Higher U.S. gasoline production and inventories are reducing gasoline crack spreads (6/15/2016)

Release date: June 15, 2016  |  Next release date: June 22, 2016

Higher U.S. gasoline production and inventories are reducing gasoline crack spreads

U.S. refiners are shifting their output mix to increase the gasoline production share and reduce the distillate production share, which is increasing gasoline inventories and beginning to reduce the gasoline crack spread—the difference between gasoline futures prices and crude oil. Monthly average gasoline crack spreads are now lower than they were last year, the second consecutive month of year-over-year declines. While distillate crack spreads are also lower than last year, they are only 3 cents per gallon (gal) lower than the five-year average and have increased 9 cents/gal over the past two months. Changing gasoline-to-distillate production ratios are a contributing factor in the difference in crack spreads.

The U.S. gasoline-to-distillate production ratio began increasing in 2015, reversing a several-year decline. In May 2016, the gasoline-to-distillate production ratio reached a five-year high of 2.12 (Figure 1). Over time, refineries have some ability to adjust petroleum product yields in response to changes in price signals by adding additional equipment or modifying processes and feedstocks. A way for refineries to gauge product value is to look at the prices of futures contracts for delivery of a product at a future date. Because both gasoline and distillate prices exhibit seasonality in the summer and winter months, averaging the front-month and sixth-month futures contract price of each of the gasoline and distillate contracts and then calculating the price spread between the two averages provides insight into the price spread between these two physical products without reflecting sudden seasonal price swings that occur throughout the year.

From 2010 to 2013, U.S. refineries increased production of distillate compared with gasoline because the average price of the New York Harbor distillate contract, which began trading ultra-low sulfur diesel (ULSD) in the spring of 2013, rose compared with the reformulated blendstock for oxygenate blending (RBOB, the petroleum component of gasoline) contract over that period. The strength in distillate prices was in response to rising distillate demand in developing countries, while U.S. demand for gasoline was stagnant or declining during much of that time.

However, in 2015, the trend changed, as the price of RBOB futures contracts rose compared with distillate contracts because of lower distillate demand and higher distillate inventories globally. Lower economic growth in developing countries and increased distillate exports from the Middle East and China led to high distillate stock levels in major storage hubs, including Singapore, northwest Europe, and the United States. On the other hand, the drop in crude oil prices in late 2014 was one of many factors that led to an increase in gasoline demand, both domestically and abroad. These developments spurred U.S. refineries to increase gasoline yields, which is contributing to the rise in overall U.S. gasoline production. In first-quarter 2016, total U.S. refinery and blender net production rose 0.82%, compared with the same period in 2015. During the same span, gasoline production rose 2.18%, while distillate production declined 2.56%.

Inventories of both gasoline and distillate have been above the five-year historical range for most of 2016. As refineries increased gasoline production to meet rising demand, U.S. gasoline inventories leveled off after months of declines but are still well above the five-year range. On an absolute basis, gasoline inventories are 19 million barrels greater than at the same time last year and distillate inventories are also 19 million barrels higher. On days-of-supply basis, taking into account both domestic consumption and exports, U.S. gasoline inventories can fulfill an additional day of total gasoline demand than the same period last year (Figure 2). The year-over-year change in days of supply for gasoline gradually increased since February. Alternatively, the decline in distillate production and a slight strengthening of distillate demand following a very warm winter in the Northeast reduced the year-over-year change in distillate days of supply from a high of nearly 11 days in February to 3.2 days, according to the latest Weekly Petroleum Status Report.

Despite an increase in gasoline consumption and exports so far this year over the comparable 2015 period, higher inventory levels are likely moderating price increases typically seen during the start of the summer driving season. Through June 14, the June 2016 average RBOB-Brent front month futures crack spread so far is 38 cents/gal compared with the June 2015 monthly average of 55 cents/gal last June (Figure 3). Unlike last spring and summer, when refineries were seeing gasoline crack spreads at their highest level since 2007, this year gasoline crack spreads may retreat closer to the average seen over the past five years.

U.S. average regular gasoline retail and diesel fuel prices increase

The U.S. average regular gasoline retail price rose two cents from the previous week to $2.40 per gallon on June 13, down 44 cents from the same time last year. The East Coast and Gulf Coast prices both decreased one cent to $2.31 per gallon and $2.14 per gallon, respectively. The Midwest price rose six cents to $2.47 per gallon. The West Coast price increased two cents to $2.72 per gallon. The Rocky Mountain price rose one cent to $2.32 per gallon.

The U.S. average diesel fuel price increased two cents to $2.43 per gallon, down 44 cents from the same time last year. The Midwest, Gulf Coast, and West Coast prices each increased three cents to $2.39 per gallon, $2.31 per gallon, and $2.71 per gallon, respectively. The Rocky Mountain price increased two cents to $2.41 per gallon. The East Coast price rose one cent to $2.45 per gallon.

Propane inventories gain

U.S. propane stocks increased by 1.1 million barrels last week to 78.4 million barrels as of June 10, 2016, 2.3 million barrels (2.9%) lower than a year ago. Midwest, Gulf Coast and Rocky Mountain/West Coast inventories increased by 0.7 million barrels, 0.6 million barrels, and 0.2 million barrels, respectively. East Coast inventories decreased by 0.4 million barrels. Propylene non-fuel-use inventories represented 4.3% of total propane inventories.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at 202-586-4522.

Retail prices (dollars per gallon)

Conventional Regular Gasoline Prices Graph.On-Highway Diesel Fuel Prices Graph.
Gasoline 2.399 0.018 -0.436
Diesel 2.431 0.024 -0.439

Futures prices (dollars per gallon*)

Crude oil 49.07 0.45 -10.89
Gasoline 1.560 -0.048 -0.561
Heating oil 1.516 0.028 -0.373
*Note: Crude oil price in dollars per barrel.

Stocks (million barrels)

Crude oil 531.5 -0.9 63.6
Gasoline 237.0 -2.6 19.2
Distillate 152.2 0.8 18.6
Propane 78.351 1.057 -2.309

Storage capacity utilization rises, as growth in stored volumes outpaces expansion of storage capacity (6/8/2016)

Release date: June 8, 2016  |  Next release date: June 15, 2016

Storage capacity utilization rises, as growth in stored volumes outpaces expansion of storage capacity

The United States added 34 million barrels (6%) of working crude oil storage capacity from September 2015 to March 2016, the largest expansion of commercial crude oil storage capacity since EIA began tracking such data in 2011 (Figure 1). At the same time, reported weekly U.S. commercial crude inventories have increased by more than 72 million barrels (16%) since September, which implies crude oil storage capacity utilization at a record high of 74% for the week ending June 3.

