Debt problems remain in oil & gas industry, cast a large shadow on its Malaysian peers, Alam Maritim

Some oil companies that piled on too much debt won’t make it in today’s world of $40-$50 oil.

THE near-demise of Singapore-listed oilfield services company Swiber Holdings Ltd has cast a large shadow on its Malaysian peers who are facing similar mounting debts, a lack of new tenders and a depleting cash pile.

With oil prices still in a bear market for the second year running, smaller offshore services firms may continue to underperform as high debt obligations will continue to eat up existing cash reserves, say analysts.

Swiber had initially filed for liquidation on July 29 but had subsequently sought judicial management in an attempt to restructure the company’s existing businesses. The firm, which has 51 vessels in its fleet, has a prominent presence in Southeast Asian waters in a variety of jobs.

The effects of the two-year slump in oil prices were clearly seen in Swiber. Its capitalisation had fallen by 90% from its 2013 peak prior to the stock’s suspension last week.

Over the same period, its cash pile has been depleted by a series of debt repayments, which is a recurring theme for companies in the industry that tend to be highly leveraged.

The company’s predicament has put the spotlight on its Malaysian peers. Alam Maritim Resources Bhd, which has two joint ventures with Swiber, will now have to proceed without its partner.

As the joint ventures are vital cash generators for Alam, it is unlikely that the firm will dissolve them following Swiber’s exit. But it is now faced with the choice of buying out Swiber’s stake or finding a new partner, said Maybank IB Research in a note.

“The two JVs, which comprise a pipelay barge and a ship operator, are doing fine. The ventures could generate a combined net profit of RM8-RM10mil, of which Alam’s share is RM4-5mil,” said the research house, which nonetheless remained bearish on Alam with a ‘sell’ call and a target price of just 11 sen.

At the moment, the need to preserve cash flow continuity is of utmost importance in order to service existing debts. According to AllianceDBS Research, domestic contract flow in the oil and gas industry hit its lowest point in nearly four years during the second half of this year (2Q16).

“With utilisation rates at and charter rates at multi-year lows, there are few immediate bullish catalysts in the industry at present. To give just one example, talks of the possible mergers or consolidation in the oil and gas industry have largely fizzled out as there is no extra cash to be spent.” explains one oil and gas sector analyst.

To illustrate the debt load situation, a check on Bloomberg data reveals at least seven companies listed on Bursa Malaysia whose net debts currently exceed their entire market capitalisations.

The companies include SapuraKencana Petroleum Bhd (SapKen), Bumi Armada Bhd, Wah Seong Corp Bhd, and Icon Offshore Bhd, among others.

Meanwhile, at least twelve oil and gas companies have net debt-to-earnings ratios of at least three times, which far exceeds the benchmark FBM KLCI’s ratio of 1.17 times currently.

This financial metric is typically used to measure a company’s ability to service existing debts relative to its earnings performance.

UMW Oil and Gas Corp and Barakah Offshore Petroleum Bhd are among the highest with ratios of 13.71 times and 12.52 times respectively, according to Bloomberg data.

While large cap companies such as SapKen has successfully refinanced a large part of their debt load, the oil and gas industry as a whole remains highly leveraged even now.

Some 20% of Bursa Malaysia listed corporates showed below average debt coverage levels while another 8% were aggressively leveraged, said RAM Ratings in a commentary on Aug 2.

Oil and gas companies are among those with weaker credit indicators and will be most vulnerable to economic stress, it added.

The current abundance of crude oil supply and inventory means that the occasional rallies in the market were short-lived this year.

After hitting a year-to-date high of US$52 per barrel in early June, Brent crude prices have declined by 15% in a month to US$44 on Aug 4.

Supply from the Organization of the Petroleum Exporting Countries (Opec) also rose to a record high of 33.41 million barrels per Aday (bps) in July, which could further dampen any upside potential in the commodity’s price, Reuters reported. – by Afiq Isa The Star/Asian News Network

Alam Maritim on Swiber impact


Azmi says contribution from JV with company not substantial

PETALING JAYA: Alam Maritim Resources Bhd will not feel the heat from financial troubles of its partner, the Singapore-listed Swiber Holdings Ltd.

In fact, Alam Maritim is considering taking over the stake of the troubled-oil and gas (O&G) firm in a project that the companies are working on.

“There is only one project directly contracted with Swiber which is almost fully-completed namely engineering, procurement, construction, installation, commissioning of SK316 development job worth US$76mil,” Alam Maritim group managing director and group chief executive officer Datuk Azmi Ahmad told StarBiz.

The SK316 project is the development of a huge gas field located offshore Sarawak.

The other option for Alam Maritim is to find a new partner to take over Swiber’s role.

He said Alam Maritim had two JV companies with Swiber,

The first is Alam Swiber Offshore (M) Sdn Bhd which is equally owned by Alam Maritim (M) Sdn Bhd and Swiber Offshore Construction.

The second is Alam Swiber DLB 1 (L) Inc, which is 51% owned by Alam Maritim (L) Inc and 49% by Swiber Engineering Ltd.

“The impact is minimal to us as the contribution from the Alam-Swiber JV is not substantial to the Alam Maritim group,” he said.

Swiber, the Singapore-based oilfield services firm was reported to be in talks with its creditors for a possible debt restructuring exercise.

The stock had slumped by nearly 90% since mid-2014, taking its market value to just S$50mil, while the company had flagged delays in orders, raising concerns and sparking demands for cash.

From just 10 vessels in 2006 when it was listed, Swiber had expanded to own and operate a fleet of 51 vessels with more than 2,700 employees across South-East Asia and other countries, according to its website.

Its shares surged after listing, pushing its valuation to S$1.5bil in late-2007, but the stock fell sharply in recent years.

Smaller firm Technics Oil & Gas Ltd was placed under judicial management this month, and analysts said other firms could face difficulties.

