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Domestic Heating Oil Prices at an 8 Year Low – But Why?

In case you haven’t noticed Heating Oil prices have been falling dramatically. The UK average for home heating oil was 48.56 pence per litre (inc VAT) this time last year, it’s now at a staggering 8 year low of 31.92 pence per litre today. So why is this happening? How long will it last?

Factors that Influence Heating Oil Prices

There’s always a number of factors effecting the price of oil in the UK; VAT rates, weather conditions, demand, distribution costs, refining costs, currency exchange rates, and even conflicts in oil-producing countries all need to be taken into account.

This time though, the main factor contributing to this drop seems to be the price of crude oil.

Crude Oil is Cheap!

If you read the business section of your favourite paper you’ll already be well aware, but Crude Oil is cheap at the moment, and this can’t be overstated, with the price per barrel falling from above $100 a barrel in 2014 to $40 a barrel in 2015. To put this into perspective the price hasn’t dropped lower than $70 per barrel since 2010.

With the US production of oil it’s highest in almost 30 years, and Opec refusing to cut production, the market is flooded, bringing crude oil prices down, and allowing domestic oil users to benefit.

Source: International Energy Agency

Should I Stock Up Now?

So how long will this last? Will they drop even further?

Well the answers would be we don’t know, and maybe.

Not very helpful we agree, but at the moment we’re not sure anybody knows. All countries are starting to feel the pinch though; this means production could slow down and prices could rise at any moment – so now may be the perfect moment to take advantage…

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

How to Save Energy (& Money!) this Winter

You could save money by following out easy energy saving tips

Saving energy saves you money; but there are so many tips, tricks, and tall tales online these days that it’s hard to know what really works. So here’s our quick guide to things you can easily do to save money on your energy bills this winter.

The Nest is one of the leading smart thermostats on the market currently.

Only put the heating on when it’s required, not all day

Why let your house get cold just to have to use up energy heating it up again right? Well, wrong. Unless your house is incredibly well insulated you’re going to be using a lot of energy maintaining your home’s temperature. Heat will be constantly escaping, so heating it up only at certain times of the day when you need it is the cost effective route. Buying a smart thermostat may be an expensive initial outlay, but over a year you’ll often save money as they automatically adjust your heating schedule to match your lifestyle.

Set the timer on your hot water boiler

Heating your water 1-2 hours a day is a great way of saving money. Most water tanks have great insulation ensuring the water inside stays hot throughout the day. So setting a timer so that your immersion heater or boiler switches on for a couple of hours should be sufficient. Depending on your timer, you can always set it to switch on again a second time every day if you’re worried you’ll run out of hot water.

Setting a timer on your water boiler means you won't be heating water you don't use

Switching off unused electrics in your home can save you up to 17% on your energy bill

Unplug chargers when not in use, and don’t leave electrics on standby

According to the Energy Saving Trust UKhouseholds spend roughly £30 a year powering appliances left in standby mode, and/or not turned off at the plug. It may not seem a lot but every little helps, and it’s a free and easy way to save money every year. If you see the red light your device is still using energy.

Install thermostatic radiator valves

Thermostatic radiator valves, or ‘TRVs’, are a great way of controlling your heating in individual rooms rather than always heating the whole house. The valves, connected directly to your radiator, work by sensing the temperature of the air around it. As the room temperature rises, the valve gradually closes, limiting the amount of hot water entering the radiator. TRVs can reduce heating bills by up to 17% a year!

Installing TRVs helps you control temperatures in individual rooms.

Make sure you close your doors to trap heat

Keep your doors closed

Don’t undo all your hard work. Whilst you’re heating unused rooms less with your TRVs, you want to make sure that the cold air from those rooms isn’t mixing with the rest of the house. This may seem like an obvious one, but you’d be amazed how many households don’t do this. Oh, and whilst you’re at it shut your curtains too, and keep the cold air outside.

