heatingoilinfo

Tightening US storage capacity could quickly become a glut: Fuel for Thought

Demand for storage is reaching a fever pitch with tank capacity and utilization at all-time highs, but the storage market is volatile and at the same time could be barreling toward oversupply.

The US crude market is in contango, meaning crude is worth less for delivery now than later. That dynamic encourages storage, but it could reverse as the contango narrows and production shrinks while tank capacity continues to expand.

There is an easy comparison between the take-or-pay contracts on pipelines and storage tanks, which might give a hint of things to come if the market structure reverses. Under both kinds of contracts, the counterparty has to either use the committed space on the asset or pay a penalty, often as much as the price to use the space in the first place.

In the case of pipelines, that pushed Midland WTI into a premium over its counterpart in Cushing as demand for crude to meet shipping commitments stacked up at the pipelines’ origin terminals. Not only that, but the existence of the contracts helped drive investment in infrastructure, which contributed to the explosive growth in pipeline capacity since the turn of the decade.

If the contracts have a similar effect on the storage market, it would likely manifest in stronger prompt prices, with weaker prices further down the curve — especially if production declines, leaving marketers who expected growth holding contracts to store barrels that don’t exist. For now, at least, imports have been able to keep driving storage demand, but how long might that last as the contango flattens out?

A capacity oversupply would lend strength to the crude prompt market by creating demand simply to meet the contractual commitments that underpin current and upcoming projects’ volume agreements. It could also apply downward pressure to the back end of the contango structure, because cheaper storage lets marketers work slimmer time spreads, Bentek Energy Analysis Manager Anthony Starkey said.

“It doesn’t really ‘solve’ anything, but [an overbuild] could provide that kind of support for oil,” Starkey said.

Though March and April so far have seen a relatively wide contango, with the front-month WTI contract in Midland averaging $1.48/b less than the second-month contract, it is still lower than February, which averaged $1.94/b.

The sustained contango has buoyed crude stocks in the US to an unusually-high 529.9 million barrels. Those stocks are especially concentrated in Cushing, Oklahoma, with 66.32 million barrels and the Gulf Coast, which holds 277.54 million barrels.

Source: http://blogs.platts.com/

Discount Heating Oil Prices is a company where one can find the lowest home heating oil prices. The company also provides delivery assistance to your home punctually and securely. Just visit the official website, enter your zip code, browse the lowest price available on heating oil in your place and click on the “buy now” button. Getting discount heating oil in Massachusetts is now just a click away from you

Central Asian oil: destined to disappoint?

The stagnation pervading Central Asia’s oil industry could be alleviated by a couple of big announcements in the coming months, on the Kashagan and Tengiz fields.

But industry veterans are more heedful of the numerous obstacles presented by the region, from the geological to the bureaucratic, and an unpromising global context.

Home to some of the world’s largest oil and gas fields, ex-Soviet Central Asia and particularly Kazakhstan was once an exciting frontier for the industry. But of late Kazakh oil production has stagnated at around 1.7 million barrels per day, partly because of a decade of delay starting output from the giant Kashagan project.

A consortium led by Chevron has also delayed plans to increase output at Tengiz from around 600,000 b/d to nearly 900,000 b/d, a project that could cost tens of billions of dollars.

In neighboring Turkmenistan, planned gas exports to Europe have made little headway due the cost of building a trans-Caspian pipeline, doubts about European demand, and difficult regional politics.

Turkmenistan’s gas exports have increased — the International Energy Agency expects it to have pipeline capacity for 80 billion cubic meters/year of exports to China by the early 2020s — and it has hopes of eventually building another pipeline across Afghanistan to South Asia.

But for now Turkmenistan is increasingly reliant on China as a sole client. More marginal projects, in Tajikistan and Uzbekistan, are languishing.

Kazakhstan might have thought it need not worry, until oil prices collapsed. But its economy is at a standstill and state finances suffering.

State producer KazMunaiGaz has been at daggers drawn with its upstream subsidiary, a semi-independent entity listed in London.

A row over the parent company’s under-payment for crude appears to be resolved on April 4, but the subsidiary’s scrapping of dividends for 2015 disappointed investors.

Confidence could get a boost if Kashagan starts producing. Foreign executives and Kazakh officials involved in the project have said it will start toward the end of this year.

The project has been dubbed a “failure of the industry” by a top official from France’s Total, chief financial officer Patrick de la Chevardiere, after leaking pipes forced the Kashagan consortium to abort an attempted startup in 2013.

The World Bank has warned that low oil prices increase the chances of further delay.

Whether Kashagan will be trouble-free once it starts producing is also unclear. The field is still at the frontier of what the industry can handle, due to high sulfur levels, which led to the leaks, and intense pressures below the Permian salt layer.

Estimates of how much Kashagan will produce following startup vary. Theoretically it will have a capacity of 370,000 b/d, but Platts has been told the “real” level will be 300,000 b/d annually, reflecting the fact that staff will be barred from the main artificial island used for operations when well intervention work is under way, due to the risk of hydrogen sulfide poisoning.

