Thereafter, Hughes and Art Berman begin to question all the estimates of reserves and long term production rates of both U.S. tight oil and shale gas that both the EIA and IEA were announcing periodically. J. David Hughes is an earth scientist who has studied the energy resources of Canada for four decades, including 32 years with the Geological Survey of Canada as a scientist and research manager. His main focus has been on the accuracy of the U.S. reserve estimates coming from the IEA and their contractors and the production rates that the IEA is predicting far into the future. The following is from Hughes’ latest contribution, “2016 Tight Oil Reality Check”, which you can get a copy of free at the Post Carbon Institute web site. Over the past decade, Hughes has researched, published and lectured widely on global energy and sustainability issues in North America and internationally. His work with Post Carbon Institute includes: • a series of papers (2011) on the challenges of natural gas being a "bridge fuel" to renewables; • Drill, Baby, Drill (2013), which considered prospects for unconventional resources in the U.S.; • Drilling California (2013), which critically examined U.S. Energy Information Administration (EIA) estimates of technically recoverable tight oil in California’s Monterey Shale, which the EIA claimed constituted two-thirds of U.S. tight oil (EIA subsequently reduced its resource estimate by 96%); • Drilling Deeper (2014), which challenged the EIA’s expectation of long-term domestic oil and natural gas abundance with an in-depth assessment of all drilling and production data from the major shale plays through mid-2014; and • Shale Gas Reality Check, Bakken Reality Check, and Eagle Ford Reality Check (2015), updates to Drilling Deeper using data from the U.S. Department of Energy’s Annual Energy Outlook 2015. Art Berman’s main focus, since he has been actively involved in the oil and gas industry for years, is on how profitable these tight oil and shale gas plays really are compared to the hype promoted by the EIA and many of the CEOs of these exploration and production companies. From artberman.com: Arthur E. Berman is a geological consultant with thirty-seven years of experience in petroleum exploration and production. He currently is consulting for several E&P companies and capital groups in the energy sector. He frequently gives keynote addresses for investment conferences, boards of directors and professional societies. Back in 2011, I became interested in what these two professionals were saying and incorporated that knowledge into what I had been reading about the growing federal debt, the Federal Reserve
  5. 5. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 5 of 66 manipulations of interest rates in order to maintain the past growth era, and the ultimate consequences of all this manipulation of the free market. Since I have 43 years’ of broad experience mainly in the downstream sector of the U.S. petrochemical industry, my interest in the upstream sector has been on whether the production of the two feedstocks - crude oil and natural gas – could continue unabated at past rates and at prices that did not destroy future demand that propels the Petrochemical Industry. The EIA’s “Annual Energy Outlook 2016” and Hughes’ response to it in “2016 Tight Oil Reality Check” convinced me that a closer look is necessary at these numbers that the EIA has been tossing out to the marketplace like tossing free candy to children. U.S. Tight Oil Below is a picture of the prize – tight oil (shale oil) and shale gas in the “lower” 48 states. The average American wants it because it continues the lifestyle the Baby Boomers have become accustomed to and have brainwashed the X-Generation to conclude they can have also. The oil and gas industry definitely wants to give it to them, and the federal bureaucracy in the holy mecca of Washington, D.C. is trying to convince everyone they can have it without any noticeable pain. Let’s see if the present transportation world can continue unabated because that is basically what crude oil supports, as well as mostly Aromatics and Olefins to the industry downstream. In Appendix A is a spreadsheet I put together to make it easier for me to understand the EIA
  6. 6. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 6 of 66 numbers and the J. David Hughes concerns, which is summarized from “2016 Tight Oil Reality Check” as follows: Some general observations with respect to the assumptions and projections in the EIA’s AEO2016 reference case: • EIA assumes West Texas Intermediate (WTI) oil prices will remain low and will not exceed $100/barrel until 2031. • EIA assumes tight oil production will continue growing and that U.S. oil production will reach an all-time high of 11.3 mbd in 2040, of which tight oil will be 63%. Overall tight oil production from 2014 to 2040 has increased by 19% in AEO2016 compared to AEO2015 and by 37% compared to AEO2014. • The seven major plays analyzed in Drilling Deeper, which constituted 82% of AEO2014 projected tight oil production through 2040, have increased to 85% of the AEO2016 forecast. Production from plays other than the major seven has increased by 22% between the AEO2015 and AEO2016. • Forty-nine percent of tight oil production through 2040 is projected to come from the Bakken and Eagle Ford in AEO2016, compared to 51% in AEO2015—highlighting yet again that high quality tight oil plays are not ubiquitous. (Which is a major problem with these fantastic estimates.) • Considering that these forecasts are just 12 months apart, there is a lot of change in both recoveries through 2040 and the production profiles between projections, which raises questions about the robustness—or lack thereof—of the EIA’s forecasting methods. In Appendix A are my spreadsheet and the notes which explain the numbers. The Appendix will be in a separate report so you don’t have to scroll down and back up reading and then looking for the numbers in the Appendix. The numbers above the double horizontal line, except for the red and blue, come from Hughes’ “2016 Tight Oil Reality Check”. The numbers below the horizontal double line are my humble conclusions. I’ll explain them as we proceed. The second column is the EIA’s 2013 estimate of unproven technically recoverable reserves in billions of barrels. The third column is the total tight oil production from each of these plays from 2000 to June 2016 in billions of barrels. The fourth column is the approximate operating wells in each play as of June 2016. The fifth, sixth, and seventh columns are the EIA’s 2014, 2015, and 2016 estimates of the total production expected from each play for the years 2014 to 2040. The plays are broken down by Hughes into the major plays – Bakken, Spraberry, Eagle Ford, Wolfcamp, Austin Chalk, and Bone Spring plus Niobrara and “Others”. The “Others” category includes Monterrey and Woodford (STACK and STOOP have been added to the confusing names for all these areas) and other minor plays not specifically identified by the EIA. The “Others category alone sounds “fishy”, but read on. The eighth column is my guess at what Hughes might have arrived at if he had included 2014 to 2040 estimates of more than the Bakken and Eagle Ford “Most Likely” recovery estimates in his
  7. 7. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 7 of 66 2014 “Drilling Deeper” report, which he references in “2016 Tight Oil Reality Check”. I am putting words in his mouth with this and he may not agree, but nevertheless the following is how I arrived at the blue numbers. In Hughes’ 2014 “Drilling Deeper”, he estimated the “Most Likely” number of wells producing the “Most Likely” total production from 2012 to 2040 for both the Bakken and Eagle Ford plays. Get a free copy of “Drilling Deeper” at Post Carbon Institute web site to understand how he made those estimates. In “2016 Tight Oil Reality Check”, he estimated that the “Most Likely” recovery of tight oil from Bakken and Eagle Ford for the 27 year period 2014 to 2040 would be 5.7 and 7.0 billion barrels, respectively. This differs considerably from EIA’s Annual Energy Outlook (AEO) 2014, which estimated recovery of tight oil from Bakken and Eagle Ford for the 27 year period 2014 to 2040 at 7.9 and 9.7 billion barrels, respectively. So the ratios of Hughes 2014 estimate to EIA’s 2014 estimate are: For Bakken: 5.7/7.9 = 0.72 For Eagle Ford: 7.0/9.7 = 0.72 I arrived at Spraberry, Austin Chalk, Bone Spring, Niobrara, and others simply by multiplying the EIA’s 2014 numbers (in red) by 0.72 to get the numbers in blue, except for Wolfcamp. The USGS recently announced that 20 billion barrels of oil have a roughly 50% chance of existing in the Wolfcamp play. I don’t know if the EIA AEO2016 included that consideration in 5.98 billion barrels estimated to be recovered from 2014 to 2040. I doubt if they know either so I decided to be generous and use that number for Wolfcamp. The total estimated production for 2014 to 2040 sums to 33.76 billion barrels, which is an average rate of 3,426,000 barrels per day for 27 years. One of the main complaints Hughes had about the AEO2016 was the increase of the overall tight production from 2014 to 2016 of 37%. Where did that come from? Let’s look at the 2014, 2015, and 2016 numbers. Year Total Production from 2014 to 2040 Average Production Per Day for 27 Years 2014 41.05 billion barrels 4,166,000 2015 48.21 billion barrels 4,892,000 (17% increase from 2014) 2016 56.95 billion barrels 5,779,000 (37% increase from 2014) What is the source for increasing total tight oil reserves? Why did the 2014 number increase at all? Hughes doesn’t know, and he apparently follows this information closely. Now let’s compare the AEO2014, 2015, and 2016 average production per day numbers with 2015 actual average production. 2015 average production can be closely estimated by adding the 12
  8. 8. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 8 of 66 2015 data points from Figure 3 and dividing by 12. The answer comes to about 5.3 million barrels per day average for 2015 – close enough, huh? So what the EIA is telling us is that according to the magical numbers that appeared all of a sudden in the AEO2016 report, the average tight oil production for the U.S. will be about 5.78 million barrels per day from 2014 through 2040. I don’t believe this has any relationship to reality, and will show the data for this conclusion all the way to the end of this report. Hughes and others have pointed out the technical realities of tight oil (and shale gas also, which I will address next report) production as follows: From “2016 Tight Oil Reality Check” – Fundamentals Section” Key fundamentals used in projecting future production of tight oil plays in Drilling Deeper were: • Rate of well production decline: Tight oil plays have high well production decline rates, typically in the range of 75-85% in the first three years. • Rate of field production decline: Tight oil plays have high field production declines, typically in the range of 30-45% per year, which must be replaced with more drilling to maintain production levels. • Average well quality: All tight oil plays invariably have “core” areas or “sweet spots” where individual well production is highest and hence the economics are best. Sweet spots are targeted and drilled off early in a play’s lifecycle, leaving lesser quality rock to be drilled as the play matures (and requiring higher oil prices to be economic); thus the number of wells required to offset field decline inevitably increases with time. Although technological innovations including longer horizontal laterals, more fracturing stages, more effective additives, and higher volume treatments have increased well productivity in the early stages of the development of all plays, they have provided diminishing returns over time and cannot compensate for poor quality reservoir rock. The decline in oil prices starting in mid-2014 led oil producers to focus more on sweet spots, disproportionately depleting high- productivity drilling locations compared to the overall number of potential drilling locations in each play. • Number of potential wells: Plays are limited in area and therefore have a finite number of locations that can be drilled. Once the locations run out, production goes into terminal decline. • Rate of drilling: The rate of production is directly correlated with the rate of drilling, which is determined by the level of capital investment. The decline in oil price starting in mid-2014 resulted in a major decline in drilling rates in most plays, which resulted in production declines as intrinsic field decline overcame additions from new wells. I believe the rate of drilling issue is the most important, and not being able to maintain past rates will be one of the reasons tight oil production can’t continue to climb. Now I have only addressed tight oil so far, but that is not all the U.S. consumer consumes.
