Features

Energy Secretary: US Will Move Quickly on LNG Export Permits

New US Energy Secretary Ernest Moniz said his department will move "expeditiously" to process more applications for liquefied natural gas export (LNG) licenses, but he gave no further details about the pace of the licensing process.

The high level of interest in US policy on LNG exports was evident during a question and answer period after Moniz spoke at a US Energy Information Administration (EIA) conference in Washington on Monday.

About 20 of the two dozen or so questions asked by audience members dealt with the timeline for decisions on additional LNG exports. 

Shortly before Moniz was confirmed last month, Freeport LNG joined Cheniere's Sabine Pass as the second LNG liquefaction facility to secure government approval to export gas to countries that do not have a free trade agreement with the US (OD May20'13).

The last couple of years have seen the emergence of a backlog of more than a dozen export license applications, driven by the sharply higher prices that can be obtained for gas overseas.

LNG cargoes sold into Europe and East Asia have fetched prices as much as four times the domestic price of gas in the US.

"In my first few weeks at the department, I have had a pretty thorough review of the processes," Moniz said during his presentation.

"We are getting to the point of the specific evaluation of license application, which I pledge to do as expeditiously as I can," he said.

Moniz, who was a physics professor at the Massachusetts Institute of Technology before replacing Stephen Chu as energy secretary, remarked how the energy landscape has changed dramatically since President Barack Obama took office in January 2009.

Among other things, he mentioned a doubling of renewable energy production in the US since 2009, adding that US renewable energy output is expected to double again by 2020. 

He noted that the US automobile industry has largely recovered from its near bankruptcy in 2009, thanks to government support, and that the Obama administration's push to increase fuel economy standards by up to 40% by 2025 could cut US oil demand by up to 3 million barrels a day. (OD Sept.22'11).

However, Moniz said the biggest change of all in the US energy space since 2009 has been the staggering growth of shale gas and tight oil production. 

The surge in domestic gas production has opened the door to exports of LNG from the US, which until quite recently had been expected to become a major importer of LNG.

Major consumers and processors of natural gas such as Dow Chemical have spoken out against LNG exports, arguing that they could drive up the cost of gas in the US and lead to less investment and fewer jobs at home.

Such criticism has slowed down the permitting process for would-be LNG exporters.

Moniz suggested that a major shift in global energy markets is just beginning and that it could have a "profound effect" on US energy security, especially if large-scale shale gas development takes off in other parts of the world. 

The EIA recently issued a report which indicated that in addition to the US, countries such as China, Argentina, Algeria, Canada, Mexico, Australia and South Africa have large technically recoverable shale gas resources (OD Jun.11'13).

Bill Murray, Washington


GeoPark Reports Another Oil Discovery in Colombia

GeoPark Holdings, a London-listed independent that focuses on Latin America, has announced a heavy oil discovery in Colombia, adding to its list of recent finds in the South American country.

The Tarotaro discovery was made in the Llanos 34 Block in Colombia's oil-rich Llanos Basin. The Tarotaro-1 exploration well was drilled to a depth of 3,175 meters and produced at a rate of 2,239 barrels per day of crude with a water cut of 0.6%. 

The crude -- with an API gravity of 15.5° -- is already being marketed and sold, the company said. Another well, Tarotaro-2, is being drilled to further appraise the field.

GeoPark operates the Llanos 34 block with a 45% working interest. Canadian independents Parex Resources and P1Energy hold stakes of 45% and 10%, respectively.

The Tarotaro field is the second discovery announced by GeoPark this month and its fourth in Colombia since it began operations in the country in early 2012. The company has interests in 27 upstream blocks in South American spanning Argentina, Brazil, Chile and Colombia.

GeoPark's previous discoveries were dubbed Max, Potrillo and Tua (OD Jan.3'13). All of them are located in the Llanos Basin, which accounts for most of Colombia's output and is home to the large producing fields Chichimene, Quifa and Rubiales. 

The company had net production of 4,932 b/d in the first quarter of 2013, a 66% increase over the same period of last year.