Once the field starts up, President Nursultan Nazarbayev’s leadership is likely to need additional projects to absorb Kazakh labor and materials. But Kazakhstan’s reputation as a place to invest has been tarnished by sluggish administration, the lack of an independent judiciary and use of strong-arm tactics.

In the latest dispute with investors, the state is demanding $1.6 billion from the consortium that runs the giant Karachaganak oil and gas field. Operated by Shell and Italy’s Eni, Karachaganak produced 390,000 b/d of oil equivalent last year, about 60% being liquids, and is also due for expansion.

The parties “are determined to find a consensual solution and to peacefully resolve the issue,” Kazakhstan’s energy ministry has said.

Above-ground difficulty

Paradoxically, some executives argue in private that the tightening of international anti-bribery regulations has made it more difficult to operate in Central Asia.

The story of the former Soviet Union’s oil sector has long been tainted by claims of corruption, ranging from the mundane giving of fax machines to, in the case of Kazakhstan, transfers of fur coats, speedboats and payments for Swiss boarding schools.

Some reasons for disillusion are less controversial. Geologically, the north Caspian and Kazakhstan’s coast have been thoroughly explored and where resources might still be abundant, corruption is not the only issue.

Tajikistan has hopes of uncovering subsalt resources near the Afghan border perhaps akin to the Galkynysh gas field in Turkmenistan, thought to be the world’s second largest.

But in impoverished Tajikistan even basic letter writing skills are lacking among younger officials, let alone industry or economic competence, a foreign oil executive told Platts, requesting anonymity.

The joint venture conducting a 2D seismic survey across a swathe of Tajikistan has found it hard going. The survey has involved drilling deep holes for the laying of explosives in order to get clear seismic images from beneath the salt layer, adding to costs “significantly,” Julian Hammond, the chief executive of Tethys Petroleum, said.

Tethys, which set up the joint exploration venture with Total and China’s CNPC in 2013, is now under pressure to withdraw due to its inability to meet its share of costs.

While a vibrant mix of large and small companies might revive Central Asia’s oil sector, in reality smaller companies, lacking connections, financial weight or expertise, have struggled.

Reports from London-listed Roxi Petroleum outline numerous difficulties involving the need to pump vast amounts of drilling fluid into its deep, high pressure wells in Kazakhstan to keep them under control, resulting in them becoming clogged, as well as various objects getting stuck thousands of meters below ground.

Others have been overwhelmed by a licensing system that stipulates long periods of “trial” production when oil must be sold domestically at controlled prices.

Getting permission to export typically involves building facilities for eliminating flaring, but this can be difficult when the state forbids the raising of additional funds on stock exchanges without its permission.

The pricing issue was a major reason why Australian independent Jupiter Energy shut down its production in February. It says it could be producing 2,500 b/d of oil from its existing wells, but would fetch just $3-6/b.

Source: http://blogs.platts.com/

Acquisition set to increase Alaska’s jet fuel buying, but still outpaced by majors

The last decade of consolidation in the US airline industry has created some of the world’s largest airlines but the most recent move, the purchase of Virgin America by Alaska Air Group, makes a smaller splash from a jet fuel buying perspective.

The $2.6 billion price tag will give Alaska more of a foothold on the East Coast and help solidify its role on the US West Coast by giving it a larger share of the California market with Virgin America’s slots in San Francisco and Los Angeles. The move has the added benefit of keeping JetBlue, which Alaska says it has now surpassed, from buying Virgin America and adding to its West Coast portfolio.

But even as Alaska says that it is poised to become the fifth largest US airline, it still has a ways to go before it starts to rival the big four, American, Delta, Southwest and United — at least in terms of jet fuel buying.

In terms of fuel consumption and management, the addition of Virgin America’s fleet and routes represents 21% of Alaska’s total fuel usage. In 2015, Alaska used 508 million gallons of jet fuel, paying $1.88/gal, according to the company’s financial reports. Virgin America, on the other hand, used 169 million gal and paid $2.07/gal. Independently, Alaska had been increasing its own fuel consumption, adding 8.3% to its annual fuel buying in 2015.

Despite the addition of Virgin America, Alaska’s fuel consumption still tracks slightly behind JetBlue and significantly behind the other major US carriers. Even if the buyout results in further growth and not slight consolidation of routes, there is a wide gulf between fourth and fifth place. Southwest Airlines was the fourth largest airline in terms of fuel use in 2015, consuming 1.901 billion gallons, according to its financial reports. In total, US carriers used 16.73 billion gallons of jet fuel in 2015 for scheduled service, according to the Bureau of Transportation Statistics.