Storage and capacity volumes used to calculate storage utilization rates must be comparable in scope to provide accurate estimates. Weekly U.S. crude inventories include volumes in transit by pipeline, tanker, barge and rail, and lease stocks. To facilitate accurate utilization calculations, EIA’s biannual Working and Net Available Shell Storage Capacity Report, which is released with March and September data, now provides information on the sum of working storage capacity, stocks in transit by pipeline, tanker, barge and rail, and lease stocks. This tally provides a capacity estimate with the same scope as commercial inventories reported by EIA for use as the denominator when calculating storage capacity utilization. Simply dividing total commercial inventories by working storage capacity alone would overstate utilization because it does not account for the volume of crude oil stored outside of tankage (pipeline fill and stocks in transit). Using weekly data, crude oil storage capacity utilization can be estimated by subtracting the amount of Alaskan crude oil in transit from commercial inventories, then dividing by the sum of working storage capacity, stocks in transit, and pipeline fill from the most recently available Working and Net Available Shell Storage Capacity Report.

The large increase in crude storage capacity between September and March was prompted by increased demand for crude oil storage as global supply has outpaced global demand for most of the past two years. Because of generally rising crude oil inventories since the end of 2014, the structure of crude oil futures prices has been in steep contango, where near-term deliveries are discounted versus long-term deliveries. The Nymex West Texas Intermediate (WTI) 1-13 spread averaged $7.25 per barrel between September and March. The large and continued contango structure prompted many market participants to place more crude oil into storage.

The largest commercial crude oil storage capacity expansions were in Petroleum Administration for Defense Districts (PADD) 2 (Midwest) and 3 (Gulf Coast), 19 million barrels (13%) and 13 million barrels (4%), respectively. Combined, PADDs 2 and 3 represent 82% of total U.S. commercial crude oil storage capacity. Within PADD 2, storage capacity at Cushing, Oklahoma, the delivery point for the Nymex WTI futures contract, expanded 1.5 million barrels (2%), similar to the previous period of March 2015 to September 2015, during which capacity expanded 1.6 million barrels (2%).

The expansion of crude oil storage capacity helped to accommodate the growth in U.S. crude oil inventories, which surpassed 500 million barrels at the end of January 2016. U.S. crude oil inventories increased in 24 of the 30 weeks from September to March, and were 532 million barrels for the week ending June 3.

Despite the large expansion in crude oil storage capacity, the net effect of capacity growth and increased inventories resulted in high storage utilization rates. Storage utilization at Cushing averaged 88% over the past four weeks, compared with 81% for the same period last year. PADD 3 storage utilization rates averaged 73% over the past four weeks, after having never surpassed 70% in the previous four years. (Figure 2).

U.S. average regular gasoline retail and diesel fuel prices increase

The U.S. average regular gasoline retail price increased four cents from the previous week to $2.38 per gallon on June 6, down 40 cents from the same time last year. The Midwest price increased seven cents to $2.41 per gallon, followed by the Gulf Coast, up five cents to $2.14 per gallon. The West Coast and East Coast prices each rose three cents to $2.70 per gallon and $2.31 per gallon, respectively. The Rocky Mountain price dipped slightly to $2.31 per gallon.

The U.S. average diesel fuel price increased three cents from a week ago to $2.41 per gallon, down 48 cents from the same time last year. The West Coast and East Coast prices each rose three cents to $2.68 per gallon and $2.44 per gallon, respectively. The Rocky Mountain, Midwest, and Gulf Coast prices each increased by two cents to $2.39 per gallon, $2.36 per gallon, and $2.28 per gallon, respectively.

Propane inventories gain

U.S. propane stocks increased by 1.9 million barrels last week to 77.3 million barrels as of June 3, 2016, 1.5 million barrels (1.9%) lower than a year ago. Gulf Coast, Midwest, and East Coast inventories increased by 1.4 million barrels, 0.5 million barrels, and 0.3 million barrels, respectively. Rocky Mountain/West Coast inventories decreased by 0.2 million barrels. Propylene non-fuel-use inventories represented 4.6% of total propane inventories

For questions about This Week in Petroleum, contact the Petroleum Markets Team at 202-586-4522.

Retail prices (dollars per gallon)

Conventional Regular Gasoline Prices Graph.On-Highway Diesel Fuel Prices Graph.
Gasoline 2.381 0.042 -0.399
Diesel 2.407 0.025 -0.477

Futures prices (dollars per gallon*)

Crude oil 48.62 -0.71 -10.51
Gasoline 1.608 -0.024 -0.422
Heating oil 1.488 -0.006 -0.382
*Note: Crude oil price in dollars per barrel.

Stocks (million barrels)

Crude oil 532.5 -3.2 61.9
Gasoline 239.6 1.0 22.3
Distillate 151.4 1.8 17.9
Propane 77.294 1.913 -1.501

Recent drilling activity has lowered costs and increased performance (6/2/2016)

Release date: June 2, 2016  |  Next release date: June 8, 2016

Recent drilling activity has lowered costs and increased performance

The profitability of oil and natural gas development activity depends both on the prices realized by producers and the cost and productivity of newly developed wells. Overall trends in well development costs are generally less transparent than those in price and productivity, which are readily observable in the markets or through analyses of well productivity trends such as EIA’s monthly Drilling Productivity Report.

To better understand the costs of upstream (or, wellhead) drilling and production activity, the U.S. Energy Information Administration (EIA) commissioned IHS Global Inc. (IHS) to study these costs on a per-well basis in the Bakken, Eagle Ford, and Marcellus plays, two plays within the Permian Basin (Midland and Delaware), and the offshore federal Gulf of Mexico (GOM). The IHS study finds that upstream costs in 2015 for the onshore plays were 25% to 30% below their 2012 levels, when per-well costs were at their highest point over the past decade, and 16% to 20% lower than the average of the past five years (Figure 1).

Changes in technology have improved drilling efficiency and completion, supporting higher productivity per well, but shifts toward deeper and longer lateral wells with more complex completions have tended to increase costs. To assess upstream costs of developing these plays in economic terms, the study applied the term unit cost, which compares capital expenditure with expected well performance to measure effectiveness, calculated as cost per barrel of oil equivalent (BOE) produced. Although some drilling costs have increased, the resulting performance benefit per well more than offsets those increases, leading to an overall decrease in cost per BOE produced (Figure 2). The unit cost concept does not, however, factor in the market value of the oil and gas produced from these wells, which is important for calculating net present value of profit or loss.

The use of multiwell pad drilling, more efficient fracturing and service providers, and decreased drilling times have all contributed to cost savings. At the same time, the use of longer laterals, better geo-steering to stay within the targeted formation, increased quantities of proppant use (to keep the fractured spaces open), an increased number and density of fracturing stages, and spacing optimization have increased well performance. Since oil prices started falling in mid-2014, reduced demand for drilling services has also enabled operators to renegotiate contracts with service providers, resulting in lower costs for drilling and well completions. Additionally, costs vary across the studied areas because of differences in geology, well depth, and water disposal options.