  9. 9. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 9 of 66 Total U.S. Oil Production Look at Figure 1, “U.S. Total Crude Oil Production”, and notice how total U.S production was declining rapidly from 1985 to 2008 before the tight oil production ramp-up gift, care of the Federal Reserve’s latest easy money (financial heroin) injections. U.S. total production rate had fallen from almost 9 million barrels per day (thanks to Alaska’s pipeline) in 1985 to about 5 million barrels per day in 2008. Of course, even in 2008 most of that production was “conventional” from vertical wells. So let us assume conventional production rate in 2008 was somewhat less than 5 million barrels per day in 2008 and has decreased further to 4.1 million barrels per day in 2016 (read note 15 in Appendix A). This makes sense to me when you look at EIA data from 2010 to 2015 in the “Crude Oil Production” section broken down by “PADD” and state production. Here is what you see from what used to be the three major contributors to “conventional” oil production. • Federal Offshore (PADD 3) (this is Gulf of Mexico): 2010 production - 1,552 thousand barrels per day and 2015 production – 1,515 thousand barrels per day. So there has been no increase there in the last five years. • Alaska (South Alaska + North Slope): 2010 production - 600 thousand barrels per day and 2015 production - 483 thousand barrels per day. So this area is going down fast. • Federal Offshore (PADD 5) (California): 2010 production - 59 thousand barrels per day and 2015 production – 31 thousand barrels per day. California is no longer that interested in oil. They are into fruit and vegetables, and a growing number of nuts. You can’t drill on the east coast or near Florida. From the Washington Post Health & Science section: By Juliet Eilperin August 13, 2012 Interior Secretary Ken Salazar on Monday announced the first comprehensive plan to manage the National Petroleum Reserve in Alaska, allowing for new drilling on half of the nearly 23 million- acre reserve while putting the rest off-limits to oil and gas exploration. The move — which leaves open the possibility of constructing a pipeline to transport oil and gas extracted from the Chukchi Sea onshore — drew praise from environmentalists but sharp criticism from oil and gas proponents who said it would restrict the industry’s ability to tap the nation’s hydrocarbon resources. Then there is this from and.com: Shell's Chukchi failure the latest in decades-long series of offshore Arctic flops Author: Yereth Rosen Updated: May 31 Published September 29, 2015
  10. 10. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 10 of 66 After pouring billions of dollars into offshore Arctic leases and a complicated drilling program that used the latest available technology, oil explorers were confident that they would strike a gusher and open up a new northern petroleum frontier. The plan went bust and the explorers walked away. Royal Dutch Shell in the Chukchi Sea in 2015? No, it was the notorious Mukluk flop, which became known as the world's most expensive dry hole. How about this? From Indian Country Media Network: Oil Giant Chevron Cancels Plans to Drill in Beaufort Sea in Canadian Arctic ICMN Staff • December 22, 2014 Chevron Corp. has canceled its plans to drill for oil in the Beaufort Sea because of plummeting oil prices, according to reports. It is the fourth oil conglomerate to suspend offshore drilling in the Arctic over the past couple of years, though this year’s reason is different. In February 2013 Royal Dutch Shell announced a halt to drilling in the Chukchi Sea after a string of equipment failures, while Norwegian’s Statoil announced a postponement in its own drilling plans. ConocoPhillips announced last April that it would not drill exploratory wells off of Alaska’s Arctic coast in 2014. Also, from NRDC, Joshua Axelrod, June 29, 2015: In a surprise announcement, Imperial Oil and its partners--ExxonMobil and BP--informed two Canadian regulators that they would "defer the proposed Beaufort Sea Joint Exploration Drilling Program." NRDC engaged early in the regulatory process to highlight the severe risks posed by Imperial's proposal to commence deep sea drilling in the Canadian Arctic without essential safeguards (such as relief wells). By stopping this industry proposal to waive a critical safeguard for offshore drilling in Canada, this victory means that deep water Arctic exploration will for--the time being--not put these fragile waters or our climate at risk. Rex Tillerson and the Exxon top brass know all this about the slowdown in conventional oil discoveries, so do the other CEOs of the major oil companies. From OilPrice.com: BP CEO Dudley: We’ll Double Our North Sea Oil Production By 2020 By Tsvetana Paraskova - Dec 08, 2016, 3:51 PM CST UK’s oil major BP (NYSE:BP) will double its production in the North Sea to 200,000 barrels of oil per day, chief executive Bob Dudley said in an interview with Energy Voice in Aberdeen on Wednesday.
  11. 11. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 11 of 66 “You will see portfolio changes for us in the North Sea, but you may see us invest in other projects as people approach us about joining them. So I think there’s a mix, but we should double our production by 2020 from where it was in 2015,” Dudley said. The manager went on to add: “We should be over 200,000 barrels a day in 2020 and by then I’m hopeful our exploration program will lead to more things to do.” Hope is right! Good luck with that! Technology will save us! Let me tell you about technology. In the summer of 1969, I witnessed the test of the first stage of the ill-fated Apollo 13. The Boeing Co. “Michoud Facility” in New Orleans was winding down that summer. The auditorium style work area was filled with engineers and technicians that would eventually be looking for jobs in other industries. Why did we stop at Apollo 17? It cost too much! And maybe another reason they aren’t telling! Nevertheless, eventually it comes down to priorities. In the future, the priorities may come down to what they were pre WWI, food and shelter. Everything else may be a luxury too expensive for most. Crude Oil Imports to the U.S. Wait a minute; can’t we import the oil we need? We did in the past, and we still do. Go back to Figure 1 and look again at total US crude oil production, then look at Figure 6, “U.S. Imports in Barrels Per Day”. Domestic crude oil production has been dropping since 1985 and bottomed in 2008. Imports starting rising again in 1985 after recovery from the early 1980s economic recession and maxed out in 2005. The tight oil “revolution” has decreased the need for imports; however, in 2015 we still imported at a rate of 7.36 million barrels per day. Yea sure, we are energy independent. Can we continue to rely on imports at even the 2015 rate? Let’s look at the past major importers of crude oil. Saudi Arabia Take a look at Figure 9, “Saudi Arabia Monthly Oil Production”. Production has increased from below 8 million barrels per day to above 10.5 million barrels per day recently; however, I believe Saudi Aramco (SA) is paying a heavy price for that. SA used to be the number one importer of oil to the U.S. It dropped to second place way back in the 1990s after Canada’s Alberta province started to ramp up production. The following is from a report made by the Center for Strategic Studies published in October 2005.
