News Flow

Tanker demand could signal further price weakness

The global tanker market is sending clues that further upside momentum in crude prices may be limited.

A sudden surge in demand for supertankers drove benchmark charter rates nearly 60%higher in the second quarter. Last year’s crude sell-off pushed the cost of oil for prompt delivery to well below future prices, making it profitable to purchase oil and store it to sell at a later time. One measure of the trend is the Baltic Dirty Tanker Index, which tracks shipping rates for the transportation of crude oil. Analysts follow the index to assess crude tanker companies’ revenue and earnings potential.

Off the coast of West Africa and in the waters of the North Sea, supertankers holding 1 million barrels (MMbbl) of oil have essentially become accidental storage as their owners seek customers.

The vessels are competing with new loadings, as well as time-chartered cargoes that major trading houses such as Trafigura and Unipec booked to store crude months ago and are now selling.

The release of floating oil volumes will introduce additional supply into an already saturated market and exacerbate the number of unsold Mediterranean, North Sea and West African cargoes in the Atlantic Basin. Nearly 55 MMbbl were being stored on tankers—more than double the amount in January, Thomson Reuters data show.

Enterprise foots Eagle Ford bill in Gulf pipeline selloff

Enterprise Products Partners LP effectively found its down payment for its recently acquired Eagle Ford Shale midstream assets with the sale of its Gulf of Mexico (GoM) pipelines, platforms and services to Genesis Energy LP.

Houston-based Enterprise closed on its$2.15 billion purchase of Pioneer Natural Resource Co.’s EFS Midstream LLC, which includes 460 miles of natural gas pipelines, 10 central gathering plants and other facilities.

The Gulf acquisition is divided into two payments, the first for $1.15 billion and the second installed for $1 billion within 12 months. In mid-July, Enterprise said it entered an agreement to sell its GoM pipelines and service businesses to Genesis Energy for about $1.5 billion in cash.

Enterprise sold six offshore hub platforms, ownership interest in nine crude oil pipeline systems consisting of more than 1,100 miles and nine gas pipeline systems totaling about 1,200 miles.

The sale also eliminates any need for equity capital for the remainder of 2015. The company nevertheless already had plenty of liquidity—about $4.3 billion, including unrestricted cash on hand and borrowings under a $3.5 billion, multiyear revolving credit facility and $1.5 billion in a 364-day credit facility.

Leading Asian LNG consumers reduce imports

China, Japan and South Korea—the world’s largest importers of LNG—cut their collective intake by almost 7% in the first five months of 2015 compared to the same time period in 2014, the U.S. Energy Information Administration (EIA) reported in a natural gas update.

The three countries accounted for 61% of global LNG imports in 2014, the EIA said, citing data from the International Group of Liquefied Natural Gas Importers. The EIA attributed the reduced consumption to a variety of factors, including mild weather and government policies favoring other sources of energy for power generation.

South Korea saw the sharpest decrease in LNG imports, an average of 0.9 billion cubic feet per day (Bcf/d) or 15.1% in January through May. Natural gas consumption in that country’s power sector has declined for the past two years as a result of government policies favoring coal and nuclear power over gas.

Japan’s lower imports of LNG were part of the country’s reduced reliance on fossil fuels in general for power generation (7%decline) while hydro generation rose by 16%. Fossil fuel generation has declined despite the sharp decrease in global crude oil prices since second-half 2014. The EIA forecasts a continued reduction in demand for fossil fuels in coming years as Japan prepares for the restarts of two nuclear power plants—Sendai Unit 1 in August and Sendai Unit 2 in October.

China’s drop in LNG imports is related to its increased reliance on cheaper imported pipeline gas. The Chinese Customs Agency reported a 22% hike in pipeline imports, or 0.6 Bcf/d, compared to an 8.7% reduction in imports of LNG.

Study: Utica holds 20x as much gas as believed

A recently released report by West Virginia University sets recoverable gas reserves in the Utica Shale at more than 20 times the estimate of the U.S. Geological Survey (USGS).