Energy and offshore marine companies in Singapore have bonds totalling nearly S$1.2bil due to mature over the next year-and-a-half, with S$615mil due over the next five months, according to IFR, a Thomson Reuters publication.

Alam Maritim, too is facing a challenging period.

On the O&G support services industry, Azmi said the impact of Brexit on the fragile global economy might slow down the recovery of the crude oil prices affecting overall demand and pushing out the rebalancing of the oil market.

“During this challenging period, we are aggressively and continuously embarking on various cost and asset optimisation initiatives to weather the storm,” he said.

Azmi added that Alam Maritim’s vessel utilisation rate was 56%.

“As at June, our order book stood at RM470mil, tender book at RM2.6bil,” he said.

Alam Maritim fell into the red with a net loss of RM19.2mil in the first quarter ended March 31 compared with a net profit of RM8.6mil a year ago.

Its revenue for the quarter shrank to RM48.6mil from RM73.7mil in the corresponding quarter last year.

According to Maybank Kim Eng, the low oil price has resulted in a swift response to cost reduction or renegotiating of contracts, cash conservation due to delayed projects and debts refinancing as well as strategic collaboration exercises.

“It also opened a window of opportunities to exploring mergers and acquisition options.

“About 69 North American exploration and production companies were declared bankrupt between January 2015 and April this year. “Uncertainties and differences in valuation expectations between buyers and sellers are the greatest hurdles. There is currently a buyer-seller mismatch in terms of expectations,” said Maybank Kim Eng in a June report on the sector.

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Petronas needs to tell more,Drilling for future opportunities

Petronas needs to tell more



More relevant info from the national oil company will help dispel suspicion.

THE question of whether the national oil corporation, Petronas, is giving away too much to local oil field services company in the exploitation of marginal oil and gas fields can only be answered if Petronas reveals much more than what it already has.

On our part, we can only raise some of the burning questions surrounding the emergence, for the first time, of other Malaysian companies besides Petronas, effectively as joint venture partners in the mining of oil and gas in the country.

The new arrangement that Petronas has come up with for marginal oil fields, those which have less than 30 million barrels of oil equivalent (BOE), is called a risk service contract or RSC against the previous production sharing contract (PSC).

First, the PSC. After Petronas was set up to own and manage all the country’s oil and gas resources on behalf of the Government in 1974, it negotiated with the oil majors who eventually became Petronas’ contractors under PSCs.

Under these, a certain proportion of oil produced was deducted as costs of exploration and exploitation once oil was found and the remainder was shared between Petronas and the oil majors on an agreed proportion depending on oil prices. That proportion is at least 80% in favour of Petronas, going up to 90% or higher as the oil price rose.

Conceptually, this is a scheme which is easy to understand and has since been emulated by countries around the world in their dealings with the oil companies. Basically, the oil companies do the exploration. If they hit oil, they get to recover their costs and the remainder of the oil is shared on an agreed proportion.

Petronas bears hardly any risk as the owner of the concession, basically merely sharing profits with someone who has the expertise and the capital to extract the oil.

It is different with the marginal oil fields. Here, no exploration is needed but oil majors are not interested in recovering this oil because it is not economical enough for them although there are specialised companies which engage in this activity. What is reasonably certain is there is oil. The question is how to extract it.

For reasons it has not fully explained, Petronas is now putting the emphasis on local operations instead of building upon its overseas operations which account for 45% of total revenue and some 37% of total production. Petronas does not say how much profit comes from overseas though.

As part of this new emphasis to concentrate on the domestic sector, it has embarked on a programme to develop marginal fields involving some 106 fields and 580 million BOEs. It has also stated its intention of getting foreign oil companies to partner with local oil field services companies to extract oil (and gas) from the marginal fields.

It says that this is to help develop local expertise so that they become sort of oil explorers and extractors in their own right and are able to compete in the international market place for contracts. Some 15 local companies are reported to be involved in oil field services currently.

However, it is difficult to see how any of the local companies will become internationally competitive even with this leg up. That they became successful in the first place as oil field service providers was because of Petronas’ insistence that the oil majors used local companies. Even if their services were more expensive, Petronas, as the owner of the concession eventually bore this cost.

However, extraction is a different business altogether and even if we call the relevant fields marginal ones, there is still a lot of money to be made and the amount increases as oil prices rise. There is a lot of expertise involved and those who extract marginal oil are not going to be sharing their expertise readily with local partners they are forced to take.

At 580 million BOE, and using an oil price of US$80 per barrel, the oil is worth nearly RM140bil! Thus, it is important to ensure that Petronas does not lose out in this and extracts the best deal for itself.

The method it is employing is the RSC but it does not give sufficient details about the RSC to independently determine whether it is a fair arrangement. It says that the model strikes a balance in “sharing of risks with fair returns” for development and production of discovered marginal fields.

It adds that it shares risks as the project owners while contractors receive a “reasonable return with limited upside” while it says key performance indicators or KPIs will be in place with incentives or penalties triggered depending on performance.

However, there is no disclosure of what is a reasonable rate of return for the project or the KPI, or the kind of risk that contractors undertake because they are paid a service fee. Can the contractors share in the upside with no evidence of downside sharing? How much of a free ride are our local oil service companies getting in such a deal?

Let’s look at the first such contract. Petronas has awarded this to Petrofac Energy Developments Sdn Bhd, Kencana Energy Sdn Bhd and Sapura Energy Ventures Sdn Bhd for the development and production of the Berantai field, offshore Peninsular Malaysia.

Under the terms of the contract Petrofac with a 50% equity interest will be the operator of the field. The two local partners, Kencana and Sapura, will own the remaining 50% interest on an equal basis.

“The RSC model strikes a balance in sharing of risks with fair returns for development and production of already discovered fields. In this arrangement, Petronas remains the project owner while contractors are the service provider. Upfront capital investment will be contributed by the contractors who will receive payment commencing from first production and throughout the duration of the contract,” Petronas said.