  12. 12. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 12 of 66 Center for Strategic and International Studies Arleigh A. Burke Chair in Strategy Saudi Arabia's Upstream and Downstream Expansion Plans for the Next Decade: A Saudi Perspective Saudi Aramco has 85 oil fields, 320 reservoirs within those fields and approximately 1,000 producing wells. More than 50% of reserves are located in eight fields. Saudi Aramco’s total depletion rate to date is estimated to be between 28-30 percent. Currently, Saudi Aramco crude oil production capacity is approximately 10.65 million b/d, which would bring Kingdom-wide capacity to more than 10.9 million b/d when its share of the Neutral Zone is included. Saudi Aramco is confident that it can produce up to 15 million b/d in the future and continue that level of production for the next 50 years. In June 2005, Aramco’s senior vice president of gas operations, Khalid al-Falih, indicated that Saudi Aramco would increase production capacity to more than 12 million b/d by 2009, or more if demands required. Moreover, Falih stated that Saudi Aramco would have 90 drilling rigs operating by early 2006. That is more than twice the number in operation in 2004, and three times the number in operation during the previous decade. These plans reflect a major change in Saudi strategy. Up until 2004, Saudi Aramco operated under the assumption that maintaining maximum sustainable capacity (MSC-90) of 10 million b/d provided an ample cushion of capacity, given that market conditions since 1990 rarely warranted Saudi Aramco production much above 8 million b/d and sometimes dictated lower production. In fact, although world oil consumption rose by 12.5 million b/d between 1994 and 2004, Saudi Arabia’s production in 2002 was more than 100,000 b/d lower than it had been in 1994, thanks to competition from other suppliers and Saudi Arabia’s leading role in supply management. It is only in the past two-and-half years that Saudi Arabia has been able to regain some of the market share it lost in the previous decade. Accordingly, it was not until mid-2004 that Saudi Aramco began to reclassify one of its increments of new production—Qatif and Abu Safah—as an addition to capacity rather than a replacement for previous production declines. In September 2004, Petroleum Minister Naimi announced that henceforth Saudi Aramco would resort to intensified drilling in currently produced reservoirs to make up for past declines—the equivalent of repairing what they had rather than completely replacing it. As I understand it, SA made considerable investments after 2006 to increase crude oil production capacity to the levels that Falih had predicted. As you can see from Figure 9, production level has not reached the levels that SA was confident it could produce, and it never will. There are those who think that the production level recently attained is pushing the limits of their production system. Only SA knows, but they bet on these high production levels and they also bet they could outlast U.S. tight oil and they lost the bet. Now, they have recently announced they will agree to cut back on production. I think there is a reason for cutting back more necessary than being cooperative with other OPEC members to raise the price of oil. Now SA is talking about an IPO to sell part of their operations. From alamanarnewsEN, dated December 19, 2016:
  13. 13. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 13 of 66 The world’s biggest oil company is planning to sell shares in the entire business and not just in its refining or distribution operations, Bloomberg reported. The New York-based media outlet quoted Aramco’s chief executive officer as saying that the company will announce “very soon” a list of investment banks and consultants advising it on the initial public offering. Aramco CEO Amin Nasser did not specified a date, but he said that the Saudi Arabian Oil Co. plans to list shares on the Saudi stock market and is also considering foreign bourses in London, Hong Kong and New York. Aramco’s plan to sell a stake of about 5 percent could value the company in trillions of dollars, Bloomberg reported. “We need to do a lot of internal work to prepare for this listing,” Nasser said in Bahrain. “We are listing a part of the entire company, and not just downstream,” he said, referring to operations including refining, marketing and distribution. Saudi Arabia, under pressure from lower crude prices, wants to sell shares in Aramco in early 2018 as part of an effort to generate revenue and reform its economy. The government hopes to raise about $100 billion from the IPO of its flagship asset. The planned sale, which Deputy Crown Prince Mohammed bin Salman announced in April, could be the world’s largest share offering, according to the interview. “There are no obstacles for the IPO of Aramco,” Nasser said. “It’s going very smoothly, and we are on target. We achieved a lot of progress so far. People have to appreciate the size of Aramco and its complexity.” The company will review its budget “shortly,” he said. “Our spending program is active and evolving.” Source: Bloomberg This news combined with talk in the last few years about possible Saudi investments in solar and the long term strategy to build a petrochemical industry to rival the U.S. means I don’t think the U.S. refiners can expect much availability to Saudi crude oil in the future. They will continue to supply their Motiva refineries, but refining competitors will have to look elsewhere for feedstock. Venezuela Look at Figure 10, “Venezuela Monthly Oil Production”. In 2015, Venezuela was the third largest importer of oil to the U.S. after Canada and Saudi Arabia, but it is a hopeless case vying to become another Cuba. From theguardian, May 13, 2016:
  14. 14. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 14 of 66 Venezuelan President Nicolas Maduro declared a 60-day state of emergency on Friday due to what he called plots from within the OPEC country and from the US to topple his leftist government. Flanked by his ministers and a statue of Chavez, Maduro signed a state of emergency and extended a state of economic emergency to protect the country from foreign and domestic “threats”, without providing details. From theguardian, December 17, 2016: Venezuelan president Nicolas Maduro on Saturday suspended the elimination of the country’s largest denomination bill, which had sparked cash shortages and nationwide unrest, saying the measure would be postponed until early January. About 40% of Venezuelans do not have bank accounts, and so cannot use electronic transactions as an alternative to cash. Adding to the chaos, Venezuela has the world’s highest rate of inflation, meaning large bags of cash must be carried around to pay for basic items. Not even China is going to risk investing in Venezuela. From CNN Money: China is cutting off cash to Venezuela by Patrick Gillespie @CNNMoney September 30, 2016 After pouring billions into Venezuela over the last decade, China is cutting off new loans to the Latin American nation. It's a major reversal of relations between the two nations, experts say. It also comes at the worst time for Venezuela, which is spiraling into an economic and humanitarian crisis. "China is not especially interested in loaning more money to Venezuela," says Margaret Myers, a director at Inter-American Dialogue, a Washington research group that tracks loans between China and Latin America. The U.S isn’t getting any more out of Venezuela, and the imports probably won’t even continue at the present rate. Mexico Mexico’s crude oil production has been declining for some time, as shown in Figure 11, “Mexico Crude Oil Production”. From Eurasia Review, September 24, 2016: Mexico is one of the largest producers of petroleum and other liquids in the world, the fourth- largest producer in the Americas after the United States, Canada, and Brazil, and an important partner in U.S. energy trade. In 2014, Mexico accounted for 781,000 b/d, or 11% of U.S. crude oil imports.
  15. 15. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 15 of 66 Mexico’s oil production has steadily decreased since 2005 as a result of natural production declines from Cantarell and other large offshore fields. The rate of total production decline has slowed in the past several years. In December 2013, in an effort to address the declines of its domestic oil production, the Mexican government enacted constitutional reforms that ended the 75-year monopoly of Petroleós Mexicanos (PEMEX), the state-owned oil company. From OilPrice.com: Can Mexico Reverse Its Steep Output Decline? By Qarnain Foda - Aug 09, 2016 Cantarell consists of four fields: Akal, Nohoch, Chac, and Kutz—all which are formed of high permeability fractured carbonate rock. Production from the Ku Maloob Zaap field has helped in offsetting the rapidly declining production from the Cantarell field, which reached its peak at 2.2 million bbls/day and by 2015 had dropped to 256,000 bbls/day. One of the main reasons for the decreasing production is due to the existence of a giant natural gas bubble that was maintaining pressure across the reservoir for the first 20 years of the field. In an effort to counteract the decreasing reservoir pressure, PEMEX developed and installed the world’s largest nitrogen generation plant used to maintain reservoir pressure. The Cantarell field now experiences increasing gas and water production, and is being used as lessons learned in developing reservoir management guidelines to be applied to the Ku Maloob Zaap Field. This declining production has also reduced Mexico’s available exports to the U.S. as shown in Figure 6, “U.S. Crude Oil Imports in Barrels Per Day”. The Mexican government is trying to entice foreign investments now that they realize that state-run oil governments don’t work well. Ask Venezuela and Brazil about that. From OilPrice.com: Now Is The Time To Invest In Mexico’s Oil Boom By James Burgess - Dec 13, 2016 From the supermajors to the small-caps, the interest is expansive and the competition is only set to intensify further.
  16. 16. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 16 of 66 The December 5th auction saw the who’s who of oil and gas giants bid, with Australia’s BHP Billiton outbidding British Petroleum (BP) to become Mexican state-owned Pemex’s first private partner in deep-water exploration and production in the massive Trion oilfield, discovered in 2012 and believed to contain 485 million barrels of commercial reserves alone. And this Gulf of Mexico offering was only a small part of the deep-water sale—another 10 deep-water blocks estimated to be worth $10 billion were up for auction, and the winning bidders included ChevronCorp., France’s Total SA and Exxon Mobil Corp., Norway’s Statoil and BP Plc, and Murphy Oil Corp., Ophir Energy and Malaysia’s Petronas Carigali. With every new change in direction in the world oil industry, there is always the hype, especially from the small-fries about a new savior for the industry accompanied by the usual gross overestimates to draw in the shrinking available capital. It’s always “bigger than anything in history”. “Right now we’re in the early stages of an oil and gas opportunity that will be bigger than anything in history,” says International Frontier Resources Corp. (OTQB: IFRTF) President and CEO Steve Hanson While the supermajors have their radar locked on massive deepwater discoveries offshore auctioned off successfully on December 5th, juniors such as International Frontier Resources Corp. are focused on Mexico’s onshore bonanza. As first movers, IFR is setting itself up for success with aggressive oil field development. It’s also setting the stage for an advantage in the next auction round. And of course, the EIA jumped on the hype bandwagon some time ago after Mexico announced opening their oil fields to outside investors. From the EIA website: AUGUST 25, 2014 Energy reform could increase Mexico’s long-term oil production by 75% On August 11, Mexico's president signed into law legislation that will open its oil and natural gas markets to foreign direct investment, effectively ending the 75-year-old monopoly of state-owned Petróleos Mexicanos (Pemex). These laws, which follow previously adopted changes in Mexico's constitution to eliminate provisions that prohibited direct foreign investment in that nation's oil and natural gas sector, are likely to have major implications for the future of Mexico's oil production profile. As a result of the developments in Mexico over the past year, EIA has revised its expectations for long-term growth in Mexico's oil production. The changes in EIA's assessment of Mexico's liquids production profile are profound. Last year's International Energy Outlook projected that Mexico's production would continue to decline from 3.0 million barrels per day (MMbbl/d) in 2010 to 1.8 MMbbl/d in 2025 and then struggle to remain in the range of 2.0 to 2.1 MMbbl/d through 2040. The forthcoming Outlook, which assumes
  17. 17. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 17 of 66 some success in implementing the new reforms, projects that Mexico's production could stabilize at 2.9 MMbbl/d through 2020 and then rise to 3.7 MMbbl/d by 2040—about 75% higher than in last year's outlook. Actual performance could still differ significantly from these projections because of the future success of reforms, resource and technology developments, and world oil market prices. The EIA’s projections are profound all right, and they are probably just as accurate as projections about the Monterrey play’s reserves as The Los Angeles Times found out. U.S. officials cut estimate of recoverable Monterey Shale oil by 96% May 20, 2014 Federal energy authorities have slashed by 96% the estimated amount of recoverable oil buried in California's vast Monterey Shale deposits, deflating its potential as a national "black gold mine" of petroleum. Just 600 million barrels of oil can be extracted with existing technology, far below the 13.7 billion barrels once thought recoverable from the jumbled layers of subterranean rock spread across much of Central California, the U.S. Energy Information Administration said. The energy agency said the earlier estimate of recoverable oil, issued in 2011 by an independent firm under contract with the government, broadly assumed that deposits in the Monterey Shale formation were as easily recoverable as those found in shale formations elsewhere. The estimate touched off a speculation boom among oil companies. The new findings seem certain to dampen that enthusiasm. See, this is how you keep Ponzi schemes going. Make big talk that you can’t back up in the long run. We will see how the Mexico deals work, but my guess any success in increasing oil production will go to the petrochemical industry being built up on the east coast of Mexico.