Rank	Airline	2015 Fuel Consumption (gal)	Average Cost ($/gal)	% of Expenses
1	Delta	3.988 billion	$1.90	23.0%
2	United	3.886 billion	$1.94	23.0%
3	American	3.611 billion	$1.72	21.6%
4	Southwest	1.901 billion	$1.90	23.0%
5	JetBlue	700 million	$1.93	25.9%
6	Alaska	508 million	$1.88	22.0%
7	Spirit	255 million	$1.82	28.3%
8	Hawaiian	234 million	$1.78	22.1%
9	Virgin America	169 million	$2.07	25.7%

Source: Airline Form 10-K annual reports

International routes obviously help the top four airlines with their extra billions of gallons of fuel consumption. Alaska’s international routes currently only include Canada, Mexico and, as of last year, Costa Rica.

Of course, airline mergers can take a significant amount of time to impact trends. It was only last October that US Airways flew its last route, nearly two years after the merger first occurred. Virgin America reportedly already issued a tender for its 2016-17 jet fuel supply. Considering the often-lengthy process of airline mergers and acquisitions, market sources believed that each company’s respective fuel management policy would continue for now, likely delaying any potential and significant changes to the airline’s fuel buying and management strategy.

“So far they [Virgin America] will stick with their own process of bidding alone,” one industry source said. “[They will need] time for the merger to be validated and so on. We have time.”

While Virgin America issues tenders to supply fuel, it outsources its fuel management to World Fuel Services. Alaska manages its fuel in-house, according to market sources.

“Tough to tell which way management goes,” a trader said.

Despite consolidation and some overlap in routes, some in the jet fuel market did not think that there would be a large change in overall industry jet fuel consumption because of the merger.

“Overall the aviation market is growing anyway despite of merging,” added the industry source who said Virgin America is sticking to its bidding process. “I don’t really see real impact here.”

Source: http://blogs.platts.com/

California’s tough rules a blessing and curse for refiners: Fuel for Thought

Refiners operating in California expect a tough environmental regulatory permitting process. This has been a bit of a curse at times, causing long delays and restrictions on modifying their plants.

But it has also been a blessing. While the strict rules make the fuels more expensive to make, it also limits the number of suppliers who can supply the fuel to California, giving regional refiners virtually unlimited access to demand in a state where gasoline demand is greater than any other and growing.

Give this backdrop, it was interesting to see what may have been a brief loosening of restrictions in Southern California because of a personnel change open a window of opportunity for the restart of ExxonMobil’s Torrance refinery.

That reopening, which had been slowly moving through the environmental regulatory process before the ouster of the longtime head of South Coast Air Quality Management District, was necessary before ExxonMobil could sell its Torrance plant to East Coast refiner PBF Energy.

Long-time head of South Coast Air Quality Management District, Barry Wallenstein, was voted out in a 7 to 6 vote taken by the regulatory agency’s 13-person board during a closed session on March 4.

The vote to oust Wallenstein occurred after January’s appointment of two board members shifted the balance of power to the Republican camp, a move which was expected to result in “a loosening of requirements” and less rigorous air quality policies, according to sources familiar with the situation.

The timing of the board change will help facilitate the sale of ExxonMobil’s Torrance refinery to PBF, which is contingent on the proven performance of the refinery’s gasoline-making FCC unit, shut February 2015 after an explosion and a fire.

Wallenstein had headed the agency since 1997, and his removal caused dismay among environmental groups, who feared any loosening of regulations would bring back the nasty smog, which plagued the Los Angeles Basin for years.

In early April, following Wallenstein’s departure, agency approval was given to restart the 87,000 b/d FCC unit at ExxonMobil’s 149,500 b/d Torrance, California, refinery.

The restart was a bone of contention among Torrance residents, due in part to ExxonMobil’s failure to notify the community of a hydroflouric acid pipeline leak last September, an action for which it was fined by the state.

While the Torrance restart plan has multiple stringent and rigorous monitoring requirements, it expects refinery emissions levels would exceed permitted levels because it will not use pollution control devices known Electrostatic Precipitators (ESPs) during the restart process.

“This limitation on use is necessary to ensure the safety of the start-up procedure but will minimize excess emissions to the maximum extent feasible,” the agency’s order of abatement said, referring to not using ESPs continuously during the restart.

Personnel change doesn’t mean looser rules

Industry participants caution in assuming an agency change in Southern California means a loosening in the state’s environmental regulations.

“Our mandate is to ensure petroleum refining activities are done as safely as possible,” said Paul Penn, Emergency Management and Refinery Safety Program Manager at the California Environmental Protection agency.

The California Environmental Quality Act, passed in 1970, requires extensive review of project impacts, using 18 environmental factors to determine whether to issue permits.

Despite the personnel change in Southern California’s air quality regulatory body, the state’s strict guidelines are not under threat — and neither is PBF’s deal for ExxonMobil’s Torrance refinery.

The state’s strict CARBOB gasoline and diesel specifications make the fuels more expensive to produce, it also limits the number of suppliers who can sell the fuel to California drivers.