Household Bills Survey Results Revealed

Household bills equate to some of our most expensive outgoings each month, but across Great Britain, are we doing enough to save money?

A recent survey by NatWest revealed that across England, Scotland and Wales, consumers are missing out on opportunities to save, with almost a third admitting to not comparing prices to find a better deal on any of their household bills.

Across all monthly bills, council tax was seen to offer the worst value for money, with just 15% of respondents believing that it offers ‘very good’ or ‘good’ value for money, whilst on-demand video services were seen to offer the best value.

When it comes to energy efficiency, the majority of consumers across Great Britain believe themselves to be energy efficient to some extent; however, nearly half of consumers believe that they could be doing more.

UK Households – How They Save

Looking at the existing uptake of energy-saving measures in households across Great Britain, double glazing (79%), energy-saving lightbulbs (78%) and loft/wall insulation (66%), had the highest uptake. Consumers living in Wales had the largest uptake of energy-saving measures, whilst those in London, perhaps due to its large proportion of renters, had the lowest.

Household uptake in eco-shower heads (13%), energy-saving plugs (10%) and radiator boosters (4%) could add further cost savings to consumers.

Savings to be had by Comparing Heating Oil Suppliers

BoilerJuice in 2004 by a group of friends who wanted to make ordering heating oil easier, cheaper and more convenient.

Today we are the UK’s Number 1 Heating Oil website and compare prices from over 100 trusted suppliers to find you our best price for your heating oil, every time you order.

You can get a quote 24/7, 365 days a year on http://www.boilerjuice.com or by calling us on 0800 151 3135 (Monday – Friday 8am to 8pm / Weekends 9am to 5:30pm).

BoilerJuice Launch £25 Voucher Giveaway

BoilerJuice are delighted to announce the launch of a new daily £25 voucher prize giveaway.

We’re always looking to give something back to our customers, whether it’s group savings cash-back or regular “win 500 litres of heating oil” competitions.

But we wanted to give more.

Following on from the success of our ‘January Madness’ and ‘March Mayhem’ competitions; we’ve decided to give away a voucher not just every week, but every day!

On top of this we’re opening up this latest competition to include anyone who orders anything from BoilerJuice, not just heating oil. That means even if you order Red Diesel, a bottle of BoilerMax additives, or even an oil tank lock – you still have a chance to win a £25 BoilerJuice voucher.

We’ve already given away vouchers to 15 winners for every day so far this month, and the plan is to give away at least 16 more. The total value of vouchers given away is already £375 – and by the end of the month? – we’ll have given away £775 worth of BoilerJuice vouchers.

It’s so easy to enter! Just order something from BoilerJuice today and be in with a chance.

In Canada, a battle brews over pipelines, power lines: Fuel for Thought

With the current assumption that a crude export pipeline from Alberta to the US Gulf Coast is unlikely to ever be built, never has there been a better opportunity for Canada’s provinces to join hands and hasten efforts to open up oil export outlets along the country’s Pacific and Atlantic coasts.

Be it the recent rejection by the US government of the Keystone XL Pipeline — described by Alberta Premier Rachel Notley as a “kick in the teeth” — or the low-level east-west rivalry between the provinces to get a trans-Canadian oil export pipeline built, consensus building and not antagonism is a discerning aspect of the confederation.

A new issue is, however, brewing between Alberta and British Columbia that, instead of pulling the provinces together to optimize the value of the nation’s crude oil resources, is putting them at loggerheads.

In early March, Alberta’s energy minister Margaret McCuaig-Boyd said that the province would not buy additional electricity from neighbor British Columbia unless the latter lends its support for an oil export pipeline through that province.

The next day Notley said: “We’ve just got to get our product to other markets. We’re not necessarily going to have that much demand for electricity if we can’t find someone to sell our products to.”

Neighbors wanting to talk about new power lines crossing provincial borders need to understand that the issue is tied to inter-jurisdictional product distribution infrastructure, like pipelines to carry bitumen to tidewater.