In the Bakken, lateral well lengths have increased to just under 10,000 feet to achieve a balance between cost and estimated ultimate recovery (EUR). Producers have also increased the quantity of proppant and fluids used at each stage, and a switch in the type of fracturing fluids. The type of proppant varies from expensive ceramic sand to cheaper natural sand between subplays, but is expected to move more toward natural sand. Well design and technology are expected to improve, but application of more proppant is not substantially increasing EURs, suggesting that as oil prices dropped in 2015, drilling operators switched to focusing on geological sweet spots rather than technological improvements to maintain production performance. Gathering, processing, and transport costs are high in this region because of infrastructure constraints associated with distance to markets and transportation being limited to rail (which can cost $5-$7 more per barrel than pipeline transport).

In the Eagle Ford, lateral lengths of wells have increased to 6,400 feet, while proppant and fracturing fluid quantities per stage have grown. Proppant mixes are focusing on cheaper, natural proppant allowing an economical increase of proppant. Also, more wells are being drilled on multiwell pads, allowing savings from shared facilities, roads, and water disposal systems. Unlike in the Bakken, an increased use of proppant directly correlates with production performance and abundant infrastructure, and proximity to markets decreases operating and transportation costs. Furthermore, in a low crude oil price environment, the Eagle Ford also has optimal production from site-specific drilling.

Horizontal wells in the Delaware and the Midland basins have increased their lateral lengths to 5,600 feet and 7,300 feet, respectively, with further increases projected. The Delaware Basin completion designs support 20 fractured stages with more than 6.2 million pounds of mixed natural sand and ceramic proppant and 6.6 million gallons of gel-based fluid. The Midland Basin designs support 28 stages with 8.8 million pounds of natural sand proppant and 9.2 million gallons of either slick water (low viscous fluid, mixture of water and chemicals) or gel-based fluid, with water-based fluid becoming more popular. However, even with these improving well and completion designs that have increased the EUR, sustained low prices have left unit costs in the Delaware Basin fluctuating and in the Midland Basin declining. Although horizontal wells in these basins have diminished cost savings in recent years, the Midland Basin is projected to have as many as 24 horizontal wells drilled from a single pad, potentially reducing costs by $700,000 per well. Similarly, horizontal drilling in the Delaware is expected to see incremental efficiency gains as more wells are drilled from multiwell pads.

Offshore projects are typically more complex than onshore ones, as they can require construction and installation of infrastructure unique to the project, and take years to develop. There are fewer wells from which to examine historical and current costs and a larger variation in the costs themselves. To demonstrate the variability in project costs, the IHS study characterized the cost profiles of four deepwater GOM projects representing the different plays, development concepts, and technical challenges offshore operators encounter: Chevron’s Big Foot ($4.3 billion), Anadarko’s Lucius ($2.47 billion), Deep Gulf Energy’s Kodiak ($1.2 billion), and Chevron’s Jack/St. Malo ($12 billion). Jack/St. Malo came online in 2014 and Lucius in 2015; Kodiak and Big Foot are anticipated to come online in 2016 and 2018, respectively.

The study delineated the main cost components of offshore projects and analyzed the key drivers behind each. The costs of drilling and completing wells in deepwater are driven by water depth, well depth, and reservoir quality, complexity, and productivity. The costs associated with constructing and installing the selected development concept are driven by design, reserve size, water depth, technical challenges, and infrastructure availability or proximity. The costs of laying pipeline used to transport processed oil and natural gas to an existing platform or onshore facility are driven by water depth, length, diameter, and capacity. Finally, the operating and decommissioning costs depend on the development concept.

Looking to 2018, with the significant capital investment offshore projects require and the current oil price environment, offshore operators are especially focused on reducing costs, increasing efficiency, and improving project economics. The IHS study estimates that a reduction in capital expenditure of at least 20% is required to move yet-to-be-funded projects in the most technically challenging play in the GOM to a $60/barrel breakeven. The study forecasts a 15% reduction in deepwater costs in 2015, an additional 3% reduction in 2016, and a modest rise in costs from 2017 to 2020.

U.S. average regular gasoline retail and diesel fuel prices rise

The U.S. average regular gasoline retail price increased four cents from the previous week to $2.34 per gallon on May 31, down 44 cents from the same time last year. The Midwest price increased six cents to $2.34 per gallon, followed by the East Coast, up four cents to $2.29 per gallon, and the Gulf Coast price, which rose three cents to $2.09 per gallon. The West Coast and Rocky Mountain prices each increased two cents to $2.67 per gallon and $2.32 per gallon, respectively.

The U.S. average diesel fuel price increased three cents from a week ago to $2.38 per gallon, down 53 cents from the same time last year. The West Coast price rose five cents to $2.65 per gallon, followed by the East Coast price, which increased three cents to $2.41 per gallon. The Rocky Mountain, Midwest, and Gulf Coast prices each increased two cents to $2.38 per gallon, $2.34 per gallon, and $2.25 per gallon, respectively.

Propane inventories gain

U.S. propane stocks increased by 1.3 million barrels last week to 75.4 million barrels as of May 27, 2016, 1.7 million barrels (2.2%) lower than a year ago. Midwest and Rocky Mountain/West Coast inventories increased by 1.3 million barrels and 0.2 million barrels, respectively. Gulf Coast inventories decreased by 0.3 million barrels, while East Coast inventories remained virtually unchanged. Propylene non-fuel-use inventories represented 5.1% of total propane inventories.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at 202-586-4522.

Retail prices (dollars per gallon)

Conventional Regular Gasoline Prices Graph.On-Highway Diesel Fuel Prices Graph.
Gasoline 2.339 0.039 -0.441
Diesel 2.382 0.025 -0.527

Futures prices (dollars per gallon*)

Crude oil 49.33 1.58 -10.97
Gasoline 1.632 -0.004 -0.454
Heating oil 1.494 0.004 -0.461
*Note: Crude oil price in dollars per barrel.

Stocks (million barrels)

Crude oil 535.7 -1.4 58.3
Gasoline 238.6 -1.5 18.3
Distillate 149.6 -1.3 17.0
Propane 75.381 1.252 -1.665

Oil companies focus on production over exploration as low oil prices reduce value of new reserves (5/25/2016)

Release date: May 25, 2016  |  Next release date: June 2, 2016

Oil companies focus on production over exploration as low oil prices reduce value of new reserves

For the second consecutive year, oil companies worldwide produced more oil and natural gas than they added to their proved reserves, excluding revisions to existing proved reserves and purchases of reserves in place. This is not necessarily an indication of fewer available resources, but rather that at current prices, there are fewer resources that can be turned into proved reserves, which are underground oil and gas that can be commercially produced at current prices using currently available technology.

Based on analysis of recently released annual reports, 85 publicly traded companies added a total of 13.7 billion barrels of oil equivalent (BOE) to their reserves base, three-quarters of the amount the same group of companies produced in 2015. A combination of reductions in exploration and development (E&D) investment and fewer extensions and discoveries contributed to the decline. Of the companies that submitted first-quarter 2016 financial results, capital expenditures declined 35% from first-quarter 2015, suggesting continued reductions in E&D investment, which could reduce reserves additions in 2016.