The higher production cost, combined with logistical issues such as lack of pipelines bringing in product from outside the region and the expense of fixing a Jones Act vessel from other US regions, give regional refiners the upper hand in supplying California and surrounding states like Washington and Arizona, who have opted in to using California spec fuels.

And while other refiners have said at various times they want to leave California, it helps explain why PBF’s iconic executive chairman, Tom O’Malley had been on the look out for a California refinery.

Source: http://blogs.platts.com/

Qatar’s OPEC MAX meeting and the oil price rout that wasn’t

There was much gnashing of teeth as Qatar’s grand meeting of oil producers failed to reach agreement April 17 to freeze production at January levels.

Commentators predicted a collapse in oil prices and some discerned the demise of OPEC itself.

But since then the expected rout in prices has yet to materialize, stock markets have been unfazed, and the outcome from the point of view of OPEC’s dominant Arab Gulf members may not be unsatisfactory.

No doubt some delegates found it annoying to needlessly spend 12 hours cooped up in a five-star hotel in Doha, albeit with a visit to pay their respects to the emir of Qatar, Sheikh Tamim bin Hamad Al Thani.

The failure of the talks was an embarrassment and will be felt by OPEC’s weakest nations, particularly Venezuela, which is in a state of crisis and badly needs oil prices to rise.

That prices did not immediately fall more than a couple of dollars owed something to a strike by oil workers in Kuwait, which caused the country’s production to fall initially to just 1.1 million barrels per day, barely a third of normal levels.

In the aftermath of the talks, Russia, which had invested much effort trying to broker a deal, indicated it would continue pumping at record levels, above 10.8 million b/d, helping to cap prices.

Amidst the failure to agree a freeze and Russia’s determination to boost output, there were reasons for markets not to panic, at least for the time being.

Markets had after all not given much credibility to the proposed production freeze. And production prospects are now depressed not only for Venezuela, but a number of countries worldwide.

Some observers are starting to doubt Iran has much more to offer the market for the time being than the increase it has managed since sanctions against it were lifted in January – generally estimated at 300,000-350,000 b/d.

Investment bank Tudor Pickering Holt said April 18 that further significant increases from Iran would require more capital expenditure, which was “not likely in the current environment.”

More fundamentally, the economic impetus for a production freeze has somewhat waned since the idea was first proposed in February. Back then, prices were around $10/b lower than when the April 17 meeting came round, and had recently hit $27/b, amid generalized worries about the global economy and China in particular.

Since then, the outlook for the world economy can’t be said to have transformed. But in terms of oil demand, some of those jitters have eased, as documented by successive monthly reports from the International Energy Agency.

In February the agency was talking of a “false dawn” for oil prices, in March this had changed to “light at the end of the tunnel.”

By this month it was predicting oil markets would come “close to balance” in the second half of this year, with supply exceeding demand by just 200,000 b/d in the third and fourth quarters.

Oil demand in China, India and Russia has been robust, the IEA added. Why then sweat to get a deal in Doha?

The question was pertinent for OPEC’s core Arab state members and above all Saudi Arabia, which had given mixed signals about the proposed freeze.

Saudi Arabia has cast doubt on the desirability of oil prices rising much further, sometimes framing the issue in terms of diversifying its economy.

In terms of oil markets, one question is how far prices can rise without causing a rebound in US shale oil production. The answer, with hundreds of US shale wells drilled but sitting idle – uncompleted and waiting for prices to rise – may be not much.

“As things get back into the $40-45 range then we would start completing the drilled but uncompleted wells,” James Volker, chief executive of Whiting Petroleum, which has around 150 such wells in the Bakken and Niobrara shale, said in February.

But the April 17 meeting in Qatar was about more than prices. For some participants the idea of sealing a major pact on supply management outside of normal OPEC boundaries – brokered by Russia, with help from rising regional power Qatar – may not have been attractive.

Granted, the collapse of talks was a blow to participants’ prestige, but what might have been worse for some would have been a deal that effectively replaced OPEC and its six-monthly meetings in Vienna, and put Russia in the driving seat of a larger, more nebulous group, with the Gulf Arab states’ control diluted.

Qatar’s rise as a diplomatic force, financed by the latest big thing in energy markets, liquefied natural gas (LNG), has raised hackles among some Gulf states.

Probably more significantly, Russia’s flexing of its muscles in the Middle East has not made for comfortable viewing for a Saudi regime that has made clear where its international focus lies. That is not Russia. Saudi Arabia’s Deputy Crown Prince Mohammed bin Salman made this evident in an interview with Bloomberg ahead of the April 17 talks, saying: “America is the policeman of the world, not just the Middle East. It is the number one country in the world and we consider ourselves to be the main ally for the US in the Middle East.”

Tellingly for those heading to Qatar, he added: “I don’t believe that the decline in oil prices poses a threat to us.”

Source: http://blogs.platts.com/

Electric vehicles: The impact on oil and electricity

The number of electric vehicles (EVs) on the world’s roads hit the one million mark in third-quarter 2015 and sales are growing fast. If, and it is still a big if, EVs demonstrate an exponential rate of deployment, similar to solar PV panels, it could have a profound impact on both oil and electricity demand, and by extension the very basis of world primary energy supply.