“The new arrangement facilitates direct participation of Malaysian companies in the country’s upstream oil and gas activities, in line with Petronas’ efforts to leverage on their existing capacity while fast-tracking their capability in development and production in a structured manner,” it added.

There was nothing more material than that from Petronas’ official statement.

In separate announcements, Sapura Crest and Kencana Petroleum, because they are listed companies, announced that the total development costs would be US$800mil which meant each of them had to raise US$200mil. That is a huge amount for these relatively small companies which are still among the larger oil players in the country.

While they are scrambling to raise the funds for this, it is by no means certain that they will acquire expertise in extracting oil from marginal fields as their partners will be committing commercial suicide if they just passed this knowledge on to them.

The question is, are Kencana and Sapura, and the others who follow them, merely equity partners who provide some amount of oil field services? If that is so, why could not Petronas itself have become an equity partner? After all it has the funds and more capability and capacity than all the oil field companies put together.

Petronas has to remain cognisant that it is the guardian and keeper of the nation’s oil and gas wealth and it needs to guard that position jealously against both foreign as well as local companies so that maximum benefit is obtained by the Malaysian public from its oil and gas wealth.

Any other agenda is secondary to that. The only way to have done this without raising any controversy is for Petronas to have set up a subsidiary to undertake production from marginal oil fields, in the same way that it set up Petronas Carigali for its exploration activities.

Then this subsidiary can enter into joint ventures with the various world-renowned names who are engaged in exploiting oil from marginal wells and after many years, it would have gained enough expertise and size to venture out into the world much the way that Petronas itself has for oil exploration.

The RSC with its explicit agenda of promoting local companies will do just that probably at the cost of Petronas itself because international companies can be expected to extract concessions for the profits they forego to local companies, who will be too small and too diverse to ever become a force internationally.

If Petronas still insists that this arrangement is best, than it has to reveal all. As a national oil corporation, the more transparent it becomes, the more the public will see its workings and the less suspicions it will have. Let’s see if the numbers are forthcoming.

Managing Editor P Gunasegaram believes that one major oil company – Petronas – is enough for Malaysia.

Related Stories:
Petrofac explains key performance indicators
Mokhzani: Kencana’s committed to the project
SapuraCrest willing to take the risk
Potential beneficiaries

Drilling for future opportunities


For the first time local oil and gas players have a chance to play a major role in the production and development of marginal oil fields. However there are risks involved. Will the local companies step up to the challenge?

THE recent US$800mil risk-service contract (RSC) awarded by Petroliam Nasional Bhd (Petronas) to a consortium formed by two local parties and a foreign player for the development and production of the Berantai marginal oil field, located 150km offshore Terengganu, has drawn enormous interest for more than one reason.

Firstly, it marks the adoption of a new contract, RSC, for development and production of local marginal oilfields (as oppose to the production-sharing contract used for exploration and production works).

As the bidding for many more local marginal oilfields are to be carried out, local oil and gas service providers stand to reap benefits either by way of being a bidder or as a beneficiary of sub-contracts.

Although there is certainty that marginal fields have petroleum resources, there is no certainty how much can eventually be exploited from these fields.

But this also gives rise to questions on how local contractors are chosen, why Petronas has not chosen to undertake development of these fields through its own unit, and will local oil and gas service providers learn quickly enough to go it alone in marginal oil field development in the coming years?

The art of the field

National oil company Petronas president and chief executive officer Datuk Shamsul Azhar Abbas says Malaysia has 106 marginal oil fields containing 580 million barrels of oil, with Petronas having firm plans to develop 25% of the total marginal oil fields to replenish its oil reserves and generate new revenue.

A marginal oil field is defined as a field that can produce 30 million barrels of oil equivalent (BOE) or less.

“For the remaining 75% of marginal oil fields, we don’t have plans yet as they require further assessment. We have been working with the Government to come up with another method as the PSC (arrangement) does not encourage the development of marginal oil fields,” Shamsul told a media briefing held late last month.

Shamsul says that two more marginal field contracts will be awarded by April.

Datuk Shamsul Azhar Abbas says two more marginal field contracts will be awarded in April.

The first RSC was awarded to a consortium formed by Kencana Petroleum Bhd, SapuraCrest Petroleum Bhd and Petrofac Energy Developments Sdn Bhd (PED) in January to develop and produce petroleum resources in Berantai over a nine-year period starting from Jan 31 this year.

The joint operating agreement will be 50% owned and led by PED, part of the London-listed Petrofac Ltd group of companies, while Kencana‘s wholly-owned Kencana Energy Sdn Bhd and SapuraCrest’s wholly-owned Sapura Energy Ventures Sdn Bhd would each hold a 25% interest.

Bids for marginal oil fields are called roughly every quarter, with the bid for the Berantai oil field having taken place last October and the next bidding expected to take place in March. As Petronas will cluster four to five marginal oil fields to make it more attractive in drawing bidders, the 26-odd marginal fields earmarked for development will likely be awarded in the next one to two years, says an industry source.

While the estimated cost of development for the Berantai marginal field is pegged at US$800mil, an industry player projects that development cost for the other marginal fields could vary between US$500mil and US$1bil, with the RSCs tenure ranging from three to nine years accordingly.

Although there is certainty that these marginal fields will have petroleum resources, there is no certainty how much can eventually be exploited from these fields.

“For any field under the ground, you are using probability from high up utilising the seismic (method). The chances of misjudgement are high for marginal oil fields, which are smaller in nature compared with bigger (developed) oil fields,” says Dialog Group Bhd executive chairman Ngau Boon Keat. Dialog is an engineering company in the oil, gas, petrochemical and chemical industries and is widely speculated by research houses as one of the front-runners for the RSC job to be awarded down the road.