These were not separate issues, Notley said.

British Columbia has opposed Enbridge’s 525,000 b/d Northern Gateway and the Kinder Morgan-backed 890,000 b/d Trans Mountain pipeline expansions, primarily for environmental reasons.

Now British Columbia has a project at risk: the fate of its recent final investment decision to build the 1,100 MW Site-C hydroelectric power project near Fort St John on the Peace River at a whopping cost of C$8.8 billion ($6.7 billion) and the laying of a new transmission line to supply power to northeast Alberta, which is home to oil sands producers.

HITTING WHERE IT HURTS MOST

For British Columbia, the signing of power purchase agreements with its neighbor is just as significant, as is Alberta’s efforts to receive higher royalties from its oil sands producers by opening up an export outlet and substantially wiping off the province’s ballooning budget deficit of over C$10 billion.

Right now Alberta’s crude is heavily discounted as it has few outlets and must go through the US in order to be exported overseas. With low-cost pipeline space limited, Canadian crude also needs use higher priced rail lines to get to the market, which requires oil prices to be lower.

The genesis of Alberta’s opposition to building the power project planned by BC Hydro goes back to the 1980s. This was when the then premier Peter Lougheed expressed concerns that building a dam in the Peace River valley would inundate about 5,500 hectares of land in the Western Canadian Sedimentary Basin and impinge on the constitutional rights of the Treaty 8 and West Moberly First Nations bands to their lands.

Four decades later, the slowdown of oil sands activity in Alberta, particularly Shell’s decision to cancel its 80,000 b/d Carmon Creek project in Peace River, will result in less power demand and come in the way of BC Hydro’s PPAs.

The British Columbia government is willing to work through Alberta’s demand and find a way to work together, said its energy minister Bill Bennett. But if recent statements by the federal natural resources minister James Carr are any indication, getting oil pipelines built in Canada will not get any easier.

“Of course, the process [of building pipelines] is a political one,” Carr said at an industry event in Calgary last month. “Some people have a cynical interpretation of political in the context of pipeline. But I see political as a word that is at the very heart of our democracy. We’re elected on a platform and are held accountable for achieving those goals.”

Governments are elected to make tough choices and that could likely create a greater consensus and reduce the hurdles in building pipelines, Carr said.

The federal government is expected to play an intermediary role between Alberta and British Columbia, with Prime Minister Justin Trudeau stating unequivocally that his main responsibility is to get a pipeline built. If Canada sticks to its policy of getting a consensus when making decisions, it will be a win-win situation in the end for both provinces.

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

Fuss over “missing” 800,000 oil barrels: ‘Get over it,’ says IEA official

Has the hoo-ha over the 800,000 “missing barrels”, the difference between average daily global oil production and consumption flagged by the International Energy Agency in its March report gone a bit too far?

And did you fall for the argument that these barrels may not even exist, which in theory halves the presumed oversupply in the global oil market and gives us reason to be more bullish on oil prices, which had teetered near 13-year lows just two months ago?

In yet another testament to how clueless and sentiment-driven the oil markets have become, the case of the missing barrels was actually proffered by some as one of the reasons behind Brent clambering to over $41 this month, from levels near $30 in February and a $27 nadir in January.

Google “missing barrels” and you can catch all the excitement in case you missed it. The latest one is actually a sobering report that has Morgan Stanley analysts dismissing it as an old “market myth” and a “poor explanation” for crude’s rise in recent weeks.

In its monthly oil market report issued March 11, the IEA said it had actually been able to reduce the uncertainty in the supply/demand balance, described as “missing barrels,” to 800,000 b/d, after re-analyzing its data for floating storage and oil in transit. The figure, it said, was “well within the normal range considering the vagaries of data.”

The implied surplus of supply over demand remains a high 1.9 million b/d for Q1 and 1.5 million b/d for Q2 this year, the agency maintained.

We know nervous markets don’t have time to pause and reflect.