Recent forecasts have suggested that at a 30% annual growth rate in EV sales would result in as much as 2 million b/d of oil demand being displaced by 2028, while at the same time adding 2,700 TWh to electricity demand globally by 2040.

An EV, which means plug-in hybrid vehicles (PHEVs) and battery-only vehicles (BEVS), uses 0.3 kWh of electricity per mile. So the total electricity demand in a year equals the number of EVs times the number of miles travelled annually times 0.3.

The amount of oil demand displaced in barrels/day equals the number of EVs times the number of miles travelled in a year divided by the average miles per gallon of internal combustion engines (ICE) divided by 365, divided by 42, the number of gallons in a barrel.

As such, the critical variables are the growth in the number of EVs on the road, the evolution of mpg and the number of miles each EV is assumed to travel.

Fuel efficiency is expected to rise in both high and low EV penetration scenarios driven by regulation, from somewhere around 17-24 mpg in 2015 to 45 mpg in 2040. So, although a major variable, there appears to be a rough consensus about its evolution.

The number of miles travelled is more contentious and has a huge impact on the expected outcome. In a recent report by Bloomberg New Energy Finance, the miles travelled per EV is assumed to rise on average from 8,700 a year in 2015 to 22,420 in 2040. BNEF sees all ICE Light Duty Vehicles travelling 23,500 miles a year in 2040.

This huge increase in miles travelled comes about as a result of autonomous driving, ride sharing services and other new mobility business models, according to BNEF. However, it is a big assumption; the trend is in fact down not up. The number of miles driven per car per year in the UK, for example, fell from 9,200 miles in 2002 to 7,900 in 2014, according to the RAC Foundation.

The number of EVs on the road is also open to question. Oil major ExxonMobil – a conservative counterpoint to BNEF’s enthusiasm for all things renewable – sees 50 million EVs on the road by 2040, compared with BNEF’s 400 million. Exxon’s assumption still represents growth in the number of EVs of about 14% a year on average out to 2040. The oil company assumes widespread adoption of conventional hybrids as the most economic option for consumers.

As a result, the range of possible outcomes is huge. If mileage is assumed to be flat then under Exxon’s scenario, oil displaced by EVs in 2040 amounts to a meagre 0.83 million b/d. At the other extreme, if BNEF’s high growth rates/high mileage assumptions are adopted then the figure comes out at a headline grabbing 13 million b/d.

The impact on global electricity demand would be again be minor in Exxon’s scenario, and much larger in BNEF’s at 2,700 TWh in 2040, equivalent to 11.4% of global electricity generation in 2014.

If a compromise is reached – say flat mileage of 11,500 in line with current LDV usage in the US, and BNEF’s high growth rate is adopted – the impact is 6.7 million b/d of oil displaced in 2040 and an additional 1,385 TWh of electricity consumed.

However, even this does not provide the whole picture. BNEF considers only LDVs, but there is a lot more to transport than that – heavy-duty vehicles , trains, planes and ships. Moreover, Exxon says this is where the growth in energy demand for transportation will come from, not from the LDV sector.

Global GDP will double by 2040 based on fairly conservative economic assumptions, so there will be a huge expansion in commercial transport. Exxon does sees electricity and natural gas making inroads, but not sufficiently so to overcome the increase in demand for oil from the growth in commercial transport.

If this part of the forecast proves correct, then the impact on oil demand of higher EV sales, even combined with higher mileage assumptions, could be swallowed up by the overall expansion in transport so that oil use continues to grow. EV growth and fuel efficiency will both retard oil demand, but they do not necessarily mean that oil demand will contract.

EV sales and driving patterns are clearly key variables to watch. As the cost of lithium-ion batteries falls, regulatory support grows and consumer sentiment shifts, they could produce the kind of exponential growth curve that other disruptive clean technologies have shown.

This would provide a new area of electricity demand growth for an industry sorely in need of one, at least in the OECD. It would create a massive amount of storage capacity. And it would put a significant break on oil demand growth. But as to the overall impact, it is better not to leap to conclusions just yet.

A fuller analysis of both the ExxonMobil and BNEF scenarios for the transportation sector is available in the April 1 edition of Energy Economist.

Source: http://blogs.platts.com/

OPEC’s grip might loosen, but it still has pull: Fuel for Thought

OPEC counts 13 countries among its membership, but one of them has long reigned as a first among equals.

Saudi Arabia, with its production of around 10.2 million b/d representing about a third of the group’s output — and about 11% of world supply — has served as OPEC’s de facto leader, its swing capacity traditionally leading the organization’s efforts to manage the market.

But last week’s failed talks in Doha to enact a production freeze saw a potential new oil producer group emerge with another player in the room that could have changed the dynamics of the market and challenged Saudi political eminence in world oil affairs.