The seismic method is used for exploration of oil and gas, involving field acquisition, data processing and geologic interpretation.

Kencana Petroleum chief executive officer Datuk Mokhzani Mahathir says each marginal field is unique as its geology and geophysics would vary, thus the business model for each field may differ.

Simply put, if a field is estimated to produce say, 30 million barrels, then development cost would be derived based on that. However, if the field eventually only produces 15 million barrels, the higher development cost will have to be absorbed by the contractor. Therein lies the risk.

Ngau Boon Keat … ‘The chances of misjudgement are high for marginal oil fields.’

“A marginal field needs to be studied very carefully before anybody submits a bid. It is not as simple as people think it is,” says Mokhzani.

However, sceptics point out that the risks faced by the consortium partners are limited and that the players are more likely to recoup their investments, hence make a guaranteed profit as the discovery of petroleum resources is a sure bet in marginal fields, which are essentially discovered fields. Noteworthy is that Petronas will own all the oil and gas extracted and produced from these marginal fields.

There is a concern that the fee structure of the RSC may result in less net income for the national oil company as opposed to if Petronas were to develop these marginal oil fields on its own or together with a niche foreign player.

The foreign player, in the consortium, will act as the main contractor to develop and operate the marginal oil fields. Given that the foreign player will not want to see its margin squeezed through the presence of a local partner (which it is required to tie up with under the RSC), there is concern that Petronas may end up paying out more than it really needs to under these contracts.

These concerns have arisen in the absence of furher details on the RSC. Petronas declined to response to queries by StarBizWeek, specifically on the RSCs, as they are deemed confidential.

But this much, Petronas has made known. The project cost will be forked out by the contractors based on their equity portion and that contractors will receive payment only upon first production, which involves a reasonable return with limited upside.

The contractors also have to meet key performance indicators such as the development cost, production rate and time-frame that have been agreed upon by both Petronas and the consortium, with incentives or penalties triggered depending on the consortium’s performance.

In defence

The local players are quick to defend their role in the consortium, stressing that they have been chosen solely on the merits of their technical and financial capabilities.

“These are very credible and serious players getting together to provide a service to the client (Petronas). There are (also) other companies in Malaysia which can chip in to do different things. The client will have to vet these companies based on their criteria, which are extremely high, such as technical expertise, competencies, the track record of having delivered projects on time within cost and the balance sheet to take on such big projects,” says Mokhzani.

Sapura Group president and chief executive officer Datuk Shahril Shamsuddin says that one way of ensuring the local partners carry their weight in the consortium is the investment that will be pumped in according to their equity portions.

“To ensure that the locals can execute the job, Petronas has asked us to put in our own money so that if we make a mistake, we’ll get burnt. US$200mil is like half of our cash reserve, so the motivation to do things right is very high!” says Shahril.

Both Mokhzani and Shahril emphasise that Petrofac chose them as its partners due to their respective long-standing working relationships.

“This is a fast-track project, so they need someone with competencies and in our case it was in laying the pipes to do subsea infrastructure installation to manufacturing subsea equipment. They wanted to look for a partner that will not drop the ball it is about risk mitigation as well as sharing of risk,” says Shahril.

While the foreign player is at liberty to choose its local partner, the buck does not stop there. According to an industry source, Petronas would also need to sign off on the local partners selected by the foreign companies.

“There are some people who just want to be agents … they want to get the job and then outsource the work. But Petronas will not allow these agents to be bidders. The bidders will have to be real oil and gas service providers that are listed,” the source adds.

Although there may be some 15 local companies involved in the oil service presently, only half may have the financial muscle to pull off the financing involved as a partner in marginal oil field development.

Thus, it can be expected that the remaining local companies to be awarded the RSCs will continue to draw much attention and scrutiny from the public.

A sweet deal

If an average marginal oil field produces 30 million BOE and is sold at an average crude oil price of US$80 per barrel minus the development cost of US$800mil, Petronas would make US$1.6bil without taking into account the “reasonable return” paid to the consortium partners.

An industry source says that potential return on marginal oil field development for the contractors can be as high as 15%, in line with returns seen for upstream works.

For illustration, a 15% return on the Berantai field development works out to be US$120mil (RM360mil). This means that local players Kencana and SapuraCrest could see gross profits of up to RM90mil respectively based on their equity portion, which breaks down further to RM10mil yearly per company over the contract period.

OSK Research Sdn Bhd says it expects potential revenue and earnings for Kencana to comprise a combination of fabrication of oil and gas structures as well as some installation revenue.

“We understand that the net fabrication margin for this project is about 15%. Going forward, margins are expected to improve, especially when the company starts to manage the oilfield in 2012, by which time margins could well exceed 50%,” its report on Kencana last month said.

However, both Kencana’s Mokhzani and Sapura’s Shahril remain mum when asked on their expected returns from the Berantai project.

Industry observers have also wondered why Petronas has not formed its own unit for the development and production of marginal oil fields, especially since it is the custodian of the country’s oil and gas reserves.

While it is a question best left answered by Petronas, chiefs of the local oil and gas companies offer a few possibilities.

Shahril says that it makes more sense for Petronas to deploy larger investments and its human capital for larger exploration and production projects that bring in higher returns.

“Take two companies Company A with RM10bil assets invests RM300mil to make annual returns of RM1bil while Company B with RM100bil assets invests RM3bil to make RM10bil annually. Company B, which has a larger asset base, would represent Petronas,” he explains.

Ngau says that Petronas would typically focus its manpower to develop larger fields as opposed to operating marginal oil fields.

Another corporate head agrees, saying that Petronas has to focus its limited manpower, especially with many of its engineers being sought after by Middle Eastern oil and gas companies.

“Many Petronas engineers were offered salaries that were four to eight times higher by the Arabs, several years ago. So the manpower now has to be used for bigger projects,” he adds.