The reserves replacement ratio—the ratio of proved reserves added during a given year to production for that year—indicates the extent to which a company is replacing its produced reserves (Figure 1). The group of 85 companies as a whole had a reserves replacement ratio of approximately 100% in 2012 and 2013, and around 75% for 2014 and 2015. However, the ratios vary significantly by company type. Only the U.S. onshore companies added more reserves to their collective portfolio than they produced in 2015, but the effect on the global reserves base is modest because these companies hold a relatively small share of proved reserves and production.

Each company grouping differs by its area of operations and the types of assets in its portfolio. State-owned companies are mostly national oil companies outside of the Organization of the Petroleum Exporting Countries (OPEC). The international/integrated oil companies are large producers that have refining and midstream assets, with global portfolios of onshore and offshore oil production. The North American mixed companies are U.S. and Canadian exploration and production (E&P) companies that are smaller producers but with fairly broad portfolios geographically and by production type, including shale, oil sands, and offshore. The U.S. onshore producers are smaller E&P companies that focus mainly on onshore production in the United States. Collectively, the 85 companies produced 50 million BOE per day in 2015, two-thirds of which was crude oil and the remainder being natural gas and hydrocarbon gas liquids.

Analysis by major area of operations and production portfolio also reveals volumetric differences in reserves additions (Figure 2). State-owned companies and international/integrated oil companies increased reserves additions in 2015, while North American companies with a mixed production portfolio and U.S. onshore companies added less than in 2014. Companies can add proved reserves through new discoveries, enlargement of a reservoir’s proved area (extensions), improvements in the recovery of existing reserves, purchases of another company’s proved reserves, or revisions of existing reserves for economic or technical reasons. For the purposes of this analysis, purchases of reserves in place and reserves revisions are excluded from the calculation of reserves additions.

Expenditures for E&D constitute most of a company’s upstream capital investment. When calculated on a reserve addition per barrel basis, these expenditures represent the cost of finding and developing a barrel of oil. Finding and developing costs declined $10.23/BOE in 2015 (Figure 3). Since there may be a timing mismatch between when an expenditure is made and when a proved reserve addition is formally recognized, standard practice is to average the results over several years. Finding and developing costs for these companies were $25.69/BOE in 2015, the lowest in the 2012-15 period and lower than the four-year average of $29.25/BOE.

Similar to the reserves additions and the reserves replacement ratio, finding and developing costs differed across the company groupings. In recent years, U.S. onshore companies tended to have lower E&D expenditures per reserve addition compared with the other groups, as many reserves additions came from geologically familiar shale basins in the United States. Other producers typically operate in areas where it is more challenging to find reserves, such as deepwater offshore or in more mature fields that are the foundation of legacy production (such as in China or Russia). The decline in E&D expenditures for national oil companies and international/integrated companies suggests a reduction in exploration activity in such high-cost areas.

With most companies indicating continued reductions in E&D budgets absent a meaningful increase in crude oil prices, proved reserves additions will likely continue to decline.

U.S. average regular gasoline retail and diesel fuel prices increase

The U.S. average regular gasoline retail price increased six cents from the previous week to $2.30 per gallon on May 23, down 47 cents from the same time last year. The Midwest price increased 10 cents to $2.28 per gallon, followed by the Gulf Coast, up eight cents to $2.06 per gallon. The Rocky Mountain price rose six cents to $2.30 per gallon, the East Coast price increased three cents to $2.25 per gallon, and the West Coast price rose one cent to $2.66 per gallon.

The U.S. average diesel fuel price increased six cents from a week ago to $2.36 per gallon, down 56 cents from the same time last year. The Gulf Coast price rose eight cents to $2.23 per gallon, followed by the West Coast price, which increased seven cents to $2.60 per gallon. The East Coast price increased six cents to $2.38 per gallon, the Midwest price rose five cents to $2.33 per gallon, and the Rocky Mountain price was up three cents to $2.36 per gallon.

Propane inventories fall slightly

U.S. propane stocks decreased by 0.1 million barrels last week to 74.1 million barrels as of May 20, 2016, 0.9 million barrels (1.2%) higher than a year ago. East Coast and Gulf Coast inventories decreased by 0.2 million barrels and 0.1 million barrels, respectively. Midwest inventories increased by 0.2 million barrels, while Rocky Mountain/West Coast inventories remained unchanged. Propylene non-fuel-use inventories represented 5.4% of total propane inventories.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at 202-586-4522.

Retail prices (dollars per gallon)

Conventional Regular Gasoline Prices Graph.On-Highway Diesel Fuel Prices Graph.
Gasoline 2.300 0.058 -0.474
Diesel 2.357 0.060 -0.557

Futures prices (dollars per gallon*)

Crude oil 47.75 1.54 -11.97
Gasoline 1.636 0.048 -0.418
Heating oil 1.490 0.087 -0.463
*Note: Crude oil price in dollars per barrel.

Stocks (million barrels)

Crude oil 537.1 -4.2 57.7
Gasoline 240.1 2.0 19.5
Distillate 150.9 -1.3 22.0
Propane 74.129 -0.087 0.911

Clean Power Plan accelerates the growth of renewable generation throughout United States

June 17, 2016graph of U.S. net electricity generation by fuel, as explained in the article text

EIA’s Annual Energy Outlook 2016 (AEO2016) Reference case projects that natural gas-fired electricity generation will exceed coal-fired electricity generation by 2022, while generation from renewables—driven by wind and solar—will overtake coal-fired generation by 2029. The shift away from coal-fired generation to a combination of higher natural gas-fired and renewables generation and greater energy efficiency is expected to be accelerated by the U.S. Environmental Protection Agency’s Clean Power Plan (CPP).

Notably, the share of natural gas-fired generation exceeded coal-fired generation in 2016, according to EIA’s latest Short-Term Energy Outlook. However, in the AEO2016 Reference case, the natural gas-fired share of generation declines temporarily after 2016, then resumes rising in about 2020 and once again exceeds the coal-fired share in 2022 and throughout the rest of the AEO2016 projection to 2040.

Even without the CPP, significant growth in renewables generation is projected throughout the country, due in large part to Congress’s recent extension of favorable tax treatment for renewable energy sources. From 2015 to 2030, for the nation as a whole in a scenario where the CPP is never implemented, EIA projects that renewables generation will increase at an annual average rate of 3.9%, while natural gas generation will grow at 0.6% per year. In the Reference case, which assumes the implementation of the Clean Power Plan, renewables and natural-gas fired generation grow at 4.7% and 1.6% annually from 2015 to 2030, respectively.