The Doha summit of 18 nations included 11 OPEC members and several major non-OPEC producers, most notably Russia, whose output surpasses Saudi Arabia’s at close to 11 million b/d, according to its energy ministry.

Russia has geopolitical ambitions of its own that in many cases do not align with Saudi Arabia’s, particularly in the Middle East, where the two have clashed over the civil wars in Yemen and Syria.

But Russia and Saudi Arabia were among the leading architects of the freeze proposal, before Saudi Arabia reversed course as the Doha talks took place.

Had the talks been successful and a production freeze implemented, would Russia have found itself with an influential international perch in a new oil producer group that supplants OPEC’s role in overseeing the market?

The question is moot for now, as it was Saudi Arabia flexing its political muscle at the meeting, scuttling negotiations over its insistence that Iran be a party to any production freeze agreement and demonstrating that the market still is beholden to Saudi wishes.

But the failure of the talks, coming on the back of a fractious OPEC meeting in December, when the group scrapped its production ceiling altogether in a disagreement over output policy, has brought into sharp question the future of OPEC, which holds its next regular meeting June 2 in Vienna.

OPEC is dead, many commentators have written, as divergent interests have cracked the group and made any consensus on how to manage the market as unlikely as a blizzard in Doha.

“We’ve killed OPEC,” Texas Congressman Joe Barton said in a February interview with CNN, saying the December lifting of the US’ decades-old restrictions on crude exports will put a further squeeze on the producer group.

The Republican is not entirely wrong on premise, though his OPEC death declaration is a bit overwrought. After all, OPEC has ridden through price crashes and fractious relationships before.

OPEC still attracting new members

“OPEC is a bureaucratic organization; it is unlikely to go away anytime soon even if it never made another production decision,” said Jamie Webster, a Washington-based independent analyst. “It may be ineffective on the big decisions, but it is arguably still relevant in some form.”

Dysfunction and recent Doha embarrassment aside, OPEC membership still maintains sufficient cachet that Indonesia reactivated its suspended membership last year, while Gabon is also seeking to rejoin the group, he noted.

Even Washington-based consultant Bob McNally, who characterizes the current market as having entered a “post-OPEC” era, due to OPEC’s unwillingness to serve as swing producer, said the organization will remain as a conduit for its members to discuss market strategy.

“OPEC members are used to operating amidst high tensions among members,” said Bob McNally, a former energy adviser to US President George W. Bush. “They will exchange competing views in the meeting and to the press afterward, but this is par for the course.”

Beyond hosting the twice-annual meetings of its member oil ministers in Vienna, where it declares its output policies, OPEC also provides research on the market and issues regular reports to the public, and its secretary general, Abdalla el-Badri, speaks frequently at forums to represent producer views.

OPEC’s Vienna secretariat hosts a workforce of about 150, including researchers, statisticians, administrative staff and public relations personnel.

Amrita Sen, the London-based chief oil analyst with Energy Aspects, said to look for signs of obvious discord when judging OPEC’s ability to implement policy.

Russia may still have a role to play, as it appears it could be invited to consultations surrounding the June 2 meeting, though the impetus for now is on OPEC to find a détente among its own sparring factions.

Source: http://blogs.platts.com/

Brexit: What could it mean for the North Sea’s oil? — Fuel for Thought

In less than two months UK citizens will make one of their biggest political decisions in more than 40 years: whether to remain or leave the EU trading bloc they have been part of since 1973.

While an exit from the EU could mark a major milestone for the UK economy — the government fears GDP could suffer by over 6% after 15 years — a leave vote is seen having a limited impact on the UK upstream sector. For a start, North Sea oil has been regulated by London since before the UK joined the EU. Offshore safety laws were tweaked by Brussels in the wake of the 2010 US Gulf of Mexico spill, but their scope is limited.

In the short term at least, it is seen as unlikely that there would be any back-peddling on EU legislation which has already been implemented into domestic law. Existing rules, whether originating in Brussels or not, would not fall away on Brexit (British exit from the EU) and it is unlikely that they would simply be repealed.

Further down the road the UK would be free set its own offshore rules, which could diverge with EU legislation. In upstream oil and gas, Brexit would not change the key fiscal regime for the North Sea. London already has sovereignty over corporation tax, licensing and other regulations would not be affected in the short term.

There is also little sense of urgency over an exit vote in the industry. Any changes to the operating environment would be years down the line. Some predict it would take a decade or more for the UK to fully disengage from the EU.

“Is Brexit at the forefront of people’s minds right now as they are doing (North Sea related) deals? No is the answer,” said Julian Nichol, a lawyer at Bracewell which advises energy companies on legal issues. “From a legal perceptive, there is going to be a minimum impact on existing contracts. Brexit per se is not likely to trigger defaults.”

Most multi-national firms support the UK remaining in the EU and Big Oil is also in favor of the status quo. BP’s boss Bob Dudley has said Britain’s role would be “much diminished” if it exits while Shell’s CEO has signed a pro-EU letter saying leaving “would deter investment and threaten jobs.”