Big boys don’t try

Petronas’ Shamsul had mentioned that oil majors, such as Shell and ExxonMobil, are not keen to develop marginal fields as they are considered “sub-economic”. While marginal fields may be part of their local PSCs, some of these foreign majors have chosen to relinquish them, passing them back to Petronas largely owing to lack of interest.

Shamsul adds that a key motivation in getting the foreign players to tie up with the locals is to allow the latter to broaden their technical expertise and knowledge.

Acknowledging that local oil and gas service providers cannot become exploration and production players, Shamsul says that local service providers could become development and production players.

“The local guys can’t do it themselves, so we need to bring in the teachers and upgrade the capability of local players,” says Shamsul.

There are many foreign oil companies in the world which focus largely on marginal oilfields. They include London-based Petrofac, US-based Newfield Exploration Co, UK-based Salamander Energy Plc, Abu Dhabi’s Mubadala Oil & Gas, Australia’s Roc Oil Co Ltd, French-founded Perenco Group and Swedish Lundin Petroleum AB.

If these projects take off as planned, it will have a multiplier effect on the economy such as job creation while retaining the wealth within the economy (as opposed to awarding all of it to foreign players who are likely to expatriate their profits to their respective home base).

In addition, it could also increase the possibility of local companies, one day, venturing into the development of marginal oil fields overseas.

While industry players hope to acquire the relevant skills to become the main contractor of marginal oil fields in the next five to seven years, Shahril is gunning for his company to do it within three to four years.

“We need to learn to complete our value chain now. What happens to the local oil and gas industry when all the oil here runs out? So we’ve gotta start developing our capabilities now to get the jobs out there in future,” he says.

All of that, of course, will depend on whether the plan to award local players a stab at developing marginal oil fields in the country and its aim to allow them to tap the skills and know-how of foreign oil companies to better compete for jobs abroad, will work out as planned. Until then, the process will be closely scrutinised by market watchers.

Related Stories:
Petrofac explains key performance indicators
Mokhzani: Kencana’s committed to the project
SapuraCrest willing to take the risk
Potential beneficiaries

So long, new deepwater drilling regulations

By Shelley DuBois, reporterAugust 4, 2010: 3:44 PM ET

FORTUNE — Yesterday, Democrats in the Senate rejected taking up a new oil spill response bill because of a dispute over who foots the costs of future spill cleanups and more importantly, how much those parties — largely oil and exploration companies — will pay. The Senate is voting on the bill, vaguely titled “a bill to promote clean energy jobs and oil accountability, and for other purposes” in response to BP (BP)’s spill in the Gulf at the Macondo well.

Other parts of the over 400-page bill about energy in general and offshore drilling in particular include safety measures. Until some version of the bill passes, important issues with offshore drilling will remain caught in legislative limbo.

That’s a problem. Oil companies have argued that they have stringent safety policies on offshore rigs, regardless of holes in the regulatory system. Many of them do. But this spill has highlighted the need for more efficient oversight.

This block will slow that. The Senate, according to Politico, is supposed to vote again next month, but there’s no sign anything will change in that time to help the bill pass.

The major point of contention was the lifting of the liability cap. Generally, Democrats want to hold companies accountable for spill-related damage over $75 million(See editor’s note.) Republicans think that the liability cap should stay, so that spills won’t bankrupt oil companies.

Either way, the debate is holding up policy that should have been in place long before the spill.

Some examples of actions from the defunct bill that will now live in limbo:

  • SEC. 104. OIL AND HAZARDOUS SUBSTANCE RESPONSE PLANNING: This section mandates that the government must have a plan if another spill of this size happens again. The US has never had to deal with a spill of this magnitude, nor has it ever had to intervene at the level it has with the Gulf spill. As a result, it stumbled from strategy to strategy. A well thought-out and well described plan should help in future catastrophes
  • 204. SCIENCE AND TECHNOLOGY ADVICE AND GUIDANCE. A non-government, non-industry group of science and technology experts would weigh in on whether the government’s oil spill response plan is adequate.
  • SEC. 205. OIL POLLUTION RESEARCH AND DEVELOPMENT: This would allow the Department of the Interior to research ways to clean up oil spilled in the continental shelf and figure out how much damage this spill actually caused. There generally isn’t good follow-up to spill damage once the slicks are gone. This would be a welcome change.
  • SEC. 626. CERTIFICATE OF INSPECTION REQUIREMENTS: Under this section, floating rigs would have to adhere to the highest safety requirements. The key part of this is regulating blowout preventers – the section demands that all rigs have one that works. Most rigs out there do. Still, given the blow out preventer problems with the Deepwater Horizon, it couldn’t hurt to put this requirement more firmly on the books.

For any of these regulations to win passage, both political parties will have to agree about how much to charge companies that spill, with Republicans seeking to limit damages for future spills. Otherwise, other important parts of deepwater drilling regulation will be bereft of a much-needed update.

Editor’s note: Due to an editing error the damage cap was reported as $75 billion. It is $75 million. To top of page

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BP chief sails into fresh storm in US after taking time out for yacht race

By Angus Howarth

EMBATTLED BP chief executive Tony Hayward is at the centre of a new controversy after he went sailing in the face of mounting criticism that he is not doing enough to control the oil spill disaster in the Gulf of Mexico.

Tony Hayward’s yacht, Bob, one of the 1,754 vessels taking part in the 50-mile race round the Isle of Wight on Saturday. Picture: PA

Video: Shelby: Hayward Must Go YouTube CBS

BP boss tries to get his life back, but sails into another storm Sydney Morning Herald

Critics Knock Wind Out Of BP Chief’s Sails Sky News

The White House led the hostile comment after Mr Hayward spent time relaxing on the Isle of Wight at the JP Morgan Asset Management Round the Island Race.