But the IEA, it seems, had not gambled upon the play its “missing barrels” was to receive. The Wall Street Journal ran a report a few days later, citing some analysts suggesting that if the 800,000 b/d doesn’t exist, the oversupply that has pressured oil prices may not be as big as estimated.

The tally of unaccounted-for oil — which comes from the difference between the 1.9 million b/d presumed surplus and the roughly 1.1 million b/d of oil calculated by the IEA as being in transit and moved into onland storage — rose to its highest level in 17 years last year, and this was an important factor in an industry dominated by oversupply, the paper said.

Brent’s trek from $36 and change at the start of March to a year-to-date high of $41.79 on March 22 has left more than a few market watchers puzzled. The dollar’s weakness following the US Federal Reserve meeting March 16, a lingering 200,000 b/d production outage in Nigeria and a drop of about 120,000 b/d in pipeline crude supplies from Kurdistan got buttressed by the “missing barrels” argument in support of crude’s rebound. Otherwise, the few hundred thousand barrels in production outages should pale in comparison with the giant global surplus.

In an oil market of 96 million b/d, and entrenched imperfections in the gathering and reporting of oil production and consumption statistics, the discrepancy between the calculated surplus and the oil tallied as moving into storage is not something the IEA can do anything about, the agency’s head of oil industry and markets division Neil Atkinson stressed March 23.

Responding to a Platts question about his take on the buzz created by the IEA report’s “missing barrels” reference, Atkinson, who was in town to participate in the Singapore International Energy Week’s launch event, took issue with the perception that the IEA didn’t know where the “missing” oil was.

“A lot of it is in China [in the form of stockpiles], there’s some in India, some sitting in pipelines and some in ships,” he said. The IEA, an energy policy adviser to the OECD countries, does obtain data from non-OECD countries, contrary to some assertions, but it’s not perfect, the official stressed. “Get over it,” is how Atkinson summed up his view on the hullabaloo.

David Hewitt, Managing Director at Credit Suisse and fellow panelist at the SIEW event, agreed, saying that some traders seemed to have seized upon the “missing barrels” story in their hunt for reasons to be bullish about the market.

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

Vietnam’s oil tax rules run counter to self-reliance policy: Fuel for Thought

Ironic and unusual aptly describe the conundrum facing Vietnam’s sole 130,000 b/d state-owned refinery located in the central province of Quang Ngai.

The refinery has been struggling to sell its oil products since Vietnam’s free trade agreements with ASEAN and South Korea kicked in last year making it cheaper for local petroleum retailers to import oil products instead of buying from Dung Quat.

The reason behind this is a tariff imposed on Dung Quat’s products which are locally referred to as an “import tax”. This tax was originally intended to be at the same level as the tax imposed on imported oil products but as the FTAs kicked in, the tax structure started working against Dung Quat.

A lack of policy coordination has led to this unusual situation, according to an analyst at the Vietnam Petroleum Institute, the research arm of PetroVietnam.

“There are two separate teams in each relevant ministry—one is responsible for FTAs while the other is in charge of tax policies for Dung Quat. They did not cooperate well with each other,” the analyst said.

The results are intermittent tank tops at Dung Quat and strong growth in the country’s oil product imports, which is ironic given that the reason behind Dung Quat’s construction and planned construction of other refineries in the country is to lower reliance on product imports.

Vietnam’s oil product imports rose 19% year on year in 2015 to 10.06 million mt. Supplies from Singapore, Thailand and Malaysia saw a dramatic jump of 48.50%, 164% and 87.40% respectively, data from Vietnam’s customs showed.

In the first two months of 2016, imports have risen 12.3% year on year to 1.69 million mt, while South Korean supplies have seen a 57.60% year-on-year surge in the period.

After several pleas by Binh Son Refining and Petrochemical (BSR), the operator of the Dung Quat refinery, the government earlier this month agreed to implement a second round of cuts to the tax imposed on the refinery’s output. But barring jet fuel, for which Dung Quat enjoys a lower tax rate than imports from ASEAN, the tax rate on Dung Quat is generally still higher.