  18. 18. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 18 of 66 Canada In the 1950s, Canada became a major oil producer after the “Leduc” discoveries of the late 1940s put Alberta on the world petroleum map. From Wikipedia: By 1950, Alberta was one of the world's exploration hot spots, and seismic activity grew until 1953. At its recent peak in 1973, more than 78 per cent of Canadian oil and gas production was under foreign ownership and more than 90 per cent of oil and gas production companies were under foreign control, mostly American. Despite billions of dollars of investment, its bitumen - especially within the Athabasca oil sands - is still only a partially exploited resource. By 2025 this and other unconventional oil resources - the northern and offshore frontiers and heavy crude oil resources in the West - could place Canada in the top ranks among the world's oil producing and exporting nations. In a 2004 reassessment of global resources, the United States' EIA put Canadian oil reserves second; only Saudi Arabia has greater proved reserves. In 2014, the EIA now ranks Canada as third in World Oil Reserves at around 175 billion barrels, while Saudi Arabia is 2nd with around 268 billion barrels and Venezuela is ranked first with around 297 billion barrels of reserves. Having oil reserves is great. Getting them out of the ground, provided the local owners allow you to, at a price that does not destroy demand is a different story. However, Canada has increased production since the mid-1990s, and overtook Mexico in production rate by 2008 as shown in Figure 12, “Mexico Vs Canada Oil Production”. As of 2012, Canada was the poster boy for the “new oil age”. From The Globe and Mail: PETER TERTZAKIAN Canada again a focus of a new Great Scramble for oil Published Wednesday, Jul. 25, 2012 Some of the old names, like Exxon Mobil, Royal Dutch Shell, Chevron and BP, are still key players, but new ones have emerged, like CNOOC, China National Petroleum Co., and Petronas of Malaysia, among many others trying to secure their oil future. Instead of the Middle East, the new scrambling grounds are places like Africa, and the “stans” of the former USSR. And once again Canada is a focus, as one of the few politically stable, free-market oil suppliers that respects the rule of law. This situation was ideal for the insatiable consumer, the American public. The Canadians are just north of here! The problem was how to get the oil south in significant quantities. The other problem was that a large portion and the least expensive portion of the “oil” was the Alberta Oil Sands and not really oil. It was bitumen. From Oil Sands magazine:
  19. 19. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 19 of 66 CANADIAN HEAVY OIL PRODUCTION Almost 80% of Western Canada's oil production is heavy, representing about 2.8 million bbl/day. A majority of this oil is heavy sour crude from the oil sands. About 400,000 bbl/day of heavy oil is produced from conventional wells. About 35% of Alberta's heavy oil is upgraded into light synthetic sweet crude oil (SCO). Two examples of synthetic crude from the oil sands are Syncrude Sweet and Albian Premium Blend, both ultra-low in sulphur and comparable in quality to WTI. The remaining 65% of Western Canada's heavy oil is blended and sold to market (primarily the US) as heavy sour crude. This includes Western Canadian Select, diluted bitumen and heavy oil produced from conventional wells. These streams are closest in quality to Mayan heavy crude produced in Mexico. About 95% of Canada's heavy oil is exported to the US. This includes conventional heavy oil, diluted bitumen and Western Canadian Select. In contrast, about 70% of upgraded bitumen is destined for US refineries. A majority of Canada's conventional light production is processed in Canadian refineries. Over 60% of Canada's oil exports are destined for PADD II refineries in the US Midwest. There are 26 refineries in the PADD II area which is centered around Chicago, IL. The region has a refining capacity of approximately 3.8 million bbl/day. PADD III refineries in the US Gulf Coast previously sourced most of their heavy oil from Venezuela and Mexico. Since both countries have declining production profiles, PADD III has become increasingly reliant on Canadian heavy oil, which now represents 15% of their feedstock. Due to constrained pipeline infrastructure, Gulf Coast refineries rely heavily on crude-by-rail and has been the beneficiary of Enbridge’s Flanagan South pipeline which runs from Cushing, OK to the Houston area. Should the Keystone XL pipeline ever be completed, more of Canada's heavy oil can be sold to the PADD III area which has almost triple the refining capacity of PADD II. This would increase demand considerably for Canadian heavy crude and improve the sale price. There are all types of oil. The three main categories according to specific gravity are: Light crude with a gravity lighter than 31.1 deg API Medium crude having a gravity between 22.3 deg API and 31.1 deg API Heavy crude having a gravity below 22.3 deg API The least expensive ‘”oil”, and the oil that was being pushed by Canadian suppliers, was gravity below 10 deg API (oil API below 10 sinks in water), and it is almost solid at even Gulf Coast temperatures. Another problem was the Midwest refineries as of 2012 were designed for the
  20. 20. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 20 of 66 medium crude. Most of the Gulf Coast refining capacity had been modified for heavy crude, but not that heavy and not “oil” with has much sulfur as bitumen contained. The push was already in progress for low sulfur gasoline with low sulfur diesel to follow. Also, what to do with all the petroleum coke resulting from processing Canadian heavy oil? So now what? You see just finding oil is half the problem! Getting the oil to the refinery and then processing it at a profit is the other even more difficult half of the problem. Also, there are inexpensive oil reserves of pre 2000 and earlier (Beverly Hillbillies style) and then there are increasingly expensive reserves to both produce and to process downstream. Most of the world’s refineries were originally built for Beverly Hillbillies “bubbling crude”. Those days are long gone! It gets progressively more difficult from now on. By 2013, U.S. refineries and storage terminals started planning receiving facilities for Canadian bitumen. From RBN Energy: Go Your Own Way – CN Railroad Facilities To Offload Crude On The Gulf Coast Sunday, 08/25/2013 Published by: Sandy Fielden Five large-scale rail terminals planned or being constructed in Western Canada will be able to ship up to 550 Mb/d of crude by 2015. Most of that crude will be headed to the Gulf Coast. If crude by rail shipments from Canada are going to compete with pipeline alternatives then the ability to ship bitumen crude raw without diluent will be an important advantage. Yet only about 170 Mb/d of rail terminal capacity is currently built or being developed on the Gulf Coast that can offload raw bitumen using special heating equipment. By mid-June, bitumen rail transport south into the United States had begun. From Desmog: Tar Sands on the Tracks: Railbit, Dilbit and U.S. Export Terminals By Ben Jervey • Tuesday, June 17, 2014 Last December, the first full train carrying tar sands crude left the Canexus Bruderheim terminal outside of Edmonton, Alberta, bound for an unloading terminal somewhere in the United States. While shale oil, predominantly from the Bakken, has driven the trend, Canadian tar sands producers are increasingly turning their attention to rail. Hobbled by limited pipeline capacity out of Alberta, and frustrated by their inability (so far) to ram the Keystone XL pipeline through the American heartland, tar sands producers are signing contracts with Canadian rail operators. Canadian National Railway is getting the lionshare of the business. Downstream, rail terminals are similarly adapting to handle shipments of tar sands crude. From the Runaway Train report:
  21. 21. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 21 of 66 Terminals designed to unload tar sands crude are currently concentrated in the Gulf Coast region, where the biggest concentration of heavy oil refining capacity is located… The Gulf Coast terminals have about one million bpd of unloading capacity today, set to grow to over two million bpd in 2016. Some of this capacity is at refineries such as those operated by Valero in Port Arthur, Texas, and St. Charles, Louisiana. Valero has ordered 1,600 insulated and coiled tank cars specifically for hauling tar sands crude to its refineries. The Gulf Coast also has significant midstream capacity on the Mississippi River, where crude oil, including tar sands crude, is unloaded from trains and pumped from storage tanks into local pipelines or loaded onto barges that deliver to coastal refineries via the Intracoastal Waterway. Meanwhile, refineries on the Atlantic and Pacific coasts are angling to get in on the action, hoping that their shipping advantages to Europe and Asia respectively will prove appealing to tar sands producers. Tar sands producers are particularly motivated to get their crude to coastal terminals and refineries for export. As we’ve covered in the past on DeSmogBlog, tar sands companies want to export their product, because the low-grade crude is more easily refined into diesel, which has a much larger market in Europe and Asia. Railbit vs. Dilbit As this still-nascent segment of crude-by-rail develops, it’s worthwhile to take a moment to understand the distinction between a couple of different tar sands products that are being shipped by train. The vast majority of tar sand crude-by-rail shipments thus far have been diluted bitumen, or dilbit. Dilbit, which you have heard of as the tar sands crude that is already funneling through North American pipelines, is composed of the sticky, viscous tar sands bitumen, which is then mixed with about 30 percent diluent, allowing it to flow through pipelines. This mixture of dilbit is particularly volatile and abrasive, and reports have pointed to it being more likely to cause leaks and spills and explosions during transport. Railbit is a relatively new designation for crude, and is defined as bitumen that has been mix with roughly 17 percent diluent. Moving railbit, rather than dilbit, saves tar sands shippers about half of the so-called “diluent penalty,” or the cost of adding the diluent to the mix. So why are most trains still loaded with dilbit? Because to this point, most loading terminals are still being fed by feeder pipelines or trucks that can only handle this more watered down blend. That and the fact that special loading and unloading facilities are necessary to handle railbit, which is more viscous and needs to be heated in special tank cars to be unloaded. Some downstream terminals are making these investments, seeing railbit as a viable alternative going forward, but today dilbit is still dominant.