"GeoPark is pleased to announce our fourth new oil field discovery in Colombia in a little more than a year, and we believe these results further demonstrate our team's ability to consistently find and develop oil and gas reserves through the drill bit," said Chief Executive James Park.

"We have seen step-change growth in our production, reserves and cash flow since entering Colombia last year and we look forward to additional positive results from the ongoing 2013 drilling campaign, both in Colombia and Chile."

The company plans to carry out a 35-45 well drilling program this year in Chile and Colombia, with anticipated capital spending of $200 million to $300 million.

The news of the Tarotaro discovery follows an announcement by GeoPark on Jun. 6 that it had drilled, tested and started production from the Potrillo 1 exploration well in the Yamu Block in the central Llanos Basin. The well was drilled to a depth of 3,560 meters and produced around 650 b/d of light oil with an API gravity of 33°. 

Naki B. Mendoza, Washington


Carrizo Raises Guidance for Production, Capital Spending

Carrizo Oil & Gas has raised its guidance for production and capital spending on the strength of better-than-expected results from the company's oil operations in the Eagle Ford Shale of South Texas.

The Houston-based independent said its Eagle Ford oil production averaged about 9,500 barrels per day in the first two months of the second quarter, a result that Chief Executive Chip Johnson described as "outstanding."

Carrizo now estimates that company-wide oil production will average 10,800-11,200 b/d for the second quarter, a 12% increase over its previous guidance of 9,600-10,000 b/d for the period.

Guidance for full-year oil production was also bumped up by 12% to 10,600-11,200 b/d, with the company's full-year production of all hydrocarbons now pegged at 27,433-29,200 barrels of oil equivalent per day.

Carrizo is maintaining its prior guidance for natural gas and NGLs at 90 million-94 million cubic feet of gas equivalent per day.

Increased productivity and drilling efficiency in the Eagle Ford has prompted Carrizo to increase its planned capital spending for this year to $530 million-$540 million, up from its previous target of $500 million.

The additional spending will be used to step up drilling activity in the Eagle Ford, the Niobrara Shale in Colorado and the Utica Shale in Ohio.

Carrizo now plans to drill three more wells than the 41 net (60 gross) it had originally planned in the Eagle Ford, where the company operates three rigs across 53,000 net acres and already operates 87.4 net (113 gross) wells.

It also plans to complete 21 net wells in the Niobrara, up from its earlier goal of 17-18, and before the end of 2013 it will spud a second well in the Utica, where in January the company upped its acreage to 14,000 net acres (OD Jan.16'13).

Chris Raine, New York


Crude Futures Fall Despite Growing Tensions in Mideast

Brent crude oil futures touched a 10-week high of almost $107 a barrel on Monday as tensions in the Middle East rose, but prices finished slightly lower on the day after a late sell-off in US gasoline futures.

US crude oil hit a nine-month high near $99/bbl but also reversed direction to settle lower, with investors cautious ahead of the start of the US Federal Reserve's two-day policy committee meeting on Tuesday. The meeting may provide more clarity on when the central bank will reduce its stimulus program.

In London, Brent crude futures settled down 46¢ a barrel at $105.47. In New York, the Nymex WTI crude contract shed 8¢ to finish at $97.77.

Brent's premium over US crude ended at $7.70, at the narrow end of the $7.50 to $10 range in which it has traded since early May.

US gasoline futures fell more than 1% as traders eyed refineries returning from planned maintenance work, including BP's 405,000-barrel-per-day Whiting refinery in Indiana (OD Jun.10'13).

Investors were cautious before the Fed meeting as Chairman Ben Bernanke may provide more clarity on how and when the central bank will reduce its stimulus program.

"People are going to want to hear what's going to come out of the G8 meeting and we also have the Fed meeting coming," said Mark Waggoner, president of Excel Futures in Bend, Oregon. "They're waiting on the sidelines."

The market was also watching a standoff over the civil war in Syria as President Barack Obama and Russia's Vladimir Putin sought to find common ground at the G8 meeting in Northern Ireland on how to bring Syrian leader Bashar al-Assad to the negotiating table.

Syria is not key to global oil supply, but investors are worried the civil war there could affect other countries in the Middle East and plunge the whole region into conflict.