The crisis that followed the blast on the Deepwater Horizon well, which killed 11 workers, has seen millions of gallons of oil continuing to threaten the Gulf Coast. It is America’s worst environmental disaster and has led to tensions between the United States administration and BP. President Barack Obama’s chief of staff, Rahm Emanuel, said Mr Hayward had committed yet another in a “long line of PR gaffes” by attending the race while the disaster continued.

He also mocked Mr Hayward’s notorious statement on Facebook that he wished the crisis was over so he could have his life back.

Referring to the yachting, Mr Emanuel said: “He’s got his life back, as he would say.”

He added that the focus should stay on capping the leaking well and helping the people of the Gulf region.

Charlie Kronick, of Greenpeace, was also angry and said Mr Hayward’s actions were “rubbing salt into the wounds” of people whose communities have been affected by the catastrophe.

A BP spokeswoman said: “We wouldn’t dream of commenting on what the chief executive does in his rare moments of private time.” She added he was spending some time with his son.

It is understood Mr Hayward has spent much of the eight weeks since the accident in the US.

BP officials also insisted Mr Hayward was still in charge of the operation to control the spill, amid confusion over his role.

On Friday, company chairman Carl-Henric Svanberg said Mr Hayward had been relieved of day-to-day control of the spill and that BP managing director Bob Dudley would take over.

However, other officials insisted Mr Hayward remained in charge of the operation.

Shadow foreign secretary David Miliband said Mr Hayward’s position did not mean he should not be able to spend a day with his son.

But he added: “Does it mean that he does have to lead the company to deal with this fundamental issue that threatens the whole future of the economy? Yes, it does.”

Oil giant ‘plans to raise $50bn’ to help pay for oil spill clean-up

EMBATTLED BP is understood to be working on plans to raise $50 billion (£33.76bn) to cover the cost of the Gulf of Mexico oil spill – more than double the amount previously thought.

Directors at the oil group are said to have approved a scheme last week to raise the money in a bid to ensure they have enough reserves to cover any claims as a result of the disaster.

The figure is more than double the $20bn the group has already agreed to pay into a compensation fund for those affected by the spill, although analysts have warned the final cost of the disaster could be as much as $100bn.

BP is expected to start raising the cash as early as next week through a $10bn bond sale.

It is also understood to be in talks with banks to raise a further $20bn through loans, with another $20bn to be raised through asset sales during the coming two years.

BP has already scrapped shareholder dividends until the end of the year to help pay for the clean-up operation.

The company pointed out that chairman Carl-Henric Svanberg had said last week that the company needed to have “an unusually strong cash position”.

The group is reported to be preparing to take legal action against one of its partners, Anadarko Petroleum, after it said it would not cover any of the cost of the clean-up.

BP owns 65 per cent of the ruptured Deepwater Horizon well, while Anadarko has a 25 per cent stake.

Anadarko’s chairman and chief executive Jim Hackett said BP’s actions probably amounted to “gross negligence or willful misconduct” and that it should foot the whole damage bill.

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How to Prevent Deepwater Spills

Safety upgrades are critical but could mean higher prices for oil and gas

A cuture of tighter safety and more experienced regulators might have prevented the BP Deepwater Horizon leak. But equipment modifications and new technology will be needed to minimize the risk of such deepwater oil leaks. According to some petroleum engineers, recommended technology upgrades could price some deepwater resources out of the global energy market.

A mess: Workers clean up oil from a beach on Grand Isle, LA, earlier this week.  Credit: U.S. Coast Guard/PA2 Gary Rives

This could help extend the six-month moratorium on deepwater drilling instituted by President Obama last month. “I tend to be kind of a glass half empty guy, but I think there’s a 50/50 chance that the current six-month moratorium will stretch out,” says Paul Bommer, a senior lecturer in petroleum engineering at the University of Texas at Austin.

Documents and statements released by various federal investigators point to several decisions and at least one faulty piece of equipment that allowed uncontrolled gas and crude to blow out and destroy the Deepwater Horizon rig in April, initiating the worst oil spill in U.S. history.

Engineers contacted by Technology Review insist that conclusive answers will come with completion of the investigations, but criticize, for example, BP’s decision to install a continuous set of threaded casing pipes from the wellhead down to the bottom of its well. “The only thing I can figure is they must have thought it was a cost-cutting deal,” says Bommer of BP’s well design.

This can be problematic in deep, high-pressure wells for two reasons. First, it seals off the space between the casing and the bore hole, leaving one blind to leaks that sneak up around the casing pipe (as the BP Deepwater blowout is suspected to have done). Second, the long string gives gas more time to percolate into the well. A preferred alternative in high-pressure deepwater is a “liner” design in which drillers install and then cement in place a short string of casing in the lower reaches of the well before casing the rest of the well. This design enables the driller to watch for leaks while the cement is setting. “It takes a more time and costs a little more but it’s a much safer way to do it,” says Geoff Kimbrough, vice president for deepwater operations at Houston-based drilling consultancy New Tech Engineering.

Kimbrough cautions that transforming corporate cultures will take time because choosing the more conservative operation can easily cost $10 million to $20 million. Not all companies have leaders who readily support these decisions, says Kimbrough: “The courage to do that doesn’t come overnight. It comes from years and years of support from senior management.”

Regulatory ideas for how to push a culture of safety appear in a 30-day safety review delivered to Secretary of the Interior Ken Salazar late last month, and include establishing new drilling guidelines, operator certification requirements, and tougher inspection regimes. Kimbrough says the Interior Department must simultaneously boost its internal training so that it can effectively review drilling plans.

Attention has also focused on the failed blowout preventer, or BOP, that could have saved the Deepwater Horizon. The Interior safety review calls for upgrades to BOPs to address various failure mechanisms that may have doomed the Deepwater Horizon, such as placement of redundant shear rams strong enough to cut through the toughened threading between casing pipes.

