Growing U.S. Oil and Gas Production Set to Reshape Competitive Position of U.S. Refineries

Transcription

1 Growing U.S. Oil and Gas Production Set to Reshape Competitive Position of U.S. Refineries Prepared by: Charles G. Kemp March 2013 Baker & O Brien, Inc N. Central Expressway, Suite 1200 Dallas, Texas This report as well as others can be downloaded from our website.

2 INTRODUCTION A production renaissance is taking place in the United States (U.S.) oil and gas industry, the likes of which could not have been contemplated even five years ago. Advances in drilling technology and the opening up of previously untapped shale deposits have combined to increase total domestic oil production for the first time in over four decades. An abundance of domestic natural gas production has pushed prices down to the point where natural gas-based chemicals can again be competitively produced and large-scale Liquefied Natural Gas (LNG) exports are seen as a possibility. Such developments are also having a profound impact on the competitive economics of various segments of the U.S. refining industry and its ability to compete in the global refined products marketplace. THE GLOBAL OUTLOOK FOR LIQUID FUELS The International Energy Agency (IEA) projects that world demand for liquid fuels will increase by an average of approximately 0.8 percent (%) per year through the year 2020, as shown in Table 1. Net demand within the Organization of Economic Cooperation and Development (OECD) nations will actually decline during this period, while non-oecd nations, led largely by China, India, and the Middle East countries, will account for virtually all of the demand increase. According to the IEA, world liquids fuel demand will reach more than 94 million barrels per day (MMB/D) by 2020 an increase of almost 8% over Page 1

3 TABLE 1 WORLD CHANGE IN LIQUIDS DEMAND, SOURCES: IEA and U.S. Energy Information Administration (EIA) estimates; Baker & O Brien analysis. Most projections show only a modest population growth in OECD countries, substantial improvements in fuel efficiency, increased biofuels production, and overall demand reduction resulting from relatively high oil prices. Year after year, increasingly less energy (and, in particular, liquid fuel) is needed to produce a unit of Gross Domestic Product (GDP) in these developed nations. Declining liquid fuel demand in such nations, combined with rising fuel export capacity in non-oecd countries, raises the specter of continued closure of old, inefficient refining capacity in many OECD nations. In contrast, rising populations in non-oecd countries, most notably India and China, combined with higher living standards, continue to increase energy and oil consumption. When one considers that per-capita energy consumption in India and China are approximately oneeighth and one-fourth, respectively, of the U.S. energy consumption, it is easy to understand why population growth and improved living standards in non-oecd nations will remain the drivers of global oil demand in the future. Page 2

4 The bifurcation of future world oil demand between OECD and non-oecd nations, along with the oil and gas renaissance being experienced in North America, will have significant implications to both the global and U.S. refining industries. Table 2 summarizes how incremental world oil demand in 2020 is likely to be satisfied. Increased production of natural gas liquids (NGLs) and biofuels neither of which require refining can be expected to supply a combined 3 MMB/D. With natural gas prices relatively low in the U.S., gas wells yielding high NGL volumes will be favored over dry natural gas production. Biofuels production will be largely driven by regulatory requirements and is expected to be especially important in Europe. Assuming that China proceeds to construct the 2.4 MMB/D of announced refining capacity to satisfy its incremental domestic needs through 2020, Table 2 shows that only 1.4 MMB/D of additional crude oil processing capacity may be needed, excluding China, to satisfy the incremental global demand for liquid fuels by TABLE 2 COMPONENTS OF PROJECTED INCREMENTAL WORLD LIQUID FUELS SUPPLY (BETWEEN 2011 AND 2020) SOURCES: IEA and EIA estimates, Baker & O Brien analysis. Page 3

5 In contrast to the relatively modest projected incremental demand for new refining capacity, announced additions to global refining capacity through 2017, as shown in Figure 1, total over 5 MMB/D. As illustrated in Figure 1, most of this new refining capacity is targeted for Asia-Pacific (largely China) and the Middle East. Together, these two areas account for approximately 75% of the total announced refining capacity. Since much of this new capacity (excluding China) is destined for export, the imbalance in incremental capacity versus incremental demand raises serious challenges to existing suppliers of refined products in OECD nations, especially North America and Europe. FIGURE 1 EXPECTED INCREASES IN GLOBAL REFINING CAPACITY SOURCES: Industry announcements and Baker & O Brien analysis. For reasons detailed later in this paper, U.S. refiners are expected to be significantly more competitive, on a global basis, than their European counterparts. However, substantial Page 4