Some have suggested that a UK decision to leave could trigger a new vote for Scottish independence, with Scots likely plump for alliance to Brussels rather than London. If Scotland decides to break ties with the UK to keep access to EU markets, uncertainties may resurface over the progress of reforms needed streamline offshore rules.

Labor mobility concerns

Operators could also be forced to comply with two sets of regulations, some suggest.

Ahead of the Scotland’s vote to remain part of the UK in late 2014, industry group Oil & Gas UK flagged implications for the North Sea industry on costs and red tape should London and Edinburgh part ways. North Sea producers, it said, were also vexed over attracting skilled workers to the UK’s highly mobile offshore workforce should Scotland leave. Those same concerns are likely to hold sway for producers in the UK’s current choice over Europe.

The UK would be quick to sidestep any labor supply hiccups, many believe, forging labor migration deals with EU members to replace the bloc’s core free movement of workers principle. One risk of a UK exit is currency depreciation.

The pound could plummet in value, the theory goes, dragged down by uncertainties over the fate of the British economy.

“If that were to happen, upstream operators may benefit from a lower cost base relative to the dollar denominated oil and gas prices,” energy research group Wood Mackenzie said.

On the flip side, companies with US dollar debt will see their repayments rise if their revenue is in sterling and some will need to hedge against this effect, according to Bracewell.

The answers to many of the questions over a Brexit depend on the nature of the UK’s post-EU relationship with Brussels and the level of participation in the EU’s single market.

A withdrawal deal must be negotiated with the EU after two years or when such an agreement would come into force—which could take much longer. Non-EU members Norway and Switzerland both hold trade agreements with the EU. The Norwegian model would guarantee UK access to the single market, including free movement of workers. It would also mean the UK is bound by most EU legislation.

Source: http://blogs.platts.com/

Closed loop: The disruption of electricity and fuel distribution

The new range of electric cars are priced in the $35,000-$40,000 bracket. Solar PV and home energy storage costs are falling fast. A green, closed loop of self-generation and consumption is on offer that could meet not just an individual’s electricity needs, but their transport requirements as well. These early adopters can opt out of the megalithic supply and distribution chains of the oil and electric industries. It may not quite add up yet, but for many, the difference is so small it doesn’t matter.

Transportation and electricity provision are two fairly distinct markets, each with their own supply chains and market structures. Liquid fuels are distributed by ships, pipes, trains and trucks, electricity by wires. Both operate on a massive scale.

Renewables have disrupted these megalithic industries. They have done so in many ways, but there are three that are particularly important: the reversal of the trend towards scale, the move behind the meter to allow self-generation, and the simplification of technology.

This is a powerful combination because it makes electricity generation accessible to the consumer. But it also means that if electricity becomes a means of transport then it puts transport fuel behind the meter (or pump) as well.

Solar panels are the perfect embodiment of this: they are small, safe, modular and require no operation and maintenance. They cut through the barriers to market entry of cost and expertise that formerly dominated the electricity industry, representing both a huge addition of capacity and a mobilization of capital which is not controlled by the electricity industries’ traditional incumbents.

This has given rise to the much-documented ‘utility death spiral.’ This is the idea that as consumers source less electricity from the grid, the unit cost of maintaining the grid for its remaining users increases, creating an unsustainable spiral of rising costs. These are passed from the grid operator to generators and consumers, increasing the incentive to disengage. It is a vicious circle in which small-scale generation becomes increasingly viable as it escapes the common costs of distribution.

However, the potential for change goes even further. Power is about to be transferred in part to the end user not just for electricity generation but for transportation. And it will rejuvenate or create a different set of major industrials — the original equipment manufacturer.

The PV panel, battery and EV combination implies a revolutionary reformulation of both the transport and electricity generation supply chains. The idea is that the homeowner, using solar PV panels, generates electricity to supply both home and car.

The storage capacity of this new economic unit would be that of the car battery and the home battery combined. The home owner, in theory at least, would have no need of an electric or gas utility, or grid, except as back-up, and no need of a gasoline station and the lengthy supply chains that fill it.

They would have moved from a continual supply and small-scale expenditure model to lump sum investment in major pieces of equipment that require little servicing, a fundamental change in the relationship between energy supplier, whether electricity or liquid fuel, and the end-user. Energy would no longer be about supply and distribution, but equipment provision: solar panels, inverters, batteries and car bodies.

Does it pay?

According to US Federal Highway Administration data, the average American drives 13,476 miles a year, which, with a 24 miles per gallon vehicle, means consumption of 561.5 gallons of gasoline. The average retail price of gasoline of all grades in the US in early April was put by the US Energy Information Administration at $2.185/gal, which means the average US driver will spend $1,227 on fuel a year.