The two-year study by the Appalachian Oil & Natural Gas Consortium concluded that the Utica possesses total recoverable resources of 782.2 trillion cubic feet (Tcf) of natural gas, far beyond the previous estimate of 38 Tcf. The neighboring Marcellus Shale is estimated to hold 500 Tcf to 800 Tcf of natural gas.

“The revised resource numbers are impressive, comparable to the numbers for the more established Marcellus Shale play, and a little surprising based on our Utica estimates of just a year ago which were lower,” Douglas Patchen, director of the consortium, said in a statement.

“But this is why we continued to work on the resource estimates after the project of fiscally ended a year ago,” he said. “The more wells that are drilled, the more the play area may expand, and another year of production from the wells enables researchers to make better estimates.”

The study, “A Geologic Play Book for Utica Shale Appalachian Basin Exploration,” also estimates recoverable crude oil at 1.96 billion bbl, or about double the USGS estimate.

“The combination of a relatively shallow reservoir and the potential for liquids production has made this an attractive play,” researchers wrote.

Even if the study overestimates its natural gas figure by a factor of 10, the Utica would still possess more than two-and-a-half times the reserves of Australia, which is on the brink of leading the world in LNG exports.

The study focused on the underlying Point Pleasant Formation, where drilling is concentrated in a north-south trend in eastern Ohio, although more recent drilling in the north has shifted toward the northeast and into northern Pennsylvania. As operators migrate their activities eastward into deeper drilling and higher maturation areas, they encounter dry gas.

Control capex and catch the FLNG wave, report urges

Floating LNG (FLNG) offers oceans of possibilities for keeping the LNG industry economically afloat if operators can bring costs under control, Sanford C. Bernstein & Co. LLC maintains in a new report.

“Up to now we have viewed this technology as largely niche—but increasingly this is hard to do,” Bernstein senior analyst Neil Beveridge states in the report, in which he adds that 10 FLNG vessels are under construction around the world. “Floating regas capacity has come from nowhere to 10% of global [regasification] capacity in only a few years.”

The technology has long been viewed as the key to unlocking stranded gas fields, Beveridge said, but now it is also qualifies as a badly needed approach to cut costs. The cost per ton to build an LNG project has soared from $1,000 10 years ago to almost $4,000 on some of the pricier Australian projects today.

“While the costs of alternative energies, such as wind and solar have been falling,[onshore] LNG costs have been rising,” he said. “This is not sustainable in the low carbon world of the future.”

He drew attention to the world’s largest FLNG project, Prelude, which will be deployed in the Browse Basin’s Prelude Field, about 295 miles northeast of Broome, Australia. Over the 25 years of its anticipated deployment, the facility is expected to develop 3 Tcf of resources, including liquids, LNG, condensate and LPG.

Evolving crude-import flows show major trends

In one of the latest displays of evolving crude-trade flows, the top 10 global crude importers are expected to see significant shifts over the next decade. Imports will remain heavily concentrated in the major refining centers in Asia, Northwest Europe (NWE) and the U.S., but the balance among these importers will begin to change, recent research from U.K.-based BMI Research showed.

As part of their outlook, BMI Research analysts said a third dynamic will occur: a structural shift in regional trade flows.

Based on the analysis of net crude imports into Africa, the Asia Pacific, Central and Eastern Europe (CEE), Latin America, the Middle East, North America and NWE regions, BMI identified three emerging trends in regional crude-trade patterns:

• Increasing insularity of the Americas markets;

• Declining role of NWE refiners; and

• Entrenching core Middle East-Asia trade link.

In its annual five-year oil-market outlook published earlier this year, the International Energy Agency (IEA) said global oil-trade routes are reshaping because the old rules of oil consumption no longer apply.

“The center of gravity of oil demand continues to move east,” the IEA said. “First and foremost, oil demand is no longer about the industrialized world: In 2014, for the first time, developing countries outside the OECD burned more oil than the rich countries inside it. In 2015, for the first time, Asia will consume more oil than the Americas.