Reuters


Chevron, Total Expand Upstream Positions in Iraqi Kurdistan

Chevron and France's Total have separately expanded their upstream positions in Iraq's semiautonomous Kurdistan Regional Government (KRG), with Chevron announcing Monday that it has acquired an interest in and operatorship of the Qara Dagh production sharing contract and Total an 80% stake in the Baranan Block, in which the balance is held by the KRG.

KRG Natural Resources Minister Ashti Hawrami said in January that a deal had been signed with Chevron to develop Qara Dagh, but Chevron until Monday had declined to comment (OD Jan.25'13). The block was relinquished by Canada's Niko Resources and partners Vast Exploration and Groundstar Resources last year.

Donnie MacDonald, president of Chevron Iraq, said in a statement that, "Chevron views the Kurdistan Region of Iraq as an area of significant resource potential and the acquisition of the Qara Dagh Block, together with our two existing blocks, advances our strategy of pursuing attractive and high-impact growth opportunities."

Chevron acquired operating stakes in the KRG's Rovi and Sarta blocks from India's Reliance last July, prompting Baghdad, which views KRG oil contracts as illegal, to declare the firm would be blacklisted from any future projects.

Chevron itself has no upstream position in Iraq's south, although its ChevronPhillips chemicals joint venture is still pursuing petrochemical opportunities there.

Canada's Talisman Energy meanwhile relinquished its interest in the Baranan Block last year. Total in a statement to Reuters said that its "participation in an operated exploration block was contemplated at the time Total made its move in Kurdistan during the summer of 2012."

Total last July announced its acquisition of 35% interests from US Marathon in the Harir and Safen blocks in the Kurdistan region, including operatorship of the latter block, and a month later revealed the purchase of a 20% interest in the Taza Block from Toronto-listed ShaMaran Petroleum -- despite Iraq's central government warning that it risked losing its stake in the producing Halfaya oil development in the south (OD Aug.21'12). Halfaya, in which Total has an 18.75% interest, is operated by CNPC's PetroChina.

US Exxon Mobil and Russia's Gazprom Neft also have acreage positions in both the Kurdistan region and Iraq's south. Baghdad has said oil companies must choose between it and the KRG, but so far the status quo has endured.

The KRG's Hawrami said in January that the KRG was in talks with "two or three" major oil companies about exploration deals but declined to name the firms.

Jill Junnola, London


Angola LNG Shuts Down After Shipping First Cargo to Brazil

Angola LNG (ALNG) shipped its first cargo over the weekend to meet its latest self-imposed deadline, but it will now shut down before restarting sometime in August, a spokesman tells Oil Daily sister publication LNG Intelligence.

The first shipment is headed to Brazil's southeastern Rio LNG terminal after departing Soyo on Jun. 16 on board the Sonangol Sambizanga -- one of the project's dedicated seven-strong fleet (LNGI Jun.12'13).

Due to come on line 18 months ago, the 5.2 million ton per year (700 million cubic feet per day) ALNG plant was delayed from starting up by a series of technical glitches and fires (WGI May22'13). 

ALNG spokesman Rob Foyle says the facility will not be exporting any more cargoes straight away, despite the presence of three of the project's tankers drifting offshore.

"As is standard with similar projects, the [engineering] contractor plans to shut down the plant after the first cargo has been loaded to run a series of tests and checks and ensure the ongoing safe and reliable production of LNG," Foyle said. "Following these tests, we plan to restart the plant and ramp up production." 

Although he declined to say when the restart would take place, LNGI understands it is expected in August.

The first new LNG supply to come on line since 2010, ALNG will help meet global demand, which is expected to remain fairly tight over the coming years, with limited new capacity coming on stream. ALNG is especially well-placed to cater to the world's current premium market in South America as the region enters its winter season. 

Like a number of upcoming LNG projects, the liquefaction plant was originally expected to supply the US market, but that country's shale revolution has meant other customers had to be found. Several of ALNG's first cargoes are expected to head to Mexico as part of state monopoly CFE's first-ever tender.

At $10 billion, Angola's LNG project is the largest single investment in the West African country's oil and gas industry.