  22. 22. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 22 of 66 While Canada was trying to widen their market by getting bitumen to the Gulf Coast, they were already supplying Midwest refineries by pipeline by mid-2013. From Midwest Energy News 10/14/2013 In July piles of petcoke made bi-national headlines as dark clouds swirled over the Detroit River by the Ambassador Bridge leading to Canada. That petcoke was from the Marathon Detroit Oil refinery, which has expanded to process tar sands oil. In August, Southeast Chicago residents saw similar clouds themselves. One local resident posted a photo on Facebook after an August 30 wind storm, showing a billowing thick black haze. Locals say the amount of petcoke has skyrocketed as BP Whiting’s refinery just across the border in Indiana nears completion of a $3.8 billion upgrade to process more tar sands oil. Still in the works is the refinery’s new coker, which will be the second largest in the world and process 102,000 barrels of oil per day, creating petcoke as the tar sands are heated to 900 degrees F. Detroit’s Marathon refinery wasn’t producing petcoke before its expansion, according to the report, but now produces 1,720 tons per day while the Phillips 66 refinery in Wood River, Illinois, is increasing its petcoke output from 1,300 to 5,700 tons per day. Since then other Midwest refineries have made revisions to increase Canadian heavy crude consumption, and Canadians continue to find ways of selling more to Gulf Coast refineries via pipeline since rail shipments have decreased since 2015 as shown in Figure 13, “Canada’s Exports to U.S. by Rail”. West Canadian producers were counting on the Keystone XL pipeline, and after that was halted, they have been trying to find ways around the bottleneck. From Reuters: CERAWEEK-TransCanada mulls moving Canadian crude to Louisiana –exec By Kristen Hays | HOUSTON, APRIL 21 TransCanada Corp is mulling ways to get Canadian crude to Louisiana refineries now that the company has forged a deal to increase its reach to southeast Texas Gulf Coast plants, its head of liquids pipelines said on Tuesday. Paul Miller, president of liquids pipelines at TransCanada, said in an interview at the annual IHS CERAWeek energy conference in Houston that Louisiana's 3 million barrels per day refining market could be the company's next target for Canadian crude deliveries, possibly via an extension of its 700,000 bpd Oklahoma-to-Texas MarketLink pipeline. That could connect to a new TransCanada terminal, or to a partner's operation, much like TransCanada's plan to connect its new Houston terminal to Magellan Midstream Partners' terminal and distribution network.
  23. 23. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 23 of 66 Despite the various bottlenecks to get Canadian crude to Gulf Coast refineries, Canadian heavy oil has increased its share of imports to the U.S. Gulf Coast. See Figure 14, “Canada’s Increased Exports to U.S. Gulf Coast”. Canadian crude oil will play an increasing role in U.S. feedstock because it is priced right as shown in Figure 15, “Canadian Heavy Crude Oil Price Vs WTI”. The Canadian share of Gulf Coast imports will significantly increase in the future until it is very likely that Gulf Coast and Midwest refineries, except for Saudi Aramco’s Motive refineries, will be having to blend a combination of Canadian heavy crude and U.S. light to very light (+45 API) tight oil plus whatever various imports can be added to the mix. This is getting complicated! This isn’t like it used to be with mainly various sources of mainly medium grades with low sulfur! That’s right, and the situation will only get worse. Can Canadian production bailout U.S refining long term all by itself as tight oil production starts to rapidly decline within ten years? Of course not! “North to Alaska, to Alaska way up north!” Yes, it is on to Alaska’s National Petroleum Reserve and north of Alaska to the Chukchi and Beaufort Seas. There is a major problem with that, other than environmentalists blocking right of ways and liberal politicians, and I’ll address that further down the discussion. Other OPEC and Non-OPEC Countries The following is a list of the top ten importers of crude oil to the United States in 2015: Rank Country Average Import Rate, Million Barrels Per Day 1 Canada (I’m your butterfly!) 3,716 2 Saudi Arabia 1,059 3 Venezuela 827 (the country is falling apart!) 4 Mexico 758 (and falling from 1,284 in 2010) 5 Colombia 395 6 Russia (Rex Tillerson is coming!) 371 7 Ecuador 231 8 Iraq 229 9 Brazil 215 (Where’s all that oil offshore?) 10 Kuwait (Now you understand why 204 (433! Not much for two wars! Two Persian Gulf Wars?) Augustus would have done better.)
  24. 24. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 24 of 66 The has-beens, Norway and the U.K., combined are down to 184. But, BP’s Dudley, an American Baby Boomer to boot, says the North Sea is not finished and he’ll double his production in the North Sea. “Rah,rah,re, kick um in the knee - Rah,rah,ras, kick um in the… whatever!” Give me a break! Colombia Colombia is the “new kid on the block” and their production and exports to the U.S. have increased since 2008, but their future prospects are not good. From OilPrice.com: Colombia’s Oil Dreams Fall Short By Nick Cunningham - Dec 17, 2015 The story of Ecopetrol is one of disappointment for Colombia’s oil sector. The company used to be entirely state-owned, but was opened up years ago in order to boost production. In 2003, the company was freed from acting as the country’s energy regulator, allowing it to focus on exploration and production. A few years later it was partially privatized, opening up the company for international investment. The liberalization also allowed foreign companies to come into Colombia and take 100 percent ownership stakes in oil fields. However, from there, Colombia’s oil production leveled off. Production has been flat since 2014, and is expected not to move by much through 2016. Ecopetrol’s failure to continue to ramp up output has disappointed its investors. “They just haven’t found oil, it’s as simple as that,” Rupert Stebbings of Bancolombia SA, told Bloomberg. “The whole oil sector got massively over-bought, and people assumed that one day they’d hit an absolute gusher.” Colombia has the potential for shale production, but that too does not look profitable at today’s prices. For Colombia and Ecopetrol, any production gains from today’s base are likely many years away. With the ongoing “Oil Glut”, nothing has changed recently.
  25. 25. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 25 of 66 Ecuador Don’t expect much from this country in the future. From OilPrice.com: Ecuador Gutted By Low Oil Prices: Rig Count Down To One By SRS Rocco Report - Feb 11, 2016, There’s an ongoing catastrophe taking place in Ecuador. Not only has a significant part of its Amazon rainforest has been polluted by several oil spills, but the low oil price has totally gutted the oil industry. This is a big problem for Ecuador because 50 percent of its exports and 30 percent of its government revenues come from oil. According to the article, Ecuador Reveals Pain Inside OPEC: It’s Pumping Oil At A Loss: President Rafael Correa said on Tuesday that the South American nation is receiving as little as $30 a barrel for its crude, while production costs average about $39. The warning comes after several other members of the Organization of Petroleum Exporting Countries, including Algeria and Libya, said the group should consider holding an emergency meeting to respond to the drop in oil prices. While the drilling rig count in the U.S. and world has fallen considerably over the past 18 months, nothing can compare to the collapse that has taken place in Ecuador. When oil was trading over $100 in August 2014, Ecuador had 27 drilling rigs working in the country. Today… they have one. While Ecuador’s oil troubles are worse than other oil exporting countries, due to shortsighted government energy policies. At this point, it looks like it could get quite a lot worse for Ecuador before it gets better. For now, it seems the only thing Ecuador can do is join Venezuela’s call for an emergency OPEC meeting in the hope that oil prices will recover. Nothing has changed.