The nature of oil consumption is also changing, according to the IEA.

“In the past, there was a straight line between cheaper oil and increased demand.

Not anymore. As a result of the 2008 global financial crisis and increased energy-efficiency efforts, cheaper oil no longer automatically finds buyers.”

EIA gas forecast: well-stocked for winter

Searing heat across the U.S. has slowed the flow of natural gas into storage, but the U.S. EIA still projects that inventories will eclipse the five-year average by 3.2%when the injection season ends at the end of October.

The EIA’s short-term energy outlook reported inventories of 2,577 Bcf at mid-year, or 35% higher than a year earlier and 1% higher than the previous five-year average (2010 to 2014). Despite demands from the electric power sector, end-of-October stocks are still expected to hit 3,919 Bcf, or 121 Bcf above the five-year average.

U.S. crude oil production, however, will continue the decline it began in May, according to the forecast. Overall output will rise to 9.47 MMbbl/d in 2015 from 8.72 MMbbl/d in 2014, an 8.6% increase, but dip 1.6% to 9.32 MMbbl/d in 2016.

What this means for price is a projected 11.4% increase for gas in 2016 vs. 2015, and an 11.8% hike for crude oil. In most years in most industries, these would be celebratory figures. However, they follow the EIA’s annual average estimates of a 32.3% drop in price for natural gas and a 40.7% decline for crude oil in 2015 vs. 2014.

Gas inventory comes into play as winter approaches, and the EIA projects a 6.2%decline in heating degree days on average for the U.S. in the third quarter compared to third-quarter 2014, and virtually no change in the fourth quarter compared to a year ago. Heating degree days is a measure of how cold a location is over a period of time compared to a base temperature, typically 65° F. First-quarter 2016 heating degree days are expected to total 9.1% fewer than 2015 and 13.1% fewer than 2014 for the U.S.

Plus or minus, regulation to have major midstream impact

The direction of future federal and state government energy-industry regulation will have a significant impact on the midstream in the next two decades—either positive or negative. That’s the finding of a new Wood Mackenzie Inc. study prepared for the American Petroleum Institute.

“A Comparison of U.S. Oil and Natural Gas Policies” reviewed what could happen to the oil and gas industry overall by 2035. It plots the potential economic impact on the industry—as well as positive and negative outcomes for job creation, the GDP, government revenues, household income and energy expenditures. The study plotted both upside and downside scenarios and compared them to a baseline forecast that excluded both pro-development policies and sharp regulatory constraints.

“Increases in U.S. oil and natural gas production are expected in all scenarios, but the regulatory environment is expected to have a very material impact on the pace of growth and the peak level achieved,” the Wood Mackenzie study said. “Pro-development policies could increase oil and gas production by 8 million barrels of oil equivalent per day (MMboed), whereas regulatory constraints could reduce it by 3.4 MMboed by 2035.”

In overall employment, the regulatory impact could swing as high as creation of 2.3 million additional U.S. jobs in the next 20 years, or go as low as eliminating 800,000 existing jobs, the report added.

“Midstream investment requirements are expected to be significantly impacted by the future regulatory environment,” the study emphasized. “Cumulative midstream capex is expected to be $118 billion higher through 2035 in the pro-development scenario and $171 billion lower under regulatory constraints.”

Earnings in focus: refiners rule the shale age

Marathon Petroleum Corp.’s (MPC) $15.8 billion deal to expand its growing pipeline network highlights one of the most surprising developments in the shale era: After being written off a few years ago, refiners are making money hand over fist.

Since June 2011, when Marathon Oil Corp. spun off what some thought would be low-margin refining and pipeline units, the top four energy performers on the S&P (Standard & Poor’s) 500 index have been fuel processors—MPC, Phillips 66, Tesoro Corp. and Valero Energy Corp. Tesoro profits have more than quadrupled.

As the U.S. energy renaissance took hold, refineries were among the assets many industry observers thought were either doomed or not worth owning. Over the last four years, however, integrated majors with refining and pipeline assets have reaped the greatest rewards.