One inherently safer option that many petroleum engineers are considering is bringing BOPs to the surface. In this scheme the BOP on the wellhead thousands of feet below the ocean surface is backed up by a second BOP on the drill rig that would be accessible for more regular inspection and testing. Doing so would mean hardening the risers that link the wellhead and the drill rig to handle extreme pressures.

It’s a suggestion that Kimbrough thinks is impractical. “The cost would be somewhere near prohibitive,” he says. “Just the cost to develop the system would be astronomical.” Mandating something like that would delay new drilling by at least several years. “You’re talking about years to develop and test and prove up something like that.”

But Bommer says the potential costs are likely to be small compared to the economic impact and incalculable ecological damage that the Gulf region has sustained from BP’s leak. In Bommer’s view, if such “brute force” safety engineering pushes oil and gas companies to question whether it’s economically viable to tap deepwater reserves, so be it. “Cost is the last thing people should be thinking about now,” he says.

Another area pegged for technology development is deepwater leak response. BP’s ad-hoc response to the Deepwater Horizon leak has revealed the lack of equipment and procedures for high-pressure remote operations. BP’s CEO Tony Hayward acknowledged as much last week, saying that despite assurances in its drilling permit applications, BP “did not have the tools you would want” to respond to a deepwater leak.

In fact, the tool shortage for deepwater intervention is an issue long recognized by petroleum engineering researchers. The months-long process of drilling a relief well was, until now, the only proven fallback available in cases where the BOP fails to stop a blowout. A 2003 presentation by Texas A&M University researchers modeling deepwater blowouts cited reliance on relief wells as evidence of a “fatalistic mind-set in the industry.”

The lack of progress since then supports that assessment. Since 2005 Congress has left deepwater research primarily in the hands of the Research Partnership to Secure Energy for America, a U.S. Department of Energy-supported petroleum industry consortium in Sugar Land, Texas. But RPSEA has focused its $17 million annual budget for deepwater R&D on production-related issues.

Drilling engineers say the BP accident could finally provide the impetus for deepwater response tools. Funding to perfect some of the schemes that BP has thrown at the spill, they say, should spawn an entire deepwater response industry, analogous to the well-control contractors who secure hundreds of dangerous onshore wells per year worldwide.

James Pappas, RPSEA’s vice president of technical operations, claims that his consortium is already beginning to refocus its research agenda toward safety-related R&D. For example, he sees an opportunity to improve sensing capabilities inside deepwater wells after the drill bit is pulled: “That’s a weak spot right there, a blind side, that we haven’t really addressed as an industry.”

But Pappas and other engineers acknowledge that better training, BOPs, and response tools may not convince an outraged country that a sequel to the Deepwater Horizon disaster is impossible. They say it may take more radical upgrades to drilling technology to lift the current six-month moratorium. “We have to go back to square one and prove that we’re reliable and responsible enough to take care of our business,” says Pappas.

By Peter Fairley

Related Articles

» Another Chance to Stop the Gulf Leak
But BP’s “top kill” method to stanch the spill could also break it wide open.

» How Technology Failed in the Gulf Spill
The disaster exposes overreliance on blowout preventers that has been long disparaged by insiders.

» Nano Sponge For Oil Spills
A nanowire membrane that sops up oil while repelling water could be used for cleaning up oil spills.

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The Real Culprit Behind BP’s Oil Spill

America’s unstoppable dependence on oil.


Coastal animals covered in oily filth have given us a visceral sense of what the BP oil disaster means for our natural environment. The more disturbing news is that this oil spill represents a drop in the bucket–a small fraction of the petroleum that enters the world’s oceans every year.

A NASA estimate found that roughly 6 million tons of petroleum products enter the world’s oceans every year, or 0.25% of total world oil production. Water sewage treatment plants, for example, spew far more oil into the oceans than tanker spills in most years. Even leaving aside truly catastrophic spills like Deepwater Horizon and Exxon Valdez, estimates of average annual spills from rigs and tankers range as high as 250 millions gallons per year. These spills tend to attract far less attention. We don’t see haunting photographs of oil-stained dragonfly’s wings when a Nigerian tanker explodes. But irreplaceable forms of life are endangered all the same.

Armed with righteous indignation, a large and growing number of Americans are demanding that we end our reliance on oil and build a new energy economy in its place. The problem is that the American middle class can’t afford sudden and abrupt change.

This past year the U.S. Department of Commerce published a fascinating report for the White House Task Force on the Middle Class. To provide a more vivid illustration of the choices facing middle-class families, the report’s authors present three two-parent, two-child families at three different income levels: $80,600 for the median family, $122,800 for the family at the 75th percentile and $50,800 for the family at the 25th percentile. For all three families the cost of owning and maintaining an automobile is staggeringly high. The 75th percentile family spends $15,400 a year on two large sedans or SUVs at a purchase price of $30,000 and drives them a total of 25,000 miles a year. If this sounds profligate, consider that mobility enables a family like this to earn as much as it does: Both parents commute and work long hours, both make trips to the grocery store to stock up on prepackaged meals. The family winds up devoting far more resources to mobility than to medical care, college savings or retirement savings.

The median family is hit even harder by car ownership. Though this family purchases less expensive vehicles, it has to drive just as much. The $12,400 it spends on mobility matches what it has to pay in taxes. And for the family at the 25th percentile, which still has to drive 25,000 miles a year, the cost of mobility dwarfs the amount of taxes owed: $7,900 for two small used sedans against $6,000 in taxes. Consider what happens when you ask these two families to pay a much higher gasoline tax. Or what happens when you offer a tax credit to buy a new fuel-efficient hybrid vehicle. Given how little these families are able to save in an average year, there is no asset cushion that would allow you to buy your way out of oil dependence. The Commerce report sheds light on the angst and anxiety caused by spikes in the price of gasoline, and why efforts by congressional Democrats to pass cap-and-trade have met such ferocious resistance.