In the final version of the CPP, states with higher intensity levels generally have greater requirements for reduction of CO2 emissions.

graph of electricity market regions and carbon dioxide emissions rate by region, as explained in the article text

EIA’s analysis of the U.S. electricity market is divided into 22 regions, which in this discussion are further reduced to 9 regions shown above. The current generation mix across these regions varies considerably, with significant differences in the use of fossil-fuel, nuclear, and renewable energy sources.

graph of regional electricity generation by fuel, as explained in the article text

Certain regions such as the Midwest/Mid-Atlantic, Southwest/Rockies, and Northern Plains—regions that are home to much of U.S. coal production—tend to have greater reliance on coal-fired electricity generation. These regions have among the highest CO2 reduction requirements and are expected to have the largest shifts in their generation mix. In the Midwest/Mid-Atlantic region, a large decline in coal generation is offset by an increase in natural gas generation and relatively modest growth in renewable generation. These projected changes are expected to result in a 26% decline in the Midwest / Mid-Atlantic region’s emission rate—from 1,826 to 1,357 pounds of CO2 per megawatthour, the largest drop of any region in both percentage and absolute terms.

The Southwest/Rockies region is projected to see an expansion of renewables generation that is nearly twice as large as the decline in coal generation. In the Northern Plains region, a decline in coal generation is exceeded by a slightly larger shift to renewables generation, with smaller growth in natural gas generation. Other regions, such as Texas, the Southern Plains, and the Southeast, rely more on natural gas-fired generation. The projected decline in these regions’ coal generation is more modest, and they all are expected to see strong gains in renewables generation, with some additional growth in natural gas generation.

Finally, the Northeast region and California currently have almost no coal generation and meet most of their demand with natural gas generation, along with renewables generation in California and a mix of nuclear and renewables generation in the Northeast. While the Northwest region does have some coal generation, it has the largest renewable generation total of any region because of its extensive hydroelectric resources. These regions have among the lowest emission reduction requirements, and as a result are expected to register small or no change in generation mix as a result of the CPP.

California sees strong growth in renewable generation by 2030 as a result of the state renewable targets. Similarly, the Northwest region is expected to increase renewables generation as well. The Northeast shows an increase in both natural gas and renewables generation by 2030, and a small decline in nuclear generation due to planned retirements.

The Reference case assumes that all states implement the Clean Power Plan using a mass-based standard that caps emissions from both existing and new plants, with allowance revenues rebated to rate payers. Because the plan allows flexibility in implementation approaches, EIA produced several alternative cases that consider how outcomes change with different implementation approaches, and in a scenario with tighter standards beyond 2030. Compliance decisions by the states (as well as any future court decision that would vacate the rule) have implications for plant retirements, capacity additions, and generation by fuel type, demand, and prices. An AEO2016 Issues in focus article released early next week will explore the results of this analysis.

Principal contributors: Thad Huetteman, Laura Martin

First new U.S. nuclear reactor in almost two decades set to begin operating

photo of Watts Bar nuclear generating station, as explained in the article text

Source: Republished with permission from the Tennessee Valley Authority

The Tennessee Valley Authority’s (TVA) Watts Bar Unit 2 was connected to the power grid on June 3, becoming the first nuclear power plant to come online since 1996, when Watts Bar Unit 1 started operations. Watts Bar Unit 2 is undergoing final testing, producing electricity at incremental levels of power, as TVA prepares to start commercial operation later this summer. The new reactor is designed to add 1,150 megawatts (MW) of electricity generating capacity to southeastern Tennessee.

Watts Bar Unit 2 is the first nuclear plant in the United States to meet new regulations from the U.S. Nuclear Regulatory Commission (NRC) that were established after the 2011 earthquake and tsunami that damaged the Fukushima Daiichi Nuclear Plant in Japan. After the NRC issued an operating license for the unit in October 2015, 193 new fuel assemblies were loaded into the reactor vessel the following month. TVA announced at the end of May that the reactor achieved its first sustained nuclear fission reaction.

Construction on Watts Bar Unit 2 originally began in 1973, but construction was halted in 1985 after the NRC identified weaknesses in TVA’s nuclear program. In August 2007, the TVA board of directors authorized the completion of Watts Bar Unit 2, and construction started in October 2007. At that time, a study found Unit 2 to be effectively 60% complete with $1.7 billion invested. The study said the plant could be finished in five years at an additional cost of $2.5 billion. However, both the timeline and cost estimate developed in 2007 proved to be overly optimistic, as construction was not completed until 2015, and costs ultimately totaled $4.7 billion.

graph of U.S. nuclear reactors that began construction and came online since 1973, as explained in the article text

Although Watts Bar 2 is the first new U.S. nuclear generator to come online in 20 years, four other reactors are currently under construction and are expected to join the nuclear fleet within the next four years. Vogtle Electric Generating Plant Units 3 and 4 in Georgia and Virgil C. Summer Nuclear Generating Station Units 2 and 3 in South Carolina are scheduled to become operational in 2019–20, adding 4,540 MW of generation capacity.

Principal contributors: Sara Hoff, Marta Gospodarczyk

This Week In Petroleum – EIA.gov – Feb. 10, 2016

U.S. regular retail gasoline to average below $2 per gallon in 2016; lowest since 2004

The Short-Term Energy Outlook (STEO) released on February 9 forecasts that the U.S. retail regular gasoline price will average $1.98/gallon (gal) in 2016, which would be the lowest annual average since 2004, and $2.21/gal in 2017 (Figure 1). Lower crude oil prices contributed to U.S. regular gasoline retail prices declining to an average of $1.95/gal in January, down from an average of $2.04/gal in December. EIA projects regular gasoline retail prices to fall to $1.82/gal in February 2016 and average $1.88/gal in the first quarter of 2016, before rising during the spring. The diesel fuel retail price, which averaged $2.71/gal in 2015, is projected to average $2.22/gal in 2016, 7 cents/gal lower than projected in last month’s STEO, and $2.58/gal in 2017.

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The lower outlook for petroleum product prices is based on lower expectations for crude oil prices. North Sea Brent crude oil prices are expected to average $38 per barrel (b) in 2016 and $50/b in 2017. Forecast West Texas Intermediate (WTI) crude oil prices are expected to average the same as Brent in both years. However, the current values of futures and options contracts continue to suggest high uncertainty in the price outlook (Figure 2). For example, EIA’s forecast for the average WTI price in May 2016 of $36/b should be considered in the context of recent Nymex contract values for May 2016 delivery (Market Prices and Uncertainty Report) suggesting that the market expects WTI prices to range from $21/b to $58/b (at the 95% confidence interval).

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The confidence range for crude oil prices as shown in Figure 2 is derived using a variation of the Black-Scholes model that is often used by financial analysts to estimate the price of options. EIA starts with options prices for WTI crude oil, and uses the Black-Scholes model to calculate the implied volatility. WTI futures contracts and options are the among the more actively traded commodity derivative products, with many producers, consumers (including refiners, airlines, trucking companies, and fuel distributors), and other investors and risk-takers involved. The confidence interval is therefore a market-derived range that is not directly dependent on EIA’s supply and demand estimates.