  26. 26. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 26 of 66 Iraq First it was Saddam Hussein, and now it’s ISIS. This is not a solvable problem unless the enemy is totally destroyed. Both Trump and Putin now know who the real, common enemy is. If the Iraq oil fields are destroyed again, that is even better for Russian oil production – one less competitor in the Middle East and one less breeding ground for radical Islam. In spite of all this, Figure 16, “Iraq Monthly Oil Production” shows that production has increased significantly since 2005; however, can this continue? From OilPrice.com: Why Iraq’s Oil Production Has Reached It Limits By Charles Kennedy - Sep 22, 2016, Iraq has succeeded in ramping up oil production by more than 1 million barrels per day over the past two years, a remarkable achievement for a country that was torn apart by the lightning advances made by the Islamic State. But Iraq’s success could be running up against a wall at this point, as low oil prices sap the state of the resources it needs to invest in further production. Iraq finances the investments in the state’s oil production, with much of the work carried out by international companies such as Lukoil, BP and Royal Dutch Shell. The meltdown in crude oil prices has led to a sharp fall in state revenue. Without that revenue, Iraq and its partner companies are being forced to scale back their ambitions. A few years ago, Iraq had a goal of tripling output to 9 mb/d by 2020. Although it was considered unrealistic, most oil analysts saw a huge upside to Iraq. The IEA predicted Iraq would double output to 6 mb/d by 2020, but that no longer looks workable either. Production stands at about 4.3 million barrels per day, up substantially from the 3.27 mb/d Iraq averaged in 2014. But further gains would require more drilling and a lot more money for investment – something that is increasingly scarce in Iraq. Furthermore, from Iraq Energy Institute: China to Become Major Consumer of Iraqi Oil December 20, 2016 The energy giant China National Petroleum Corp is looking to expand its business in Iraq. US oil company Exxon Mobil Corp wants to sell stakes in the West Qurna phase 1 oilfield in Iraq, and CNPC unit PetroChina, China's largest energy producer, is interested in buying 60 percent for $50 billion, according to Reuters. Iraq isn’t going to be exporting very much oil to the U.S. in the future.
  27. 27. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 27 of 66 Brazil From EIA’s special report on Brazil: Updated: December 2, 2015 (revision) Brazil is the 8th-largest total energy consumer and 9th-largest liquid fuels producer in the world. In 2014, Brazil was the eighth-largest energy consumer in the world and the third-largest in the Americas, behind the United States and Canada, according to BP statistics. Total primary energy consumption in Brazil has nearly doubled in the past decade because of sustained economic growth. The largest share of Brazil's total energy consumption is oil and other liquid fuels, followed by hydroelectricity and natural gas. Increasing domestic oil production has been a long-term goal of the Brazilian government, and discoveries of large offshore, presalt oil deposits have already transformed Brazil into a top-10 liquid fuels producer. Weak economic growth and corruption scandals implicating the head of State-controlled Petróleo Brasileiro S.A.(Petrobras) dampen prospects for production growth in the short term. The U.S. Energy Information Administration (EIA) estimates that in 2015, Brazil had 15 billion barrels of proved oil reserves, although ANP's estimates are somewhat higher at 16.2 billion barrels of proved oil reserves at the end of 2014. This amounts to the second-largest level in South America after Venezuela, and about 1% of the world's total reserves. More than 94% of Brazil's reserves are located offshore, and 80% of all reserves are found offshore near the state of Rio de Janeiro. The next largest accumulation of reserves is located off the coast of Espírito Santo state, with 9% of the country's reserves. Reserves are expected to rise as presalt resources are further explored. In 2014, Brazil produced 2.95 million b/d of petroleum and other liquids. Crude oil made up 2.2 million b/d, and 551,000 b/d was biofuels, with the remainder produced as condensate and natural gas liquids (NGLs). A growing share of production is coming from Brazil's oil deposits in the presalt layer, making up about a quarter of total Brazilian output by April 2015 and increasing 63% year-over-year. In July 2015, oil production in the presalt layer hit a record 865,000 b/d, as new wells came on stream in the Santos basin. Presalt production has seen a dramatic rise over the past few years: it accounted for 0.4% of total production in 2008 when oil from the presalt was first produced. Brazil's consumption of petroleum and other liquid fuels continues to surpass its production. In 2014, Brazil's demand for petroleum and other liquid fuels was 3.2 million b/d, up from 3.0 million b/d in 2013. However, EIA projects that production will exceed consumption in 2016 for the first time since 2008. This forecast is highly uncertain because the effect of lower crude oil prices since
  28. 28. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 28 of 66 2014 may adversely affect development and production plans. Furthermore, the fallout from the corruption scandal may further dampen Brazil's prospects. Petrobras is under investigation in Brazil and in the United States for bribery and money laundering. The multi-billion-dollar corruption scandal (Operation Car Wash scandal) started with the arrest in March 2014 of Paulo Roberto Costa, head of refining operations for Petrobras (2004– 2012), who was accused of money laundering. The scandal escalated further with allegations of government corruption and a kick-back scheme, resulting in losses of more than $8 billion, multiple arrests, and the resignation of the CEO, Maria das Graças Foster. The new CEO, Aldemir Bendine, was appointed in February 2015. While the investigation is ongoing, the company's auditor would not certify its financial statements, which has kept Petrobras from accessing international capital markets, compounding the company's problems that have partly resulted from falling oil prices. The corruption scandal has altered Petrobras' investment plans in Brazil's oil industry, and instead of increased investments, the company was forced to undertake a sizeable divestment plan in order to raise funds.
  29. 29. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 29 of 66 From Forbes: Brazil's Oil Production Expected To Continually Increase July 12,2016 Jude Clemente "Future Of Brazil's Oil Industry In Serious Doubt," Oil Price, November 2015 Pre-Salt Bonanza Begins In Brazil With First Oil Produced," Oil Price, April 2016 These two starkly different headlines from the same website just months apart illustrate how confusing Brazil's oil industry has become. Not long ago, led by offshore development, Brazil's state-owned Petrobras was perhaps THE emerging giant in the oil business, only to be engulfed by corruption, sunken prices, high costs, and mismanagement and government interference. Petrobras is reported as being $130 billion in debt, the worst in the business, and proven oil and gas reserves were slashed 20% last year. The government has forced Petrobras to focus on new technically-challenging offshore "subsalt" resources, and laws have pushed more revenue to the government, surging spending. From OilPrice.com: Brazil Oil And Gas Production Reach Record Highs In September By Erwin Cifuentes - Nov 04, 2016 The Brazilian government on Friday reported that its oil and gas production rose to record levels in September with a total oil equivalent of 3.36 million barrels per day (bpd). The ANP data is a breath of fresh air for a Brazilian oil industry burdened by low global prices, and the “Lava Jato” probe looking into corruption at state-owned firm Petrobras. Petrobras will likely continue being the main energy player in Brazil, and the expected multibillion-dollar renegotiation of a contract with the government could help boost investor confidence in the company. Meanwhile, the fact that Petrobras is no longer required to be the operator of all new exploration and production projects could lead to greater interest from foreign oil companies in Brazil. The push for stronger output by Brazil stands contrary to the Organization of the Petroleum Exporting Countries (OPEC) campaign to limit supplies in order to boost prices. As we reported on Tuesday, as far as Brazil is concerned “any call from OPEC – or even a plea for help – is likely to fall on deaf ears, regardless of appearances and general statements of understanding.”
  30. 30. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 30 of 66 It is the same old story with these Latin American countries. Corruption always stops a good thing going. Like the Canada again a focus of a new Great Scramble for oil article said, Canada is one of the few importers to the U.S. with the rule of law. It also proves once again that reserves don’t necessarily mean anything. You have to produce the reserves in a profitable manner. It also means that investors have to be careful investing in these countries. In any case, the U.S. can’t expect much from Brazil in the future. Kuwait Kuwait’s production, which is almost all exported, has leveled off in the last four years as shown in Figure 17, “Kuwait Monthly Oil Production”. Plus Kuwait’s exports to the U.S. were 197 thousand barrels per day in 2010 and were only 204 thousand barrels per day in 2015. From OilPrice.com: Kuwait Plans To Ramp Up Oil Production By 44% Before 2020 By Irina Slav - May 11, 2016 A senior Kuwait Petroleum Corp official has confirmed to media the company’s plans to increase production by 44 percent to almost 4 million barrels a day in 2020. The plan is a continuation of current attempts to pump as much crude as possible and tender new E&P projects in the Persian Gulf. In addition, Kuwait Petroleum Corp plans to ramp up local refining capacities. Kuwaiti crude is currently trading at around $40 a barrel, a palpable discount to international benchmark Brent. However, Kuwait boasts low-cost production, but according to a local energy analyst, $40 is below the breakeven level, and significantly so. Kamal Al-Harami has slammed the government for failing to come up with a contingency plan in case prices stay at current levels, and for doing nothing to prop them up—not that there’s a lot Kuwait could do on its own, even though it is among the top 10 global oil producers. Yet the criticism may not be completely deserved. April saw oil workers in Kuwait go on strike for three days, cutting production to as low as 1.1 million barrels per day, down from 3 million, in protest to planned reforms that would see higher prices for utilities and food, and a possible salary freeze for the public sector. These price increases, Al-Harami notes, will only affect expats, so they are more of a half measure. Yet, freezing the salaries of public servants would lead to substantial savings. What’s perhaps worse is that the longer Kuwait waits for prices to improve, meanwhile raising production, the harder it will be to effect meaningful reforms and the fewer resources it will have to do this. Increasing production sounds like big talk with very little to back it up.