The downturn in global crude oil prices since June 2014, which accelerated after November, has coincided with both higher and lower profitability in the downstream sector. U.S. refiners have especially prospered from the crude collapse because of their ability to refine crudes that can be purchased at a discount to global benchmark Brent, which is linked to refined product prices, including diesel, gasoline and jet fuel.

The previously unloved part of the energy business—oil refining—has provided a cushion even as oil-production profits foundered.

Refining more oil at higher profit margins, Marathon Petroleum earned $891 million in this year’s first quarter, up from $199 million in first quarter 2014 when scheduled maintenance idled its largest refineries.

Earnings per share came in at $3.24, vs. analyst estimates of $2.96 per share and a significant improvement from $0.67 per share in first-quarter 2014. The Ohio-based independent refiner also quadrupled its quarterly profits, although its first-quarter revenue declined 26% to $17.24 billion.

Marathon CEO Gary Heminger credited the company’s extensive pipeline system and fleet of barges and towboats, which enabled it to capture the lowest feedstock prices.

“Our record first-quarter earnings highlight Marathon Petroleum’s ability to take full advantage of favorable market conditions,” Heminger said during an April 30 earnings call. “Our extensive logistics and retail networks give us tremendous flexibility in [oil purchasing] and the ability to optimize refining operations and product distribution throughout our marketing footprint.”

Slump could give majors M&A shale opportunities

Upstream deal values have crumbled and activity has gone into hibernation in 2015, but a Goldman Sachs analyst said oil majors could move on prime E&Ps such as EOG Resources Inc. to finally get their footing in U.S. shale.

Ruth Brooker, analyst, Goldman Sachs, said the A-list shale companies are targets for the next stage in the market’s evolution due to their strong positions, low breakeven points and high quality resource life.

“We see 10 to 15 MMbbl/d of production which can be transferred through M&A” to oil majors, Brooker said in a report, “M&A in the New Oil Order.”

Major oil and gas companies are under-exposed to U.S. shale oil, with about 5% of their resources. The majors have also struggled to replace their reserves.

“We expect to see further consolidation within the U.S. shale plays given the majors’ underexposure to this material and improving win-zone,” Brooker said.

Global majors practically have money to burn—about $150 billion in spending power—and could defer up to $325 billion in capex on marginal projects, she said.

Industry groups denounce new EPA methane rules

Energy trade groups are calling proposed U.S. Environmental Protection Agency (EPA) emissions rules announced in August unnecessary, citing the industry’s own success in stemming emissions. The statements followed the EPA’s announcement of standards intended to further cut the release of methane and volatile organic compounds from oil and gas facilities.

• Finding and repairing leaks;

• Capturing gas from completion of hydraulically fractured wells;

• Limiting emissions from new and modified pneumatic pumps; and

• Limiting emissions from equipment used at compressor stations, including compressors and pneumatic controllers.

The agency’s announcement was the first part of a three-step process that could place a new mandate on the industry by the middle of 2016. Other announcements would come late this year.

In the midstream, the Interstate Natural Gas Association of America (INGAA) pointed to major cuts in methane emissions already achieved in its reaction to the EPA, saying the gas transmission industry has reduced the number of leaks on gas pipelines by 94% in the last 30 years.

Don Santa, INGAA president and CEO, called on the EPA “to get a better idea of both the volume of methane released in the atmosphere and the sources of those releases” before setting any new standards. If well completions and frack jobs are a concern for upstream producers, then EPA-proposed pipeline replacements and construction-related blowdowns are a priority for midstream operators.

“While a critical and necessary component of pipeline construction and maintenance activities, pipeline blowdowns (which would be measured as part of the EPA reporting requirements) contribute to methane releases from transmission pipelines. This is one of the reasons why widespread replacement of pipeline will not significantly reduce releases from natural gas transmission pipelines, the pipe itself is not the source of material releases and its replacement may in fact result in greater releases,” Santa said. He then called on government agencies to work together on air-quality issues.