Continuing increases in global liquids inventories have put significant downward pressure on oil prices since mid-2014. After growing by an estimated 1.8 million barrels per day (b/d) in 2015, global oil inventories are forecast to grow by 1.4 million b/d in the first quarter of 2016. The largest inventory builds occur in the first half of 2016, helping keep Brent prices below $40/b through August.

During January 2016, daily changes in crude oil prices were highly correlated with daily changes in global equity indexes. The increased co-movement and higher volatility likely reflect increased uncertainty about future global economic growth. Changes in overall demand for risk assets, such as commodities and equities, by investors and market participants may also be playing a larger role in price discovery across global asset markets compared with previous months.

EIA estimates that petroleum and other liquid fuels production in countries outside of the Organization of the Petroleum Exporting Countries (OPEC) grew by 1.4 million b/d in 2015. The 2015 growth occurred mainly in North America. EIA expects non-OPEC production to decline by 0.6 million b/d in 2016, which would be the first decline since 2008. Most of the forecast decline in 2016 is expected to be in the United States. Non-OPEC production is forecast to decrease by 0.2 million b/d in 2017.

Changes in non-OPEC production are driven by changes in U.S. tight oil production, which is characterized by high decline rates and relatively short investment horizons, making it among the more price-sensitive globally. Forecast total U.S. liquid fuels production declines by 0.5 million b/d in 2016 and remains relatively flat in 2017.

Forecast OPEC crude oil production increases by 0.7 million b/d in 2016 and by 0.6 million b/d in 2017 with Iran accounting for most of the increase in 2017. EIA assumes that a collaborative production cut among OPEC members and other major producers does not occur in the forecast period, as major OPEC producers continue their stated strategy to maintain market share.

EIA expects global consumption of petroleum and other liquid fuels to grow by 1.2 million b/d in 2016 and by 1.5 million b/d in 2017. Forecast real gross domestic product (GDP) for the world weighted by oil consumption rises by 2.6% in 2016 and by 3.1% in 2017.

U.S. average regular gasoline and diesel fuel retail prices decrease

The U.S. average regular gasoline retail price decreased six cents from the previous week to $1.76 per gallon on February 8, down 43 cents from the same time last year. The Midwest price fell 10 cents to $1.52 per gallon. The West Coast price fell six cents to $2.31 per gallon. The Rocky Mountain price decreased five cents to $1.75 per gallon, followed by the East Coast price, which was down four cents to $1.79 per gallon. The Gulf Coast price decreased three cents to $1.56 per gallon.

The U.S. average diesel fuel price decreased two cents from the prior week to $2.01 per gallon, down 83 cents from the same time last year. The Rocky Mountain price decreased six cents per gallon to $1.91 per gallon. The West Coast price fell four cents to $2.24 per gallon. The East Coast and Gulf Coast prices each fell two cents to $2.09 per gallon and $1.90 per gallon, respectively. The Midwest price decreased one cent to $1.93 per gallon.

Propane inventories fall

U.S. propane stocks decreased by 3.3 million barrels last week to 74.8 million barrels as of February 5, 2016, 9.8 million barrels (15.2%) higher than a year ago. Gulf Coast, Midwest, and East Coast inventories dropped by 2.1 million barrels, 0.9 million barrels, and 0.3 million barrels, respectively. Rocky Mountain/West Coast inventories remained essentially unchanged, declining by only 0.01 million barrels. Propylene non-fuel-use inventories represented 4.2% of total propane inventories.

Residential heating fuel prices increase

As of February 8, 2016, residential heating oil prices averaged $2.09 per gallon, 1 cent per gallon higher than last week and 82 cents per gallon lower than last year’s price for the same week. The wholesale heating oil price this week averaged $1.13 per gallon, 2 cents per gallon less than last week and 85 cents per gallon lower than a year ago.

Residential propane prices averaged $2.03 per gallon, 1 cent per gallon higher than last week’s price and 33 cents per gallon lower than one year ago. Wholesale propane prices averaged 47 cents per gallon, 1 cent per gallon higher than last week and 20 cents per gallon lower than last year.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at EIA.gov

This Week In Petroleum – EIA.gov – Feb. 3, 2016

East Coast, Gulf Coast trade transportation fuels to balance needs, supply

With just over half of total U.S. refining capacity, the Gulf Coast (Petroleum Administration for Defense District, or PADD, 3) is the largest domestic supplier of transportation fuels. Regional consumption is less than one-third of in-region production. The East Coast (PADD 1) is the largest transportation fuels consuming region in the country. However, that region’s limited refinery capacity produces transportation fuels to meet just one-fifth of regional consumption. Pipeline infrastructure linking the two PADDs and international trade play key roles in balancing the mismatch between the supply and use of transportation fuels within each region (Figure 1).

On February 3, the U.S. Energy Information Administration (EIA) released aPADD 1 and 3 Transportation Fuels Markets study, which examines transportation fuels (motor gasoline, distillate fuel, and jet fuel) supply, consumption, and distribution at both the PADD level and for specific areas within the PADDs.

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The East Coast region includes states from Maine to Florida along the U.S. Atlantic Coast. The Gulf Coast region comprises states between New Mexico in the west to Alabama in the east, primarily along the Gulf of Mexico. For this study, transportation fuels include gasoline, distillate fuel (including diesel), and jet fuel. Residual fuel oil supply is also analyzed where applicable.

The study considers the East Coast as four distinct regions: New England (PADD 1A), Central Atlantic (PADD 1B), the Southeast, and Florida. The Gulf Coast is divided into five regions: New Mexico, Texas Inland, Texas Gulf Coast, Louisiana Gulf Coast, and North Louisiana-Arkansas (Figure 2).

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The study examines transportation fuels supply, consumption, and distribution patterns within the specific sub-PADD regions. The study evaluates the supply, storage, and distribution of transportation fuels from in-region refineries and other domestic sources of supply as well as imports. The study characterizes the infrastructure associated with the distribution of transportation fuels including infrastructure associated with refineries, bulk terminals, pipelines, marine movements, as well as transportation fuel distribution patterns. The study also considers regional supply/demand balances and includes a discussion of the wholesale and retail market structure for each region.

This study is the second in a series by EIA to inform its analyses of petroleum product markets, especially during periods of supply disruptions and market change. A previously published study analyzed PADD 5 (West Coast) transportation fuels markets. Planned studies will analyze PADD 5 crude supply and the transportation fuels markets in the Midwest (PADD 2) and Rocky Mountains (PADD 4).

U.S. average retail regular gasoline and diesel fuel prices decrease

The U.S. average retail price for regular gasoline decreased three cents from the previous week to $1.82 per gallon on February 1, 2016, down 25 cents from the same time last year. The West Coast price decreased eight cents to $2.38 per gallon, followed by the Rocky Mountain price, which decreased six cents to $1.80 per gallon. The Gulf Coast price was down four cents to $1.59 per gallon. The East Coast price decreased three cents to $1.84 per gallon, and the Midwest price was down one cent to $1.62 per gallon.