According to ALNG Chairman Antonio Orfao, "The project provides a solution to minimize flaring and environmental pollution by gathering associated gas from Angola's offshore oil fields," which have historically been flared or re-injected.

Ed Gomersall, London


Majors Step Up Investment as Alaska Implements Tax Reforms

The ink is barely dry on a set of industry-friendly tax code reforms in Alaska, but changes have already triggered pledges for up to $5 billion in new investments from established players BP and ConocoPhillips. If the pace of investment continues, the resultant additional supply from Alaska's North Slope could go a long way toward reviving throughput on the aging Trans-Alaska oil pipeline system, as well as support a mooted natural gas pipeline and LNG export project.

From 2007 to early 2013, Alaska's progressive production tax scheme started at 25%, rising 0.4% for every dollar a company's netback surpassed $30 per barrel (or million Btu equivalent) up to a maximum rate of 50% (OD Jun.4'13). In April, however, Alaska's legislature and Governor Sean Parnell ended several years of debate by adopting a revised flat tax rate of 35%, which the oil industry has heralded as a much more competitive fiscal scheme.

BP recently cited the tax changes as a key factor behind the unveiling of $1 billion in new E&P investments. Those plans include adding two drilling rigs to the UK major's North Slope fields over the next five years, bringing its rig fleet in the state to nine, nearly double a recent low of five in 2012. The plans will also include more well-work activity and the upgrading of existing facilities. BP said the investment is separate from a possible $3 billion being evaluated for new development projects in western portions of the Prudhoe Bay field, which minority partners Exxon Mobil and Conoco are now willing to consider as well.

BP's news followed Conoco's announcement earlier this year that it would bring an additional rig into the Kuparuk River Field this spring, work with co-owners to fund a new drill site on the southwest flank of Kuparuk, enter the regulatory/permitting phase and progress engineering work for the Greater Moose's Tooth Unit in the National Petroleum Reserve-Alaska. "We have consistently said that the passage of [tax reforms] should create a more attractive business environment that we believe will lead to increased investment and additional production," a Conoco spokeswoman said.

That sentiment is shared by Spanish major Repsol, which has yet to detail upsized investment plans but nonetheless cited the possibility of such reform as the reason why the company added onshore positions on the North Slope back in 2011. Repsol and partners Armstrong Oil and Gas and GMT Exploration announced three oil discoveries on their acreage earlier this year and said the drilling results alongside the newly passed tax reforms are "encouraging" for future development.

The production tax changes are also considered key for plans to commercialize the Alaskan North Slope's massive, stranded natural gas resources -- including associated gas that is currently extracted from established oil fields and reinjected. The recent reforms provide some long-term certainty for gas production, although most observers say other financial assurances must be ironed out before firm shipping commitments can be formally filed. This includes a property tax regime that more effectively measures the value of the proposed cross-state pipeline and LNG export terminal in southern Alaska envisioned by Exxon, Conoco, BP and TransCanada (EIF Oct.10'12).

Exxon Chief Executive Rex Tillerson recently put the value of the proposed 3.5 billion cubic feet per day (25 million ton per year) LNG venture at more than $50 billion -- more than 10 times what the companies are planning to spend on expanding oil production over the next half decade. But before the partners move forward with that level of investment, Tillerson says they must be guaranteed the fiscal regime guiding the project will stay fixed over its lifetime: "We have to have stable fiscal terms to make a $50 billion-plus investment. They have got to come to grips with that before we move forward."

Another source of supply set to underpin the project is the undeveloped Point Thomson gas-condensate field, where operator Exxon hopes to begin production by 2016. Investments have been moving along there as well: UK-based engineering and construction group Kentz said last week that it was awarded a three-year contract for a gas cycling and condensate production plant at the field, which is estimated to hold 8 trillion to 9 trillion cubic feet of natural gas and hundreds of millions of barrels of liquids. That follows a US Army Corps of Engineers wetlands-fill permit granted in late October that allows Exxon to begin building needed infrastructure for field development.

Energy Intelligence Finance

This article was originally published in Oil Daily sister publication Energy Intelligence Finance.