  31. 31. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 31 of 66 United Arab Emirates (UAE) UAE depends heavily on the revenue from oil exports as you can see below. According to Wikipedia, more than 85% of UAE’s economy was based on oil exports. Saudi Arabia, Russia, Iraq, and the UAE have been hit hard by the decline in the price of oil, and their net export surplus has declined significantly. From WTEx: Crude Oil Exports by Country DECEMBER 7, 2016 BY DANIEL WORKMAN The following countries posted the highest positive net exports for crude oil during 2015: Investopedia defines net exports as the value of a country’s total exports minus the value of its total imports. Thus, the statistics below present the surplus between the value of each country’s crude oil exports and its import purchases for that same commodity. 1. Saudi Arabia: US$133.3 billion (net export surplus down -51.8% since 2011) 2. Russia: $85.5 billion (down -50.2%) 3. Iraq: $52.2 billion (down -32.3%) 4. United Arab Emirates: $51 billion (down -47.2%) 5. Nigeria: $38 billion (down -57.8%) 6. Canada: $37 billion (down -8.9%) 7. Kuwait: $34.1 billion (down -50.4%) 8. Angola: $32.6 billion (down -48.4%) 9. Venezuela: $27.8 billion (down -54.4%) 10.Kazakhstan: $26.2 billion (down -50.3%) 11.Norway: $25.2 billion (down -56.7%) 12.Iran: $20.4 billion (down -75.9%) 13.Mexico: $18.8 billion (down -62%) 14.Oman: $17.4 billion (down -37.1%) 15.Azerbaijan: $13 billion (down -43.2%) Saudi Arabia has the highest surplus in the international trade of crude oil. In turn, this positive cash flow confirms Saudi’s strong competitive advantage for this specific product category. While crude oil production has risen from 2010 to 2015 as shown in Figure 18, “UAE Monthly Oil Production”, most exports go east to India and China. I don’t think UAE will ever be more than a very minor exporter of crude oil, if any, to the U.S. in the future. Noteworthy is BP just cut a deal with UAE which gives UAE 2% of the company instead of cash. That shows you how bad BP’s situation is. From Penn Energy: BP signs onshore oil deal with Abu Dhabi worth $2.22 billion December 19, 2016 By Jon Gambrell, Associated Press
  32. 32. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 32 of 66 DUBAI, United Arab Emirates (AP) — BP PLC signed a $2.22-billion deal Saturday restoring its share of an onshore oil block in Abu Dhabi by agreeing to give the emirate stock in the company worth 2 percent of the oil giant's overall value. The unique agreement spares BP of paying out cash and gives the capital of the United Arab Emirates' stake in a company that first arrived there in 1939, back when the country was still a British protectorate of sheikhdoms. Take that Britain and stuff it! The Rest The rest of past U.S. crude oil importers are either areas with rapidly decreasing oil production or African countries that are continuously either fighting civil wars or government corruption trying to maintain very fragile production systems. Hopeless! Russia Russia, the EXXON team is coming with former coach Rex Tillerson of the University of Texas!! Where is playing field? Look at Figure 20, “The Last Frontier”. We are going to need the NFL for this one and probably David Blaine’s magic also. The old college try by Chevron didn’t work in the Beauford Sea. Figure 19, “Russia Oil Production in Millions of Barrels Per Day vs. Brent Price”, shows how Russia’s production has increased in spite of the drop in the oil price because their economy, like Saudi Arabia of the present, is heavily dependent on oil export revenues. In any case, it remains to be seen if any significant production in the Russian Arctic helps the American “suburbia style - happy motoring” to continue. Iran Here is a wild card! Are better known as Islam gone wild! Iran has ramped up crude oil production rates after the latest sanctions were lifted in January 2016 as shown in Figure 21, “Iran Monthly Crude Oil Production”. Iran exported crude oil to India and China during the sanction period, but has resumed shipments to European countries since the sanctions lifted in January 2016. Iran agreed to only increase production 90,000 barrels per day over October production levels in conjunction with the OPEC November production cut agreement. All OPEC members, except Indonesia, and Russia agreed to cut production in order to force the world crude oil price to rise. The cuts will take effect in January 2017. We’ll see if the cuts actually happen, and whether the oil price keeps rising.
  33. 33. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 33 of 66 Whatever happens, Iran won’t be exporting any oil to the United States in the future. Conclusions Now return to my spreadsheet in Appendix A and you can see “Imports Average Bbls Per Day Over 27 Year Period” on Line 14. Next to it is the average daily imports for 2015, which was 7,363,000 barrels per day according to the EIA. For the EIA AEO2014, 2015, and 2016 cases, I assumed that the imports would remain the same for the 27 year period 2014 to 2040. I don’t think that is at all feasible given the future production outlook of each potential exporter to the U.S., but I did it for comparison of best possible versus worst possible situations in 2040. For the worst possible situation, the Hughes (actually my interpretation) case, I reduced imports by half. In my opinion, the only possible country that could still import crude oil to the U.S. by 2040 would be Canada. Also, considering all I have said heretofore, I consider the outlook for domestic conventional production to be as bleak as foreign imports so I expect the conventional production in 2040 to be half of the 2015 level. I might change my mind if Trump made significant changes in access to lower 48 states offshore and the Alaska reserve and the majors had some success in the Beauford Sea, but we will know in four years. For now, things don’t look promising. Add the three numbers up – tight oil production + conventional production + access to imports – and that equals total crude oil available for consumption, which was about 16.7 million barrels per day in 2015 (note that doesn’t include ethanol and biodiesel which are in the BP Statistical review of Energy 2016). Note that the available for consumption per day (which includes available imports) for 27 years for the AEO2016 case is 17.2 million barrels per day compared to 9.16 million barrels per day 2014 to 2040 per my guess. In fact, due to the issues I present below, I don’t think U.S. production will be at that level even in 2030. Compare my conventional + tight oil production number of 5.4 million barrels per day with the EIA’s prediction in the AEO2016 of increasing domestic production throughout the 27 years to reach 11.3 million barrels per day. If my assumption appears to be overly pessimistic, consider the following starting with Figure 22, “Conventional Crude Oil Exploration” and Figure 23, “World Conventional Oil Wells Drilled Each 1960 to 2016”. From Bloomberg Markets: Oil Discoveries at 70-Year Low Signal Supply Shortfall Ahead Mikael Holter August 29, 2016 Explorers in 2015 discovered only about a tenth as much oil as they have annually on average since 1960. This year, they’ll probably find even less, spurring new fears about their ability to meet future demand.
  34. 34. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 34 of 66 With oil prices down by more than half since the price collapse two years ago, drillers have cut their exploration budgets to the bone. The result: Just 2.7 billion barrels of new supply was discovered in 2015, the smallest amount since 1947, according to figures from Edinburgh-based consulting firm Wood Mackenzie Ltd. This year, drillers found just 736 million barrels of conventional crude as of the end of last month. New discoveries from conventional drilling, meanwhile, are “at rock bottom,” said Nils-Henrik Bjurstroem, a senior project manager at Oslo-based consultants Rystad Energy AS. “There will definitely be a strong impact on oil and gas supply, and especially oil.” Ten years down the line, when the low exploration data being seen now begins to hinder production, it will have a “significant potential to push oil prices up," Bjurstroem said. Overall, the proportion of new oil that the industry has added to offset the amount it pumps has dropped from 30 percent in 2013 to a reserve-replacement ratio of just 6 percent this year in terms of conventional resources, which excludes shale oil and gas, Bjurstroem predicted. Exxon Mobil Corp. said in February that it failed to replace at least 100 percent of its production by adding resources with new finds or acquisitions for the first time in 22 years. “That’s a scary thing because, seriously, there is no exploration going on today,” Per Wullf, CEO of offshore drilling company Seadrill Ltd., said by phone. It is a scary thing indeed because the world is consuming existing oil reserves and not replacing them at any anything even close to what is required. Also, the optimists are assuming that the existing oil reserves are real and can be extracted at prices that don’t destroy demand. The price of oil isn’t going to return to the $100 mark, in my opinion, and if it does then demand will decrease again assuming that it can increase to support an oil price rise in the first place. There is too much complacency about what technology can do. Art Berman has said something like “People have more faith in technology that hasn’t been invented yet than God”. What technology are we talking about? Horizontal fracking? It’s not magic. It takes lots of water, lots of proppants and chemicals, time, and most important lots of money. Also, you have to keep drilling at a faster and faster rate just to maintain production levels, much less increase production levels. Essentially, you are running faster to die faster. Sounds like the human race in general. The kind of predictions that the EIA and IEA make are not optimism; they are fantasy, gobbled up by the purveyors of Faith and Hope. They are based on this misconception that humans can do anything, and growth of everything can continue at any rate you can imagine. If so, why haven’t we returned to the moon? Why can’t Elon Musk get his toy rocket off the ground? Why haven’t we found a cure for cancer? What about a cure for ALS? The efforts cost too much! Plus there are other more essential priorities. You can’t afford everything, all the time.