The U.S. average diesel fuel price decreased four cents from last week to $2.03 per gallon, down 80 cents per gallon from the same time last year. The West Coast, Rocky Mountain, and Midwest prices each fell five cents to $2.27 per gallon, $1.97 per gallon, and $1.94 per gallon, respectively. The Gulf Coast price was down four cents to $1.92 per gallon. The East Coast price decreased three cents to $2.11 per gallon.

Propane inventories fall

U.S. propane stocks decreased by 5.6 million barrels last week to 78.1 million barrels as of January 29, 2016, 10.8 million barrels (16.1%) higher than a year ago. Gulf Coast inventories decreased by 3.1 million barrels, Midwest inventories fell by 1.3 million barrels, and East Coast and Rocky Mountain/West Coast inventories each declined by 0.6 million barrels. Propylene non-fuel-use inventories represented 4.1% of total propane inventories.

Residential heating fuel prices increase

As of February 1, 2016, residential heating oil prices averaged $2.08 per gallon, nearly 2 cents per gallon higher than last week and almost 72 cents lower than last year’s price for the same week. The wholesale heating oil price this week averaged $1.14 per gallon, almost 8 cents higher than last week and nearly 69 cents per gallon lower than a year ago.

Residential propane prices averaged $2.02 per gallon, less than a penny per gallon higher than last week’s price and almost 35 cents lower than one year ago. Wholesale propane prices averaged 46 cents per gallon, just over 2 cents per gallon higher than last week and almost 15 cents per gallon lower than last year.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at EIA.gov

This Week In Petroleum – EIA.gov – Jan. 27, 2016

Warm temperatures and low oil prices are reducing home heating expenditures

A combination of warmer-than-expected temperatures and lower-than-expected oil prices have contributed to a reduction in forecast average heating expenditures this winter (October-March) compared with EIA’s forecast in the October 2015 Winter Fuels Outlook. Each October, EIA produces a Winter Fuels Outlook that projects heating fuel expenditures for the coming winter (October through March) based on EIA’s forecast of fuel prices and the National Oceanic and Atmospheric Administration’s (NOAA) forecast for temperatures (as measured by heating degree days). As discussed in the October 2015 Winter Fuels Outlook, the winter of 2015–16 was expected to have lower expenditures than the winter of 2014–15. In the time since that outlook was released, the weather has been much warmer than expected and prices have fallen faster than anticipated, resulting in even lower heating expenditures as forecast in the January Short-Term Energy Outlook (STEO).

Petroleum-based heating fuels, such as heating oil and propane, are used mainly in the eastern part of the United States. Heating oil use is concentrated in the Northeast, and significant amounts of propane are used in both the Northeast and Midwest. According to the January STEO, these areas of the country are expected to be roughly 20% warmer than last winter (Figure 1). At the beginning of the winter, the Northeast and Midwest were expected to be 13% and 11% warmer than last winter, respectively. However, January is typically the coldest month of the winter, and if January turns out to be significantly colder than forecast, averages for the whole winter will move closer to normal.

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At the national level, as of NOAA’s December forecast, the 2015–16 winter is expected to be 15% warmer than last winter, as the warm temperatures east of the Rocky Mountains are partially offset by temperatures in the West that are both slightly colder than previously forecasted and colder than last year’s relatively warm winter.

In addition to the warm weather, falling crude oil prices and ample supplies of distillate fuel have contributed to lower retail fuel prices than forecast in October. Heating oil prices in particular have been weak, with the average winter 2015–16 retail price now expected to be $2.17/gallon (gal), down from a forecast of $2.57/gal in October. Last winter, retail heating oil prices averaged $3.04/gal. As a result, the average household that heats primarily with heating oil is forecast to spend $760 (41%) less on fuel this winter than last winter (Figure 2).

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Brent crude oil prices are the main driver of retail heating oil prices, and Brent prices fell from a monthly average of $48 per barrel (b) in October to an average of $31/b through the first 20 days of January. That $17/b price decline is equivalent to about 40 cents/gal. EIA did not foresee this drop in price in the October outlook. Crude oil prices fell sharply in recent months, as OPEC producers (at their December 4 meeting) indicated plans to continue the policy of defending market share in a low oil price environment and as global oil inventories continued to build, with the monthly average Brent spot price in December reaching its lowest level since mid-2004.

Strong supply and weak demand globally for distillate fuel (a fuel category that includes products such as diesel and heating oil) have reduced refining margins for distillate, further contributing to low heating oil prices. EIA estimates that the refining margin for heating oil in January is about 28 cents/gal, the lowest margin in January since 2011. Slowing economic growth in emerging economies and a relatively warm winter have reduced growth in global demand for distillate fuel. Additionally, strong gasoline refining margins for this time of year have encouraged high global refinery runs. This combination of high refinery runs and slowing demand growth has resulted in high inventory levels in major distillate markets including Asia, northwest Europe, and the northeast United States. For the week ending January 15, distillate fuel inventories in the northeast United States were 51.8 million barrels, 55% higher than the five-year (2011-15) average.

Retail propane prices have also been lower than was forecast in the October STEO. In the January STEO, EIA forecast winter 2015-16 propane prices to average $2.73/gal in the Northeast and $1.56/gal in the Midwest, down 12 cents/gal and 10 cents/gal, respectively, from the projections at the beginning of winter. These prices are also lower than last winter. Propane prices did not fall as rapidly as heating oil prices this winter because propane prices are partially tied to natural gas prices, which have declined but by less than oil prices. The link to natural gas prices occurs because a significant amount of propane is produced at natural gas processing plants and because propane competes in the petrochemical feedstock market with other hydrocarbon gas liquids produced at natural gas processing plants, such as ethane. In the January STEO, EIA forecasts that households that heat primarily with propane will, on average, see heating expenditures fall by $540 (24%) in the Northeast and by $480 (31%) in the Midwest compared with last winter.

U.S. average regular gasoline and diesel fuel retail prices decrease

The U.S. average regular gasoline retail price fell six cents from the previous week to $1.86 per gallon on January 25, 2016, 19 cents lower than the same time last year. The Midwest price was down eight cents to $1.63 per gallon. The West Coast price decreased six cents to $2.46 per gallon. The Rocky Mountain price decreased five cents to $1.86 per gallon. The Gulf Coast and East Coast prices each decreased four cents to $1.63 per gallon and $1.87 per gallon, respectively.

The U.S. average diesel fuel price decreased four cents to $2.07 per gallon, down 80 cents from the same time last year. The Rocky Mountain and Gulf Coast prices each fell six cents per gallon to $2.02 per gallon and $1.96 per gallon, respectively. The Midwest price was down four cents to $1.99 per gallon. The West Coast and East Coast prices decreased three cents to $2.33 per gallon and $2.14 per gallon, respectively.

Propane inventories fall

U.S. propane stocks decreased by 6.2 million barrels last week to 83.7 million barrels as of January 22, 2016, 14.4 million barrels (20.8%) higher than a year ago. Gulf Coast and Midwest inventories dropped by 4.0 million barrels and 1.7 million barrels, respectively, while East Coast inventories fell by 0.4 million barrels and Rocky Mountain/West Coast inventories declined by 0.1 million barrels. Propylene non-fuel-use inventories represented 3.9% of total propane inventories.