It also tells us why environmental outrage tends to dissipate after the networks stop showing footage of baby pelicans weighed down by thick globs of oil. Think of how a working parent at the median income or at the 25th percentile must feel every time she sees the price at the pump, and how it determines how much she can save for her child’s college education or for her own retirement. Once a symbol of freedom and independence, the automobile is increasingly seen as a punishing and inescapable burden. It has an appetite almost as bottomless as that of a child, only it never loves you back.


All hope is not lost. We can reduce our dependence on oil and reduce the danger it poses to our natural environment. The surest route to that end is to make more families–here and around the world–affluent enough to bear the very high transition costs. Because that process will take a very long time, we need to consider a more urgent approach.

Decades of mortgage subsidies pushed homeownership to levels approaching 70%. Though the number of homeowners has declined in the wake of the recent housing bust, millions of Americans are still tethered to homes they can’t afford in weak job markets. Rather than increase overall spending, thus pushing up the tax burden on middle class households, we’d do well to shift some of the $200 billion we spend a year on housing subsidies to easing the economic costs of clean mobility.

Lisa Margonelli, author of Oil on the Brain, has crafted a reform proposal designed to reduce oil dependence without overburdening working and middle class families. A broader package could include everything from generous subsidies for transit to loans designed to encourage the purchase of fuel-efficient vehicles, perfectly targeted to meet the needs of households at the 25th and 50th percentiles. This approach is far from perfect. But it may just give us the political capital we need to fight pollution.By Reihan Salam who is a policy advisor at e21 and a fellow at the New America Foundation. The co-author of Grand New Party: How Republicans Can Win the Working Class and Save the American Dream, he writes a weekly column for Forbes.

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BP’s $70 billion whipping

Since April 20 when the Gulf oil spill began, BP shares have tumbled about 40%.

NEW YORK ( — Despite the sharp fall in BP’s share price following the company’s inability to cap a leaking well in the Gulf of Mexico, most analysts say the selloff is overdone.

BP shares sank nearly 15% Tuesday after the company’s latest attempt to seal the leaking Gulf oil well failed over the weekend. The selloff accelerated just before the closing bell, when U.S. Attorney General Eric Holder announced a criminal probe into the spill.

Since the accident happened April 20, which resulted in 11 deaths and an oil leak of up to 19,000 barrels per day, BP shares have fallen nearly 40%, wiping out nearly $70 billion in shareholder value. Before the accident the company had a market capitalization of nearly $183 billion. Now it’s just below $115 billion.

Investors are concerned the clean up costs, lawsuits, and added restrictions from the spill, the worst in U.S. history, will sap BP’s earnings potential.

Plus, like most big oil projects, BP is self-insured for the operation, so all of the costs of the cleanup and damages will fall on its shoulders.

No one knows how much the spill will eventually cost BP. Estimates have ranged from $3 billion to $25 billion – many fall somewhere in the middle. As of Tuesday BP said it has spent just shy of $1 billion on the accident.

But whatever the price tag, it will likely be paid out over a period of years. For a company that made nearly $17 billion in profit last year and is expected to top $20 billion this year, most analysts say the stock hit is unjustified.

“They’ve got a balance sheet you could slap $20 billion of debt on and not miss a beat,” said Mark Gilman, an oil and gas analyst with the Benchmark Co., a boutique broker-dealer. “We think the financial hit has been excessive.”

Indeed, so do the majority of analysts.

In England, where BP (BP) is based, 38 analysts have a buy rating on the stock and eight have it as a hold. Only three recommend selling it, said Douglas Youngson, an oil analyst at Arbuthnot Securities, a London-based investment bank.

Beyond the clean up costs and lawsuits, there’s also possible damage to BP’s reputation. This is, after all, the company that branded itself an environmentally friendly oil firm, buying wind farms and solar arrays and adopting the slogan “Beyond Petroleum.”

Will there there be a major public backlash?

“‘Here in America we tend to have pretty short memories,” said Ken Carol, an oil analyst at Johnson Rice & Co. “There was a big boycott after the Exxon Valdez, and they seem to be doing just fine now.”

Carrol also didn’t think the spill would impact too heavily on BP’s relationship with other oil companies. Because of the high up front costs to develop an oil field, many partners are often required on a project. In this case, BP had partnered with Anadarko (APC, Fortune 500) and the Japanese firm Matsui.

Many subcontractors are also brought in to work on an oil well. The primary subcontracts in this case were Halliburton (HAL, Fortune 500) and Transocean (RIG).

Might it be harder for BP to find partners in the wake of this disaster?

“BP has been a good partner before,” said Carrol. “I don’t think people will turn their backs on them.”

Carrol said the selloff in BP’s share price was likely overdone, but said he didn’t expect it to get any better until BP can fix the problem.

As long as the well is leaking, the costs are adding up, he said.

Dissenting opinion

When BP will fix the problem is anyone’s guess. The company is trying to put a new dome over the leak this week, but with several previous attempts to cap the well failing, that procedure looks like a long shot.

The company is saying it may not be able to stop the leak until August, when a relief well being drilled into the failed well’s base is completed.

“That’s two months of horrible images and horrific headlines,” said Youngson, the analyst at Arbuthnot Securities.

Youngson is one of the few analysts that are recommending people sell BP’s stock.

He thinks that in addition to the massive cleanup and liability cots, BP will face serious regulatory pressure going forward. That may mean a loss of leases in the Gulf of Mexico, and a loss of confidence from their peers.

“Anything BP does in the future will be under the microscope, and that will drive costs higher,” he said.

Youngson also brought up another possibility that most other analysts have not openly talked about to date: That BP stock could get so cheap it might be the subject of a takeover.

He thinks if the stock falls much below $30 a share, BP will become a target. Shares traded around $38 Tuesday afternoon.

‘If the share price continues to fall,” he said, “other companies may see this for the bargain it will be.”

By Steve Hargreaves, Senior writerJune 1, 2010: 4:52 PM ET

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