The table below highlights the tax rates imposed on different oil products produced by Dung Quat and those imported from ASEAN countries and South Korea:

	Dung Quat	ASEAN	South Korea
Diesel	7%	0	5%
Kerosene	7%	0	5%
Gasoline	20%	20%	10%
Fuel Oil	7%	0	0
Jet Fuel	7%	10%	5%

Notes: The import tax on gasoline imported from ASEAN countries is valid until 2018; import tax on diesel, kerosene, gasoline, and jet fuel imported from South Korea is valid until 2018.

The table illustrates how the tax structure makes importing gasoline from South Korea and importing gasoil from ASEAN countries the best option. Vietnam’s largest retailer Petrolimex expects to import a lot more gasoline from South Korea once some of its existing term contracts expire in the middle of 2016.

No plan to remove domestic tax

According to a local industry source, the Vietnamese government is unwilling to simply remove the tax on Dung Quat because in a low price environment it is keen to maximize its tax revenue. But this is coming at BSR’s cost and at the cost of potential new investment in Vietnam’s refining industry.

Due to the tax disparity, the price of imported South Korean gasoline in January was about $4.78/b lower than Dung Quat’s gasoline, which hit BSR’s sales.

Petrolimex has requested BSR to consider lowering the selling price of gasoline on both a spot and term basis for the second half 2016, so that the refiner’s prices would be equal to South Korea’s State-owned PetroVietnam recently said that if such high disparity in taxes continued for long, Dung Quat might be forced to suspend operations or lower run rates.

Domestic products still have some advantages to imports. For example, Petrolimex does not need to issue letters of credit to Dung Quat, the delivery times are shorter and the parcel sizes can be flexible so some retailers would still prefer to buy from the domestic refinery.

Petrolimex sources said that once the 200,000 b/d Nghi Son refinery comes onstream in late 2017, Vietnam would become fairly self-reliant on oil products but the FTAs would still provide ample incentive to import, which could lead to lower utilization rates at the local plants.

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

The long and short of ethane in the Northeast US

On March 9, the JS INEOS Intrepid departed Sunoco Logistics’ Marcus Hook terminal in Pennsylvania with the first waterborne ethane cargo. Arriving at the INEOS steam cracker in Rafnes, Norway, on March 23, the shipment is the culmination of four years of work to transport ethane internationally. However, uncertainty around the ethane market has grown as new projects for domestic and export use all come online simultaneous with declining production and low prices.

Platts Bentek details this uncertainty in a free Market Alert, No Longer Adrift: Navigating a Tighter Ethane Market. Ethane exports have been viewed as a major relief for gas producers in the Northeast, where limited infrastructure has forced producers to reject large volumes of ethane into the natural gas stream. Currently Platts Bentek’s Market Call: North American NGLs estimates 2016 Northeast ethane production at the wellhead at 311,000 b/d, with 125,000 b/d (nearly 40%) of that rejected. Ethane rejection was estimated at nearly 65% in 2015.

The volumes involved in ethane exports are comparatively small. Range Resources, the primary shipper in the contract with INEOS, has 20,000 b/d contracted on the Mariner East 1 pipeline to Marcus Hook. Approximately 50,000 b/d of ethane is contracted to flow on the Mariner West pipeline to cross the US/Canada border and serve southwestern Ontario’s petrochemical industry.

Enterprise Products Partners reports 110,000 b/d currently flowing on the ATEX pipeline from the Northeast to the Gulf Coast. Current capacity on ATEX is 125,000 b/d, and Enterprise has stated that an expansion up to 265,000 b/d would require 18-24 months’ work.

Looking forward, low commodity prices have reduced drilling activity and led to a less aggressive ethane production forecast, both nationally and in the region. In the 4Q 2014Market Call: North American NGLs, published in October 2014, Bentek expected ethane supply from gas plants to reach roughly 2.07 million b/d in 2018.