Residential heating oil price decreases; propane price increases

As of January 25, 2016, residential heating oil prices averaged $2.06 per gallon, 5 cents per gallon lower than last week and 75 cents lower than one year ago. The wholesale heating oil price this week averaged $1.07 per gallon, 7 cents higher than last week and 69 cents per gallon lower than a year ago.

Residential propane prices averaged $2.02 per gallon, less than 1 cent per gallon higher than last week’s price and 35 cents lower than one year ago. Wholesale propane prices averaged 44 cents per gallon, 3 cents per gallon higher than last week and 19 cents lower than last year’s price for the same week.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at EIA.gov

This Week In Petroleum – EIA.gov – Jan. 13, 2016

Crude oil prices will remain relatively low through 2016 and 2017

The Short-Term Energy Outlook (STEO) released on January 12 forecasts that Brent crude oil prices will average $40 per barrel (b) in 2016 and $50/b in 2017. This is the first STEO to include forecasts for 2017. Forecast West Texas Intermediate (WTI) crude oil prices average $2/b lower than Brent in 2016 and $3/b lower in 2017. However, the current values of futures and options contracts continue to suggest high uncertainty in the price outlook (Figure 1). For example, EIA’s forecast for the average WTI price in April 2016 of $37/b should be considered in the context of recent contract values for April 2016 delivery (Market Prices and Uncertainty Report), suggesting that the market expects WTI prices to range from $25/b to $56/b (at the 95% confidence interval).

The confidence range for crude oil prices as shown in Figure 1 is derived using a variation of the Black-Scholes that is often used by financial analysts to estimate the price of options. EIA starts with options prices for WTI crude oil, and uses the Black-Scholes model to calculate the implied volatility. WTI futures contracts and options are the among the most actively traded commodity derivative products, with many producers, consumers (including refiners, airlines, trucking companies, and fuel distributors), and other investors and risk-takers involved. The confidence interval is thus a market-derived range that is not directly dependent on EIA’s supply and demand estimates.

Continuing increases in global liquids inventories have put significant downward pressure on oil prices since mid-2014. EIA estimates that global oil inventories increased by 1.9 million b/d in 2015, marking the second consecutive year of inventory builds. This oversupply has contributed to oil prices falling to the lowest monthly average since mid-2004. Inventories are forecast to rise by an additional 0.7 million b/d in 2016, before the global oil market becomes relatively balanced in 2017 (Figure 2). The first draw on global oil inventories in 15 consecutive quarters is expected in the third quarter of 2017.

EIA estimates that petroleum and other liquid fuels production in countries outside of the Organization of the Petroleum Exporting Countries (OPEC) grew by 1.3 million b/d in 2015. The 2015 growth occurred mainly in North America. EIA expects non-OPEC production to decline by 0.6 million b/d in 2016, which would be the first decline since 2008. Most of the forecast decline in 2016 is expected to be in the United States. Non-OPEC production is forecast to decrease by an additional 0.1 million b/d in 2017.

Changes in non-OPEC production are driven by changes in U.S. tight oil production, which is characterized by high decline rates and relatively short investment horizons that make it among the more price-sensitive crude production globally. Forecast total U.S. liquid fuels production declines by 0.4 million b/d in 2016 and remains relatively flat in 2017.

Forecast OPEC crude oil production increases by 0.5 million b/d in 2016, with Iran expected to increase production once international sanctions targeting its oil sector are suspended. Although uncertainty remains as to the timing of sanctions relief, EIA assumes the implementation occurs in the first quarter of 2016, clearing the way to ease sanctions at that time. EIA has moved up the anticipated implementation day because Iran has made faster-than-expected progress in meeting key obligations required under the Joint Comprehensive Plan of Action.

Iran’s crude oil production is forecast to grow by about 0.3 million b/d in 2016 and by 0.5 million b/d in 2017. The growth of Iran’s crude oil production through the forecast period also depends on internal factors, including Iran’s ability to mitigate production decline rates and meet technical challenges, and on its willingness to discount the price of oil.

At OPEC’s December 4 meeting, members voted to reactivate Indonesia’s OPEC membership after an almost seven-year hiatus. EIA therefore includes Indonesia’s crude oil and other liquids production in the OPEC total for both history and the forecast.

EIA expects global consumption of petroleum and other liquid fuels to grow by 1.4 million b/d in both 2016 and 2017. Forecast real gross domestic product (GDP) for the world weighted by oil consumption, which increased by an estimated 2.4% in 2015, rises by 2.7% in 2016 and by 3.2% in 2017.

U.S. average retail regular gasoline price below $2.00 per gallon for the first time since 2009; diesel fuel prices decrease

The U.S. average retail price for regular gasoline fell three cents from the previous week to $1.996 per gallon on January 11, 2016, 14 cents lower than the same time last year and the first time since March 2009 that the U.S. average was below $2.00 per gallon. The Midwest price fell four cents to $1.82 per gallon. The West Coast and East Coast prices each decreased three cents to $2.63 per gallon and $1.97 per gallon, respectively. The Gulf Coast and Rocky Mountain prices both decreased two cents to $1.73 per gallon and $1.95 per gallon, respectively.

The U.S. average diesel fuel price decreased three cents from the prior week to $2.18 per gallon, 88 cents lower than the same time last year. The Rocky Mountain price was down six cents to $2.13 per gallon. The West Coast price decreased four cents to $2.43 per gallon. The East Coast, Midwest, and Gulf Coast prices all decreased three cents to $2.23 per gallon, $2.10 per gallon, and $2.08 per gallon, respectively.

Propane inventories fall

U.S. propane stocks decreased by 4.5 million barrels last week to 91.9 million barrels as of January 8, 2016, 17.0 million barrels (22.7%) higher than a year ago. Gulf Coast inventories decreased by 2.9 million barrels and Midwest inventories decreased by 1.2 million barrels. East Coast and Rocky Mountain/West Coast inventories each decreased comparatively modestly, falling by 0.3 million barrels and 0.1 million barrels, respectively. Propylene non-fuel-use inventories represented 3.4% of total propane inventories.

Residential heating oil price decreases while propane price increases

As of January 11, 2016, residential heating oil prices averaged $2.16 per gallon, almost 2 cents per gallon lower than last week and nearly 75 cents lower than one year ago. The average wholesale heating oil price this week is $1.09 per gallon, 9 cents lower than last week and almost 70 cents per gallon lower than a year ago.

Residential propane prices averaged $2.01 per gallon, 1 cent per gallon higher than last week’s price and nearly 34 cents lower than one year ago. Wholesale propane prices averaged just over 43 cents per gallon, 2 cents per gallon lower than last week and nearly 14 cents lower than last year’s price for the same week.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at www.EIA.gov.