6 differences will exist between refineries in different regions of the U.S., largely based on their access to newly developed and cost-advantaged supplies of crude oil and natural gas. U.S. CRUDE OIL AND CONDENSATE PRODUCTION As shown in Figure 2, the U.S. Energy Information Administration (EIA) projects that new production of so-called tight oil, i.e., light crude oil that is produced from tight shale rock formations, will more than offset future declines in conventional domestic crude oil production for many years into the future. Recent technological advances have enabled fracturing of these tight shale formations to release petroleum liquids. FIGURE 2 PROJECTED U.S. CRUDE OIL AND CONDENSATE PRODUCTION (MMB/D) SOURCE: EIA, Annual Energy Outlook 2013 Early Release. As shown in Figure 3, Texas and North Dakota have accounted for the lion s share of recent production growth, with over 70% originating from the Bakken (North Dakota) and Eagle Ford (Texas) areas alone. Page 5

7 FIGURE 3 MAJOR RIG COUNT CONCENTRATIONS AND PRODUCTION GROWTH AREAS SOURCES: Baker Hughes, EIA, Texas Railroad Commission, and Baker & O Brien analysis. Production from these formations is expected to continue growing, as well as from fields in Oklahoma, Kansas, Colorado, and Ohio, adding almost 2.5 MMB/D by 2020, as shown in Figure 4. Page 6

8 FIGURE 4 INCREMENTAL U.S. CRUDE OIL PRODUCTION VS SOURCES: EIA, Texas Railroad Commission, and Baker & O Brien analysis. Some analysts project that total U.S. production could exceed 7.5 MMB/D in 2015 and 8.5 MMB/D by Even more optimistically, some believe that it may be possible for the U.S. to eventually exceed the previous domestic production record of 9.6 MMB/D set in CANADIAN IMPORTS While the new burgeoning U.S. production is primarily light, sweet crude oil, Canada continues to export increasing volumes of heavy oil to the lower 48 states. Canadian imports are expected to increase from 2.4 MMB/D in 2012 to 3.7 MMB/D by 2020, of which, diluted bitumen blends ( DilBit ) are expected to account for most of this incremental supply. 1 Such 1 Crude Oil Forecast, Markets & Pipelines, Canadian Association of Petroleum Producers, June Page 7

9 incremental imports are, of course, dependent on the construction of new and/or expansion of existing pipeline capacity linking the U.S. and Canada. Without additional cross-border pipeline capacity, incremental shipments of Canadian crude oil will be constrained by existing pipelines and rail capacity. LIMITED MID-CONTINENT TAKE-AWAY CAPACITY AFFECTS CRUDE OIL PRICES Cushing, Oklahoma, is the principal storage location for crude oil in the U.S. Mid- Continent and is situated at the intersection of numerous pipelines. Cushing is also the delivery location for the New York Mercantile Exchange (NYMEX)-traded West Texas Intermediate (WTI) crude oil contract. With recent increases in domestic crude oil production in the Mid- Continent, and with limited pipeline take-away capacity, storage at Cushing has been near its maximum. This situation has led to lower WTI prices relative to other world benchmarks and lower prices for domestic crude oils processed at refineries that either take physical supply from Cushing or purchase crude oil that is linked to the WTI crude oil price. In fact, as shown in Figure 5, although some PADD 4 (Rocky Mountain) refineries enjoyed significant crude price advantages prior to 2008 and, since 2009, many other Mid-Continent refineries have also been benefitting from the same effect as they process increasing volumes of Bakken crude oil. Throughout 2010, it became apparent that most Mid-Continent refineries would realize such discounted crude oil prices and, by 2012, production growth and pipeline constraints in the Eagle Ford formation of Texas led to a similar situation for South Texas oil refineries. During 2013, new pipelines are expected to deliver large volumes of light crude oils to the U.S. Gulf Coast (USGC), eliminating most imports of traditional light, sweet Atlantic Basin crude oils. Page 8

10 FIGURE 5 THE ENVELOPES WHERE REFINERIES ENJOY PRICE-ADVANTAGED CRUDE OILS ARE EXPANDING SOURCE: Baker & O Brien analysis. Although plans are in the works to build or expand pipelines to allow more crude oil to flow from Cushing to USGC refineries, new production is coming onstream faster than the pipeline take-away capacity is increasing. The proposed cross-border Keystone XL pipeline will eventually allow an additional 700 thousand barrels per day (MB/D) of heavy Canadian crude oil to flow through Cushing to the USGC, potentially backing out heavy Venezuelan and Arabian crudes; however, this project is mired in politically-motivated delay and uncertainty. Because of the pipeline bottlenecks at Cushing and other locations, some refining centers are building unit train unloading facilities to receive low-priced Bakken and/or Canadian crude oils by rail. Such facilities can be found at locations, such as Anacortes, Washington, Albany, New York, and Philadelphia, Pennsylvania. Unit trains can transport as much as 70,000 barrels of crude oil and unloading can often be completed within 24 hours with new high-capacity systems. Both U.S. East Coast (USEC, or PADD 1) and USGC (PADD 3) refineries import Page 9