  35. 35. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 35 of 66 Eventually many will realize that It will cost too much too maintain the “happy motoring” lifestyle that the Baby Boomer generation started and have now brainwashed the younger generations into thinking they can have also. But there is more to this story. The “oil and gas” age has been a brief period in history. It was brought on by the automobile and accelerated in size with the airplane and two world wars. Just one hundred thirteen years ago, automobiles came on to the scene. Henry Ford founded the Ford Motor Company in 1903. From Wikipedia: The Ford Motor Company was launched in a converted factory in 1903 with $28,000 in cash from twelve investors, most notably John and Horace Dodge (who would later found their own car company). During its early years, the company produced just a few cars a day at its factory on Mack Avenue and later its factory on Piquette Avenue in Detroit, Michigan. Groups of two or three men worked on each car, assembling it from parts made mostly by supplier companies contracting for Ford. Within a decade the company would lead the world in the expansion and refinement of the assembly line concept; and Ford soon brought much of the part production in- house in a vertical integration that seemed a better path for the era. Mass production brought on the era of mass consumption and then mass energy depletion. More from Wikipedia: Originally purchased by wealthy individuals, by 1916 cars began selling at $875 (US$19,060 in 2016 dollars) Soon, the market widened with the mechanical betterment of the cars, the reduction in prices, as well as the introduction of installment sales and payment plans. During the period from 1917 to 1926 the annual rate of increase in sales was considerably less than from 1903 to 1916. In the years 1918, 1919, 1921, and 1924 there have been absolute declines in automotive production. The automotive industry caused a massive shift in the industrial revolution because it accelerated growth by a rate never before seen in the U.S. economy. The combined efforts of innovation and industrialization allowed the automotive industry to take off during this period and it proved to be the backbone of United States manufacturing during the 20th century. In 1908 Ford introduced the mass-produced Model T, which would sell in the millions. The engine was capable of running on gasoline, kerosene, or ethanol and got 13 to 21 miles per gallon depending, of course, on your average speed and carry weight; however, top speed was only 40 miles per hour. This limited energy consumption initially, but cars became more numerous, driven more miles at faster speeds. Energy consumption ramped up, up and up and. The dangers of technology ramped up also.
  36. 36. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 36 of 66 1900-1930: The years of driving dangerously Bill Loomis, Special to The Detroit News 2:14 p.m. EDT April 26, 2015 As early as 1908, auto accidents in Detroit were recognized as a menacing problem: In two months that summer, 31 people were killed in car crashes and so many were injured it went unrecorded. Early vehicles were terrifyingly loud for horses and their owners, compounding the problem as their numbers grew quickly. Statistics kept by the nascent Automobile Club of America recorded that in 1909 there were 200,000 motorized vehicles in the United States. Just seven years later, in 1916, there were 2.25 million. In 1917, Detroit and its suburbs had 65,000 cars on the road, resulting in 7,171 accidents and 168 fatalities. Three-fourths of the victims were pedestrians. Detroit differed from New York City and the east coast, where most automobiles were driven by uniformed chauffeurs hired by the wealthy. In Detroit everyone from nearly all incomes was driving. Before the automobile, coal was king. Then the automobile required a new form of energy, a more intense form of energy and much more of it. Humans wanted to travel, and they wanted to travel fast. Rockefeller had founded the Standard Oil Company in 1870. Oil refined to Kerosene was an important commodity for lighting even before the automobile. Something even more energy intensive was needed and it required a more complicated refining process. How Oil Refining Transformed U.S. History & Way of Life By Katrina C. Arabe January 17, 2003 By 1911, gasoline dethroned kerosene, used for lighting, as the top-selling product of Standard Oil of New Jersey, the country's largest refiner. Kerosene's slide was also hastened by the 1910 invention of the tungsten filament for electric light bulbs by William David Coolidge. Refiners met the skyrocketing demand for motor fuels by advancing beyond the basic distillation processes that had been in use since the 1860s. In 1913, they developed thermal cracking, which was able to produce more gasoline and diesel from a barrel of oil, and the technique was only the first of many processing innovations that allowed refiners to fulfill market needs. From 1920 to 1930, the number of cars owned by Americans jumped from 8.1 to 26.7 million. The Great Depression put a dent on vehicle sales, especially during the early 1930s, but the auto industry was definitely rolling. Oil companies prospered along with automakers. Refiners built more refineries and expanded existing facilities. They also improved thermal-cracking techniques
  37. 37. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 37 of 66 and developed other catalytic processes to produce high-grade products. High-octane gasoline emerged in the 1930s from refiners' tireless efforts, and it would play a role in World War II. Running on high-octane fuel, which optimizes engine performance, Allied planes outmaneuvered German planes using inferior fuels. And U.S. oil refineries kept the Allies' fuel supply coming— providing them with as much as 80% of the fuel they used during the war. Even Joseph Stalin said in a toast during a banquet toward the end of the war, "This is a war of engines and octanes. I drink to the American auto industry and oil industry." Another important development during the war was the building of long-distance pipelines. By that time, crude and product pipelines had overtaken rail tankcars as the main method of transporting liquid hydrocarbons. In 1942 and 1943, engineers built what was then the world's longest crude oil pipeline dubbed "The Big Inch," which spanned 1,254 miles and moved crude from Texas oil fields to East Coast refineries. "The Big Inch" was followed by "The Little Inch," which transported products along a similar route. These two pipelines form part of the Colonial Pipeline system today. After World War II, the U.S. became a world superpower and created as much wealth between 1950 and 1965 as it did from 1607, the year that saw the first permanent settlement in Virginia, until 1950. All during this time oil was being consumed and discovered at faster and faster rates by oil majors all over the world and by “wildcatters” in the United States. Wildcatters would flock to the latest discovery starting with “Spindeltop” near Beaumont, Texas in 1901. They would drill like crazy, crash the prevailing oil price, and drain the plays to unprofitable levels one after the other. Starting in the second decade of the 20th century, major oil companies began an attempt to secure oil reserves from all over the world. From Wikipedia: At last in 1911, the Supreme Court of the United States found Standard Oil Company of New Jersey in violation of the Sherman Antitrust Act. By then the trust still had a 70% market share of the refined oil market but only 14% of the U.S. crude oil supply. The court ruled that the trust originated in illegal monopoly practices and ordered it to be broken up into 34 new companies. These included, among many others, Continental Oil, which became Conoco, now part of ConocoPhillips; Standard of Indiana, which became Amoco, now part of BP; Standard of California, which became Chevron; Standard of New Jersey, which became Esso (and later, Exxon), now part of ExxonMobil; Standard of New York, which became Mobil, now part of
  38. 38. U.S. PETROCHEMICAL INDUSTRY FUTURE - UPSTREAM - CRUDE OIL - LOGIC VERSUS FAITH AND HOPE Page 38 of 66 ExxonMobil; and Standard of Ohio, which became Sohio, now part of BP. Pennzoil and Chevron have remained separate companies. Post WWII, countries with vast oil supplies began to realize that these major oil companies were benefiting from national oil supplies much more than they were. From Wikipedia: Prior to 1970, there were ten countries that nationalized oil production: the Soviet Union in 1918, Bolivia in 1937 and 1969, Mexico in 1938, Iran in 1951, Iraq in 1961, Burma and Egypt in 1962, Argentina in 1963, Indonesia in 1963, and Peru in 1968. Although these countries were nationalized by 1971, all of the “important” industries that existed in developing countries were still held by foreign firms. In addition, only Mexico and Iran were significant exporters at the time of nationalization. The government of Brazil, under Getúlio Vargas, nationalized the oil industry in 1953, thereby creating Petrobras. The shortage of oil in the 1970s increased the value of oil from previous decades. The bargaining power of producing countries increased as both the country governments and the oil companies became increasingly concerned about the continued access to crude oil. Once the oil industry structure changed, oil-producing countries were more likely to succeed in nationalizing their oil supplies. The development of OPEC provided the medium in which producing countries could communicate and diffusion could occur rapidly. The first country to successfully nationalize after the structural change of the industry was Algeria, which nationalized 51% of the French companies only ten days after the 1971 Tehran agreement and later was able to nationalize 100% of their companies. The nationalization of Algerian oil influenced Libya to nationalize British Petroleum in 1971 and the rest of its foreign companies by 1974. A ripple effect quickly occurred, spreading first to the more-militant oil producers like Iraq and then followed by more-conservative oil producers like Saudi Arabia. Stephen J. Kobrin states that “By 1976 virtually every other major producer in the mid-East, Africa, Asia, and Latin America had followed nationalizing at least some of its producers to gain either a share of participation or to take over the entire industry and employ the international companies on a contractual basis.” The world’s largest source of oil was Saudi Arabia after the discovery of “Ghawar”. Now they had some power. In 1950, King Abdulaziz threatened to nationalize his country's oil facilities, thus pressuring Aramco to agree to share profits 50/50. In 1973, following US support for Israel during the Yom Kippur War, the Saudi Arabian government acquired a 25% stake in Aramco. It increased its shareholding to 60% by 1974, and finally took full control of Aramco by 1980, by acquiring a 100% stake in the company.

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