In the latest edition of Bentek’s Market Call: North American NGLs, published January 2016, ethane supply reaches only 1.86 million b/d in 2018, a 10% decline. In the Northeast, the new ethane projections indicate a smaller decline, of just 8% from 479,000 b/d to 443,000 b/d in 2018.

Projects that will increase ethane demand both domestically and for export continue to move forward, primarily in the US Gulf Coast. Eight ethane crackers are currently under construction on the Gulf Coast will come into service between 2017 and 2018.

Among the cracker projects announced for the Northeast, none are expected to come online by 2018. Export volumes are expected to ramp up as the other ethane export terminal, Enterprise’s Morgan’s Point terminal in Texas, comes online later this year.

With demand growth on the Gulf Coast, Northeast ethane remains stranded without greater pipeline access. ATEX is set to reach capacity in 2018, and Enterprise has made no announcement of expansion plans. The only alternative destinations for Northeast ethane in the near term are Mariner West to Canada or on Mariner East for waterborne export, both of which are already subscribed. Because ATEX is the only pipeline serving the Gulf Coast, it is the best candidate for expansion to meet new domestic petrochemical and export demand. Without that expansion and with current production forecasts, ethane rejection could exceed 175,000 b/d in the Northeast in 2018.

If capacity on ATEX remains restricted, Northeast producers will be disconnected from the domestic market. Lower regional ethane prices won’t matter because of the physical transport constraint. Thus, the ethane supply for new projects will need to be sourced from other regions, initially Texas and the Mid-Continent, and later the Rockies and Williston basin. Ethane prices will have to rise dramatically to overcome the costs to transport ethane to market, i.e. Mont Belvieu, Texas, and to fractionate ethane from other NGLs.

But even with ethane from the Rockies and Williston, without Northeast production, the US ethane market is short by just over 75,000 b/d by 2018. This ethane shortage would need to be made up through a combination of lower operating rates by existing petrochemical plants, delays for plants under construction, or reductions in export volumes. While this spring brought optimism for Northeast producers via a new market for their ethane, the lack of a domestic outlet looms on the not-so-distant horizon.

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

The US’ Jones Act gets a new fight and a new argument

A nearly century-old US shipping law that has broad, bipartisan support in Congress faces a new opposition effort aimed at lessening costs to East Coast refiners.

US Representative Mike Pompeo, a Kansas Republican, last week said that he has begun an effort to repeal certain elements of the law, known as the Jones Act.

“There are pieces of [the Jones Act] that are anachronistic,” Pompeo said at an event at the Hudson Institute in Washington. “We should certainly look at making sure that we reduce the friction associated with the transportation of energy commodities and, frankly, other commodities around the world.”

East Coast refiners have long complained that the Jones Act puts them at a competitive disadvantage to refiners in Canada and Europe and the American Fuel and Petrochemical Manufacturers, the industry’s chief lobbying group, has called reform of the Jones Act a key policy goal this year.

The effort to weaken the Jones Act is still in its nascent stages, but the American maritime industry, and its throng of supporters on Capitol Hill, have already begun to fight back.

The intense lobbying effort is nothing new for the Jones Act, which requires vessels transporting goods between US ports to be US-flagged, US-built and majority US-owned. But that effort, traditionally focused on the financial health of the domestic maritime industry, has been refocused, this time on national and homeland security.

“A repeal of the Jones Act would significantly undermine national security,” said Tom Allegretti, chairman of the American Maritime Partnership, in a statement to Platts. “Given the state of the world, particularly this week, it’s hard to imagine changing a law that plays a major role in border protection, homeland security and prevention of illegal immigration.”

Allegretti said the Jones Act has massive support from military leaders and the US Coast Guard due to its contribution to maintaining a US-flagged commercial fleet for military sealift, which he said would cost billions for the Department of Defense to replicate.