11 significant volumes of light, sweet crude oil from the Atlantic Basin, as shown in Figures 6 and 7. Over the next few years, Baker & O Brien, Inc. (Baker & O Brien) anticipates a substantial portion of the USEC sweet crude imports will be displaced by rail deliveries of Bakken crude oil and, possibly, waterborne deliveries of Eagle Ford-like crudes from the USGC. FIGURE 6 WATERBORNE CRUDE OIL IMPORTS BY CRUDE QUALITY PADD 1 SOURCES: EIA and Baker & O Brien analysis. Page 10

12 FIGURE 7 WATERBORNE CRUDE OIL IMPORTS BY CRUDE QUALITY PADD 3 SOURCES: EIA and Baker & O Brien analysis. Although rail costs from North Dakota s Bakken formation to coastal refineries add significantly to delivered prices, netback economics can still be favored over processing traditional imported sweet crudes. Figure 8 shows that, since mid-2011, refineries in the U.S. Midwest region (PADD 2) and the Rocky Mountain region (PADD 4) have enjoyed location crude oil discounts of as much as 30 dollars per barrel ($/Bbl.) or higher, relative to the price for North Sea Brent crude oil. Such discounted crude oil acquisition costs can more than make up for the high rail costs to deliver stranded crude oil to other refining centers. However, as more take-away capacity becomes available, such discounts can be expected to narrow. Page 11

13 FIGURE 8 REFINERY AVERAGE ACQUISITION PRICE OF CRUDE OIL AVERAGE PADD PRICE VS. DATED BRENT SOURCE: EIA. CAN RAIL-DELIVERED CRUDE OIL SAVE PADD 1 REFINERIES? Most PADD 1 refiners have traditionally processed light sweet crude oils via marine cargoes imported from Atlantic Basin producers. Such refineries have become less competitive as the price of Western Canadian or domestic crude oils, available only to inland refineries, have been depressed relative to imported crude oils. Many of the PADD 1 refiners, which, at one stage, seemed to have no alternative but to shutter their facilities, are now seeking rail access to low-cost inland domestic supplies. One USEC refiner recently signed a five-year contract for 50 MB/D of North Dakota crude oil to be delivered by rail to Albany, New York, for onward transfer by barge to its refinery in New Jersey. However, whether such high-transport-cost crude Page 12

14 oil access will be sufficient for all of the existing USEC refineries to survive in the long-term depends heavily on the ultimate sustainable production rate of the new tight oil plays. Recently installed plus proposed rail loading capacity for crude oil in North Dakota is approaching 1 MMB/D. As shown in Table 3, more than 800 MB/D of rail unloading capacity is planned to be operational in PADD 1 over the next several years. Assuming it is fully utilized, this is equivalent to more than 11 unit trains per day transiting from North Dakota to the USEC equivalent to the volume deliverable in a hypothetical 36 to 40-inch pipeline running from North Dakota to Philadelphia. TABLE 3 UNIT TRAIN UNLOADING DESTINATIONS (PADD 1) SOURCE: Company announcements. If all of the projects in Table 3 are fulfilled, and assuming that delivered prices for Bakken crude oil can be acquired at reasonable discounts to the price of North Sea Brent, then the near-term economics of USEC refineries would be significantly improved relative to what Page 13

15 they have been over the last several years. The latter assumption is critical, obviously, as competition for the barrels will likely be intense if tight oil production rates plateau at levels lower than anticipated. Therefore, it seems clear that the long-term viability of some USEC refineries is inextricably linked to the ultimate sustainable production rate in the Bakken and Utica formations. REFINERY MARGIN ANALYSIS AND COMPETITIVE ASSESSMENT Baker & O Brien maintains a proprietary refining database and modeling system called PRISM TM2 that enables the comparison of refining margins for oil refineries in the U.S. and other parts of the world for different time periods. Figure 9 summarizes PRISM results for U.S. refineries during the third quarter (Q3) of As illustrated, each refinery is ranked by its estimated cash margin over this period higher margin refineries to the left and lower to the right. As can be seen, PADD 2 and PADD 4 refineries, with their crude cost advantages, far outperformed other regions during this time frame. Only one fuels refinery in PADD 1 appears on the left side due to its pipeline supply of lower priced Canadian crude oil. 2 PRISM is a registered trademark of Baker & O Brien, Inc. All rights reserved. Page 14