Americas

Abraxas Sells Non-Operated Bakken Shale Acreage

Abraxas Petroleum has inked an agreement to sell roughly 13,500 non-operated net acres in the Bakken Shale oil play in North Dakota and Montana to Natural Resources Partners for $35.3 million.

Natural Resources Partners will also assume $8.1 million in authorization for expenditures (AFEs) from 22 producing wells that have recently been drilled or completed, or in which Abraxas has elected to participate.

Abraxas intends to use the proceeds from the sale, and others this year, to pay off some of its debt and accelerate production growth from its core properties in the Bakken Shale and the Eagle Ford Shale of South Texas.

The company said it has divested around 502 boe/d of production this year -- including the Bakken transaction -- for gross proceeds of $47.3 million. 

These sales have removed roughly $10 million of capital spending commitments from its 2013 budget, it noted.

Earlier this year, the San Antonio-based producer unveiled its plan to offload more than 14,000 non-operated net acres in the Bakken Shale and Three Forks formation outside of its core operating area with production of around 400 boe/d.

It said the non-core assets are located in Billings, Burke, Divide, Dunn, McKenzie, Stark and Williams counties, North Dakota and Richland, Roosevelt and Sheridan counties, Montana.

The company's core Bakken/Three Forks operating area is located in portions of McKenzie and Richland counties.


Green Light for Tesoro Pipeline Acquisition

Oil refiner Tesoro won approval from US antitrust regulators to buy Northwest Products Pipeline system and related assets from Chevron, on the condition it sells a petroleum terminal in Boise, Idaho.

Tesoro struck a deal in December to buy the assets from Chevron for $400 million but lowered the price in May to $355 million after a renegotiation.

As part of the deal, Tesoro bought the 760-mile pipeline, along with a series of terminals.

The Federal Trade Commission (FTC) said on Monday that with ownership of two of the three full service light products terminals the proposed transaction would have given the company too much power in the Boise market and therefore required the sale of one terminal.

The FTC said it would allow Tesoro to close the transaction immediately, but sell the terminal within six months.

In a separate transaction, Tesoro won antitrust approval in May to buy a BP refinery in southern California without being required to sell any assets (OD May20'13). That transaction was worth $2.5 billion. (Reuters)


New US NGL Pipelines Start Service

Two major new natural gas liquids (NGLs) pipelines have gone into service in recent months, relieving some of the stress on transportation capacity in the sector, DCP Midstream said Monday. DCP Midstream, Phillips 66 and Spectra Energy are each one-third owners of the two systems.

The 720-mile Sand Hills NGL Pipeline is transporting NGLs produced in the Permian Basin and Eagle Ford Shale to fractionation facilities along the Texas Gulf Coast and in the Mont Belvieu, Texas, market hub.

The pipeline will ramp up to a capacity of more than 200,000 b/d after completion of initial pump stations. Further capacity increases to 350,000 b/d are possible with additional pump stations.

In the Permian, DCP Midstream has NGL processing capacity of 1.3 Bcf/d, and the Rawhide Plant will soon add 75 MMcf/d of additional capacity. 

In the Eagle Ford, DCP Midstream and its master limited partnership, DCP Midstream Partners, have integrated assets that include seven processing plants, which will have a capacity of 1.2 Bcf/d with the completion of the Goliad Plant in the first quarter of 2014.

The 800-mile Southern Hills NGL Pipeline is transporting NGLs from the Midcontinent region to fractionation facilities along the Texas Gulf Coast and in Mont Belvieu. The pipeline will ramp up to a capacity of 175,000 b/d after completion of planned pump stations.

This pipeline provides improved market access for growing production of NGLs in the Midcontinent, where DCP Midstream has a leading position as a gatherer and processor with about 2 Bcf/d of processing capacity.


International

Australia Awards Offshore Blocks

Australia has awarded 13 new offshore exploration permits that are expected to bring in an estimated A$180 million ($187.2 million) in investment in waters off Western Australia and Tasmania over the next three years, according to a statement by Resources and Energy Minister Gary Gray. Proposed secondary work programs could bring in additional investments of above A$550 million.