The average price of residential electricity in the US as of January was 12.01 cts/kWh. And 0.3 kWh will drive an EV one mile. So the equivalent fuel cost for an EV for the average US driver would be $485.54, giving an annual saving of $741.46. As there are fewer mechanical components in an EV, servicing costs are also expected to prove lower than a typical gasoline engine.

With EVs sub-$40,000, the typical US driver could buy an EV — and the solar panels and home energy storage system to power it — for somewhere in the region of $75,000 and have fuel and electricity for 20 years.

The key trends are that the price of lithium-ion batteries are very close to the point where EVs are genuinely competitive vis-à-vis a conventional car, and solar PV generation is close to competitive vis-a-vis retail electricity prices. But perhaps the really important point is that electricity (even solar-generated electricity) is cheaper as a transport fuel than oil, even when the latter is down in the dumps at $40/barrel.

Source: http://blogs.platts.com/

The multifaceted metamorphosis ahead for Mexico’s energy markets

The Mexico energy market has been a hot topic ever since late 2013 when the government decided to liberalize the energy sector, opening it up to foreign investment.

The reform provides an unprecedented opportunity for international companies to participate in development of the nation’s vast oil resources as PEMEX unwinds its current monopoly. Multiple other opportunities exist in the power sector, in renewables development and in the natural gas pipeline sector.

The energy reforms were largely a result of the steep decline of the country’s oil production, inadequate financial resources to turn production around and an inability of PEMEX to keep pace with the technological change taking place in the industry.

Mexico ranks sixth in the world for non-conventional oil and gas resources, right behind Canada and Algeria, but lacks the financial resources to develop its reserves. It would take US$20 billion to extract the country’s reserves over a 210-year period and $87 billion to do it in 50 years. It also would not be possible to do this with one state-owned exploration and production monopoly — this is why the reforms were necessary.

However, private investment cannot come quickly enough. Active drilling rigs in Mexico fell to 43 in February, down 43% from a year prior. Developmental rigs fell to 35 in February, down 44% from February 2015. The biggest year-on-year declines came from the Southern Region (down 15.7 rigs; 52%) and the Southwestern Marine Region (down 12.4 rigs; 56%).

In March, Pemex’s announced a $5.5 billion budget cut, and active rigs plummeted another 43%, while developmental rigs dropped to only 21. The Southern region again was hit hardest, with developmental rigs falling to seven during the month, down 55% from January.

Petroleum production is a major concern for the country, but renewables also are an important focus of the reforms. On top of having significantly large oil and gas resources, Mexico also has significant resources for renewable energy such as geothermal, wind and solar. It is estimated that current renewables generation, plus proven additional renewable resources in the country, could boost generation from renewables from 3.9% of the country’s total power generation to 9.89%.

Adding possible renewable resources to the mix could satisfy the country’s total generation needs, according to Mario Gabriel Budebo, director general of the EXI Fund: Energy and Infrastructure and former independent director of gas and basic petrochemicals at PEMEX. Budebo, who was the keynote speaker at the Platts Global Power Conference in Las Vegas in early April, also noted that significant infrastructure would need to be built to support such a major turn to renewables, highlighting the significant need for private investment to support the renewables efforts. He also gave a firsthand account of the Mexican energy landscape and the other investment opportunities the reform provides for international companies.

Investment in pipeline infrastructure also is a major need throughout the country. Just a few years ago, only 10 states had natural gas pipelines, but today 22 states have them. The Ministry of Energy estimates US$10.1 billion needs to be invested in pipeline infrastructure between 2015 and 2019 to build 3,205 miles of new pipeline, which would increase the total pipeline network to 11,081 miles.

While the country waits for the benefits of private investment in exploration and production, most of its natural gas supply to feed all the new gas pipeline and power generation infrastructure will originate in the United States. In its new Mexico Energy Monthly report, Platts Analytics said US natural gas exports to Mexico rose to more than 3.5 Bcf/d in April, prompted by a near 0.7 Bcf/d year-on-year increase in gas demand from the Mexican power sector. Greater reliance on US gas supply has reduced the need for more expensive imported liquefied natural gas. LNG imports by Mexico, despite rising to about 0.6 Bcf/d in April, were down 0.2 Bcf/d from April 2015 levels. Total non-US gas supply in Mexico was down 0.3 Bcf/d in April compared to April 2015.

Platts Analytics expects that US natural gas exports to Mexico could break above 4 Bcf/d by early summer as demand picks up and domestic supply continues to decline due to a lack of drilling activity.

Power demand is expected to increase as the country transitions to greater reliance on gas-fired generation and retires as much as 2.1 GW of fuel oil-generation plants over the next year.

However, lingering gas pipeline transportation constraints on both the north-to-south corridors (Los Ramones Phase II South) and the east-to-west corridors (El Enino – Topolobampo), may hinder exports this summer if planned pipeline expansions miss their expected in-service dates, in which case Mexico would likely increase reliance on LNG imports.

Mexico’s energy infrastructure development is behind other emerging economies, creating significant investment opportunities for both domestic and foreign companies.

Source: http://blogs.platts.com/