16 SOURCE: PRISM. FIGURE 9 Q U.S. REFINERY CASH MARGIN During 2013, it is expected that the arrival of increasing volumes of Bakken crude oil to the USEC may result in a major shift of PADD 1 refinery cash margins up the margin curve just how far up they go will depend on the volumes of new domestic crude delivered and whether the large price difference between Bakken crude oil and Brent can be sustained. Figure 10 shows the relative impact that the new Bakken crude oil could potentially have on USEC refiners. Also developed using PRISM data, Figure 10 compares the delivered light oil product 3 (LOP) cost, in $/Bbl., for different refinery configurations and locations processing various qualities of crude oil into products for delivery to New York Harbor (NYH). The LOP cost is the net cost a specific refinery incurs to produce an incremental barrel of light products 3 Light oil products (LOPs) include all grades of gasoline, jet fuel, and distillate. Page 15

17 (i.e., gasoline, jet, and diesel/heating oil). The lower the LOP cost, the more competitive the refinery. As can be seen, if a USEC refiner could have processed 100% rail-delivered Bakken crude oil during Q3 2012, its economics would have been superior to all the other various refinery/location/crude oil combinations including those processing heavy crude oils on the USGC or the Middle East. FIGURE 10 BAKKEN EFFECT ON PADD 1 REFINERY LIGHT OIL PRODUCT COSTS (Q3 2012) SOURCE: PRISM. Although only a relatively small volume of Bakken crude oil was actually delivered to the USEC refineries during Q3 2012, Figure 10 shows how pronounced the potential displacement of traditional North Sea and West African crude oils can be. If additional volumes of such domestic crude oils can be secured, PADD 1 refineries should be able to compete against product imports from Europe or the Middle East. Page 16

18 Bakken crude from North Dakota is historically unique in that it is shipped to every refinery center in the U.S. The value that each refinery receives for an incremental barrel of Bakken crude can vary widely since it is dependent on the price of the displaced crude, the relative yields, and the operating costs of running Bakken, as well as the prices of the refinery s products. Baker & O Brien s PRISM model is designed to capture all of these costs and report the gate value for Bakken. Given each refinery s gate value, the additional freight costs can be subtracted to arrive at a breakeven price that each U.S. or Canadian refinery could pay for Bakken crude at the loading facility in North Dakota. These breakeven prices at the shipping point are called netback values. Stated another way, the destination refinery would be indifferent to running Bakken crude instead of a frequently-run crude, given this price in North Dakota. Table 4 shows actual netback values in North Dakota for specific refineries that are likely to run Bakken. TABLE 4 BAKKEN NETBACK VALUES, Q3 2012, FOB-NORTH DAKOTA* *Free-on-Board (FOB) indicates the refinery s value of Bakken crude loaded on a unit train in North Dakota. SOURCES: PRISM and rail freight providers. Longer term, the economic advantage of processing Bakken crude oil will depend on the bottleneck at Cushing, and how this affects the Bakken/Brent differential. Traditionally, USGC refineries import light, sweet crude from the Atlantic Basin that is priced relative to North Sea Brent Crude, but with an additional freight charge. Therefore, light sweet crude on the USGC is Page 17

19 typically set at a price higher than the Atlantic Basin light sweet crudes. If, as a result of increased domestic production, USGC refineries lose their appetite for imported crude oils, then the USGC light crude oil could be priced at a transportation discount to the Atlantic Basin market. Indeed, projections of new production from the Eagle Ford, Permian, and Mid- Continent oil plays indicate that these have the potential to satisfy USGC refineries demand for light, sweet crude and displace virtually all imports of similar quality. Already, shipments of Eagle Ford crude oil are reported to be moving from the USGC on U.S. Flag Vessels to the northeast. Notwithstanding this development, the near term prospects, at least for the next few years, point toward favorable improvements in USEC refinery margins as domestic crude oil processing increases. If USGC refineries are able to absorb larger volumes of light, sweet crude oils over time, this may serve to reduce any crude oil glut on the USGC and help sustain the domestic versus Brent crude oil differential at a higher level. For example, several announcements have already been made regarding refinery expansions to process more light crude. Also, USGC refineries designed for medium or heavy, sour crude oils may run more light domestic crudes up to physical limits because of the significant economic incentives. U.S. REFINERIES ENJOY OTHER ADVANTAGES As imported light, sweet crudes are displaced by new domestic production, not only will crude acquisition prices fall, but product yields will also improve. Crude oils like Bakken and Eagle Ford exhibit lower sulfur and notionally better light product yields than their imported competitors. This will serve to further improve U.S. refinery margins. Finally, shale gas production has resulted in very low prices for natural gas in the U.S. Natural gas is used both as refinery fuel and as a feedstock for producing incremental hydrogen needed for product desulfurization. Not only have many U.S. refineries been able to reduce energy costs by burning low cost natural gas, but the cost of hydrogen production has been substantially lowered as well. Baker & O Brien estimates that lower hydrogen production costs Page 18