With the exception of one block offshore Tasmania, the other blocks all lie in the waters off Western Australia, where Royal Dutch Shell snapped up three blocks and Total picked up two blocks. CNOOC, Woodside and Inpex were awarded one Western Australian block each. The awards were part of the first round of 2012's offshore petroleum acreage release.

Offers closed last month in Australia's second round of its 2012 offshore exploration, which put up 12 areas. Australia also offered 31 areas in May as part of its 2013 offshore exploration round, with bids due for the first round by Nov. 21.


Ithaca Farms Down North Sea Licenses

UK independent Ithaca Energy on Monday agreed to farm down in several of its production licenses in the North Sea, in a bid to reduce its exposure to high exploration costs.

Ithaca entered into an agreement with Edison, a subsidiary of French power group EDF, to farm out a 25% interest in the P1631 and P1832 licenses, which contain the Handcross prospect, estimated to hold 115 million barrels of oil equivalent. Handcross is located in the West of the Shetland Islands, and a well is expected to be drilled on the prospect later this year.

Under the terms of the deal, Ithaca will reduce its stake in the licenses from 70% to 45% in exchange for a partial carry of the share of the costs of the exploration well.

In a separate deal, Ithaca signed an agreement with Royal Dutch Shell to farm out 50% of its 100% interest in UK license P2048.

Ithaca said it has a work program that calls for the acquisition of 500 square kilometers of 3-D seismic data. Under the terms of the deal, Shell will pay the full cost of obtaining the seismic data.

Ithaca has the option to keep its 50% interest in the license if it pays Shell the costs of the corresponding share of the work program at a future date. However, if the company is unable to do so, it will transfer its 50% stake to Shell. If this happens, Ithaca said it would not have incurred any costs associated with the work program on the license.


Tables

Daily Oil and Gas Price Review Jun. 17, 2013

All data are produced by Oil Daily in cooperation with Reuters unless otherwise indicated.

Crude Oil Futures and Spot Market Equivalents
($/bbl) Chg. 1st Mth. 2nd Mth. 3rd Mth.
Nymex Lt. Swt. -0.08 97.77 98.03 98.11
ICE Brent -0.46 105.47 105.14 104.77
Chg. Price Mth-Ago Yr-Ago
WTI (Cushing) +0.03 97.86 95.68 84.06
Brent (Dated) +0.70 106.04 104.32 98.31

 

North American Spot Crudes
Cash/Spot ($/bbl) Chg. Price Mth-Ago
WTS (Midland) +0.03 97.66 95.93
LLS -0.27 106.61 106.28
ANS (Calif.) +0.17 107.23 105.92
Mars -0.07 100.56 100.58
Maya (Mexico) +0.02 98.22 98.97
International Spot Crudes and Opec Basket
Cash/Spot ($/bbl) Chg. Price Mth-Ago
Opec Basket* +2.07 103.33 100.85
Nigeria Bonny Lt. +0.70 107.64 106.62
Dubai -0.36 102.46 102.06
Oman +0.78 104.32 102.69
Russia Urals +0.70 105.79 103.77
*Opec Basket price is for previous day.

 

Refined Product Futures
Nymex (¢/gal) Chg. 1st Mth. 2nd Mth. 3rd Mth.
RBOB Gas. -4.06 285.61 284.75 283.11
Heating Oil -1.19 295.03 295.21 295.70
ICE (London) Chg. 1st Mth. 2nd Mth. 3rd Mth.
Gasoil ($/ton) -3.25 894.00 894.25 895.75
Gasoil (¢/gal) -1.03 283.81 283.89 284.37

     

US Gulf Coast Spot Refined Products
(¢/gal) Chg. Price Mth-Ago
Regular Gasoline -2.87 280.33 279.29
Premium Gasoline -2.87 307.83 303.54
Reg. RBOB Gas. -2.87 289.33 291.29
No. 2 Heating Oil -1.01 280.10 272.87
No. 2 LS Diesel -1.01 292.60 287.62
Jet Fuel -1.01 282.85 278.12
($/bbl) Chg. Price Mth-Ago
No. 6 Oil (low sulf)* 0.00 101.03 100.28
No. 6 Oil 1% S† 0.00 98.28 97.78
No. 6 Oil 3% S 0.00 91.78 90.93
*0.7% sulfur low pour †Low pour