These points were echoed in recent statements from Representative Michael McCaul, a Texas Republican and chairman of the House Homeland Security Committee.

“The domestic maritime industry in Texas is important not just for the good jobs it provides and the critical role it plays in keeping our petrochemical industry functioning efficiently, but also because it is a critical link in our homeland and border security,” said McCaul. “Tens of thousands of security-screened American seafarers, who crew the hundreds of tugs, towboats, barges and offshore supply boats working all along the Texas coast, help keep terrorists away from our border and our critical petrochemical infrastructure.”

And in a recent editorial, Slade Gorton, a former Washington Republican senator and member of the 911 Commission, wrote that “the most vital benefit of the Jones Act is the law’s critical role in protecting America’s borders and homeland security.”

Pompeo declined to detail how he intended to change the Jones Act, either through legislation or other avenues, and would not identify any other House or Senate member he was working with on the effort. He said there was support within Congress to reform the law, but “not nearly enough” to get such a change passed.

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

US oil industry business models to change post-recovery: Fuel for Thought

Green shoots of optimism are poking through the parched ground of the oil patch lately as industry focuses on the aftermath of a downturn they hope has troughed. But the US E&P sector that emerges from the latest carnage will be different as business models will be forced to change.

With crude oil hanging just shy of $40/b, industry-watchers say capital is still available to survivors of the downturn that are in relatively good financial shape. But lending criteria will be stricter as more will be asked of borrowers and production hedges may be more prevalent, they say.

Nearly $39 billion of private equity funds were raised in 2015, and on top of that there was a “substantial” amount of dry powder remaining from funds raised in 2014, Doug Reynolds, managing director and head of US business for Scotiabank, said at the Hart Energy Capital Conference last week.

“The majority of US production is owned by companies that are financially strong and there is new equity [raised] that will make them more so,” Reynolds said.

US E&P companies have recapitalized to the tune of nearly $11 billion in equity so far this year, compared to $8.6 billion in Q1 2015, he and others noted.

While many oil companies will likely disappear, victims of liquidations and takeovers, “we think for the guys that make it through, it will be somewhat of a golden era for them,” Reynolds said.

But they will have to be fiscally lean and efficient. For one thing, lenders may be skeptical of companies whose acreage is not top-tier or industry-proven as they have seen many bankruptcies in the current downturn

A recent count by law firm Haynes and Boone put oil industry bankruptcies north of 50.

Focus to stay onshore for faster returns

During the downturn, oil companies produced from their best, highest-return wells. They have also concentrated on land plays since the returns are quicker, unlike offshore projects, which can take as long as 10 years to come onstream.

The shift to onshore production is expected to continue due to the lower costs and speedier returns available.

And while well costs have come down both onshore and offshore due to concessions from oilfield service companies, offshore wells have not experienced the astounding efficiency leaps that have been such a large part of the shale revolution onshore and allowed those operators to survive sub-$50/b oil.

Costly or lengthy projects in the US will be “challenged” going forward, Wil VanLoh, CEO of private equity firm Quantum Energy Partners, said at the Hart gathering.

The downturn will refocus public oil companies on making money more quickly rather than growing production and reserves. This will “materially” alter or even eliminate certain business models, such as long-cycle projects in deepwater and international arenas, or high-cost projects in the Gulf of Mexico, oil sands, upstream master limited partnerships and the bottom 50% of resource plays, VanLoh said.

Only the exceptional of these projects will be moved forward.

In addition, the private equity model of funding may be changed post-recovery, VanLoh said.

“The model where you lease land, drill a few wells and flip [the developed assets] to a public company is likely a thing of the past,” he said.

“Public companies have much less money to buy this stuff now, and they have a lot of acreage of their own,” he added. “PE-backed companies will have to more fully develop their assets, requiring more money and more time, so quick flips won’t be as prevalent.”

Going forward, debt capital will be harder to get and cost more, while acquisitions will require more equity and that should drive down the prices of assets.

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