20 provide U.S. refineries with a cost advantage of approximately 2 $/Bbl. of Ultra-Low Sulfur Diesel (ULSD), compared to typical European producers. Such production cost advantages have almost negated transportation cost differences and enabled U.S. refiners to export products into markets where previously they were not able to compete. THE MARGINAL BARREL NEW YORK HARBOR Petroleum prices in the NYH area, like other pricing hubs for petroleum products, are governed by supply and demand. Due to the region s large demand for products that surpass its refining capacity, PADD 1 requires products supplied from PADD 3 (USGC), the Northern Atlantic, the Caribbean, Europe, and elsewhere. The marginal price for NYH is set by whichever highest-cost supply source is required to close the demand gap for any given time period. Unfortunately, for PADD 1 refineries, they were often the highest cost of supply, evidenced by reduced refining capacity in PADD 1, as well as in the Caribbean. These refinery closures have reduced short-haul supply to the region, resulting in relative price increases as supply (primarily gasoline) from more distant and/or higher cost refineries were required to meet demand. While the refinery closures are evidence that more competitive sources of supply are available, the balance has shifted measurably on the product side (less supply due to closed plants), as well as on the feedstock side (cost-advantaged supply via rail). Other barriers to cost-effective supply from the USGC, such as Colonial pipeline hydraulic limits and high-cost (Jones Act) waterborne supplies, add further support to the improved outlook for PADD 1 refineries. EUROPE THREATENED MORE THAN U.S BY GLOBAL REFINERY EXPANSIONS As noted earlier, new, world-scale export refineries continue to be built outside the U.S., largely in the Middle East and Asia-Pacific. Many of these new facilities are government or quasi-government owned and, once built, are likely to run at full or near full capacity despite any prevailing marginal economics. After meeting in-country needs, the products from these refineries will likely move first to supply any unfilled Asian demand, especially in China. Page 19

21 However, if Chinese refinery additions proceed as planned, incremental products from Indian and Middle Eastern refineries must then flow westward to the large European and U.S. markets. Given U.S. refineries new competitive advantages, and the closer proximity of Europe to the Middle East, we expect that Europe will be the main target market. As a result, low margin refineries in Europe are at an increased risk for shutdown, as feedstock cost-advantaged plants in the U.S. will push those plants to the high end of the global cost curve. CONCLUSIONS Unprecedented growth in U.S. domestic oil and natural gas production has brought new life to many U.S. refineries and the petrochemical industry for the foreseeable future. Feedstock cost advantages in the U.S., once limited to a handful of refineries in the Rocky Mountain region, are now spreading to a greater number of plants, including even those at the high end of the cost curve in the U.S. Northeast. Certainly, the game has changed the key remaining question is how long will it last? As it relates to tight oil formations, the Exploration and Production industry is still in the early stages of the learning curve, especially as it relates to the ability to predict overall plateau production rates and durations, given the rapid initial decline rates of individual wells. If longterm production is sustainable at the higher range of forecasts, even long-distance refineries with high transport costs should be able to effectively compete. If production falls short of expectations, the competitive effect may be temporary, rail infrastructure investments may be stranded, and capacity reduction will again be required. In the meantime, buyers and sellers will be monitoring production versus take-away balances closely as it is unclear if increases in production (the problem) will be met with equivalent take-away capacity (the solution). Destination markets with limited light crude consumption capacity may also prove to be a constraining factor. Going forward, price negotiations will swing on which is growing faster, the problem or the solution. Page 20

22 One thing, however, appears to be clear. The U.S. refining industry should remain very competitive in the short to mid-term. Given the planned addition of new refining capacity in the Middle East and Asia, amid relatively modest global demand growth, European refineries are more in the crosshairs of closure than ever before. The degree of European refining capacity rationalization may ultimately depend on the production levels and sustainability of tight oil basins in North Dakota and Texas. Page 21