 

New York Spot Refined Products
(¢/gal) Chg. Price Mth-Ago
Regular Gasoline -3.37 280.83 280.79
Premium Gasoline -2.87 295.33 296.79
Reg. RBOB Gas. -3.02 286.93 289.74
No. 2 Heating Oil -0.51 282.85 278.37
No. 2 Low Sulfur -1.01 307.10 305.37
Jet Fuel -1.51 287.35 281.12
($/bbl) Chg. Price Mth-Ago
No. 6 Oil (low sulf)* 0.00 100.63 101.28
No. 6 Oil 1% S† 0.00 96.28 95.28
No. 6 Oil 3% S 0.00 91.22 90.63
Los Angeles Refined Products
(¢/gal) Chg. Price Mth-Ago
Reg. RBOB Gas. -8.87 307.83 303.04
No. 2 Low Sulfur -0.01 298.35 286.62
Jet Fuel -0.01 287.35 277.62
Bid prices are for latest spot deals at press time.
* 0.3% sulfur high pour
† High pour

    

Natural Gas Prices
($/MMBtu) Chg. 1st Mth.
Nymex Futures +0.14 3.88
Regional Prices Chg. Price
New York +0.20 3.87
Henry, Louisiana +0.01 3.78
Chicago +0.11 3.86
Rockies (Opal) +0.09 3.61
Southern Calif. Citygate +0.10 4.00
AECO Hub (Canada) +0.07 3.07
Spot natural gas prices from Natural Gas Week

    


Stock Market Scorecard Jun. 17, 2013

All data are produced by Oil Daily in cooperation with Reuters.

Integrated Majors
Close 1-Day 1-Day YTD
Jun 17 Chg. % Chg. % Chg.
Hess 67.51 +1.54 +2.33 +27.47
Total 50.97 +0.87 +1.74 -2.00
Eni 43.93 +0.70 +1.62 -10.60
Exxon Mobil 91.51 +0.93 +1.03 +5.73
BP 43.26 +0.42 +0.98 +3.89
Suncor 30.70 +0.27 +0.89 -6.91
Statoil 22.25 +0.18 +0.82 -11.14
Chevron 121.22 +0.94 +0.78 +12.10
Shell-A 65.90 +0.45 +0.69 -4.42
Shell-B 68.13 +0.41 +0.61 -3.89
EIF Index 411.15 +4.92 +1.21 +7.19

 

Large Producers
Close 1-Day 1-Day YTD
Jun 17 Chg. % Chg. % Chg.
Pioneer 152.32 +5.70 +3.89 +42.90
Canadian Nat. 29.47 +0.76 +2.65 +2.08
Apache 86.52 +1.63 +1.92 +10.22
Marathon Oil 34.99 +0.61 +1.77 +14.12
Chesapeake 21.04 +0.36 +1.74 +26.59
ConocoPhillips 61.94 +0.91 +1.49 +6.81
Talisman 11.64 +0.17 +1.48 +2.74
EnCana 17.70 +0.23 +1.32 -10.43
Devon Energy 55.00 +0.68 +1.25 +5.69
EOG 133.33 +1.59 +1.21 +10.38
Anadarko 87.05 +0.94 +1.09 +17.14
Murphy Oil 63.62 +0.56 +0.89 +6.83
Occidental 92.61 +0.72 +0.78 +20.89

 

Refiners
Close 1-Day 1-Day YTD
Jun 17 Chg. % Chg. % Chg.
Alon 16.73 +0.45 +2.76 -7.52
Tesoro 57.61 +0.45 +0.79 +30.78
Phillips 66 64.26 +0.45 +0.71 +21.02
Valero 37.95 -0.06 -0.16 +21.78
Marathon Pet. 79.00 -0.61 -0.77 +25.40
Holly Frontier 44.67 -0.52 -1.15 -4.04

         


Latest Market Trends Jun. 17, 2013

    


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