Listado de la etiqueta: oil

What Will Drive LNG Growth for the Next Decade?

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Question: What will be more localized, more widely dispersed and more transparent a decade from now? Answer: The liquefied natural gas (LNG) industry.

A recent Deloitte report on the changing LNG landscape presents such a scenario, and one of the report’s authors credits the United States’ emergence as a gas exporter as a catalyst for the evolution.

«The beginning of exports of LNG from the U.S. in 2016 adds an interesting new component to the global market, expanding the range of options available to buyers both geographically and in terms of pricing basis,» said Andrew Slaughter, executive director of the Deloitte Center for Energy Solutions.

Slaughter, who wrote the report with colleague John England, also sees liquid hub-based pricing becoming a more viable option compared to longstanding oil-linked LNG pricing formulas.

«It will be interesting to see whether this type of competition results in changes in strategy from the more traditional LNG suppliers,» Slaughter said.

In a recent interview with DownstreamToday, Slaughter elaborated on the Deloitte report’s findings. Moreover, he explained why – despite the unease felt by many in the LNG sector – he sees reason for industry players to be optimistic. Read on for his insights.

DownstreamToday: How would you summarize the current upheaval in the global energy market, and where does LNG fit in amid this dynamic environment?

Andrew Slaughter: In the short term, the global energy market is still adjusting to a lower oil price environment, in which crude oil prices dropped from above $100 per barrel down to $30-$40 levels since June 2014. While the primary causes of this were an accumulating imbalance of oil supply growth, relative to oil demand growth, the LNG market was not immune to the consequences. Long-term contract prices for LNG, which are linked by formula to crude oil price levels, have declined along with crude oil, negatively impacting the cash flow of existing LNG suppliers, as well as putting into question the expected economic returns for new and proposed LNG supply projects.

Over the longer term, in a world where most nations have committed to carbon mitigation policies at COP21, we expect natural gas to be able to increase its share of energy demand around the world, both because of its intrinsically lower carbon intensity than other fossil fuels and also because of its complementarity with renewable energy in the power sector, providing grid stability and reliability when renewable generation is not available. We expect LNG to play a significant part in meeting this growth in gas demand around the world over the next two or three decades.

DownstreamToday: Deloitte has observed that the LNG trade has quadrupled over the last two decades and is poised to double over the next two decades. What were some key attributes of the previous growth period, and what major characteristics would you expect during the next one? Any particularly prominent similarities/differences?

Slaughter: LNG market growth over the past 20 years has predominantly been characterized by the development of large integrated gas projects in which most LNG has been committed to buyers under long-term contracts. This model has been necessary to secure project financing for multi-billion dollar investment in upstream gas development, liquefaction trains, specialized ships and regasification terminals. Using this model, new LNG supply sources have been developed in resource-rich countries like Qatar, Australia, Trinidad and Nigeria; and large new markets have been opened up, such as India and China.

Over the next 10 to 20 years, we expect growth in the LNG market to be associated with the opening up of many more, often smaller, markets served by more flexible supply options, such as floating storage and regasification units, smaller, more modular liquefaction technologies and the growth of both portfolio supplies and LNG traders to more flexibly match supply with market needs. We also expect new and emerging applications for LNG to grow, creating an additional boost to demand – such as LNG as a marine fuel and as a fuel for heavy trucks and rail.

DownstreamToday: You’ve identified seven key factors that should drive LNG growth in the next 10 years. Which of these factors is supported by the strongest evidence? Which factors are more of a guessing game?

Slaughter: Of the seven key factors identified in the Deloitte report, three represent challenges for LNG development, at least for the next several years. The potential slowdown in global economic growth, and perhaps particularly in China, may lead to a near-term slowing of LNG demand, as will continued improvements in energy efficiency which work to decouple demand growth rates from economic growth rates. Thirdly, the amount of new LNG supply capacity planned or announced is a threat to sanctioning the next wave of LNG projects which will likely be needed post 2020.

On the side of opportunity, the other four factors are more favorable to LNG development. These are the reduction of LNG shipping costs, allowing markets to be served more economically; the development of new markets geographically, such as in South East Asia and Latin America; the emerging penetration of LNG into new applications such as for road and marine transport fuels, as well as the larger-scale expansion of LNG as a source for natural gas as a power generation fuel; and the expansion of market liquidity, with more buyers, more sellers, more diverse contract terms and durations making it easier for market participants to structure the right deals to expand their business.

There is fairly strong evidence supporting all these factors, and it will be fascinating to watch how they play out over the next 10 years or so.

DownstreamToday: You’ve no doubt seen industry headlines proclaiming that the era of mega-LNG projects is drawing to a close and that small- and mid-scale projects are on an upward trajectory. What effects on the broader LNG market do you anticipate with the rise of smaller-scale projects?

Slaughter: Smaller-scale projects are emerging on the liquefaction side of the business with project developers proposing smaller and more modular units than have historically been the norm; and also on the regasification side of the business with the increasing deployment of floating regasification and storage units to serve new market locations. Such developments reduce the upfront capital required to launch an LNG project, potentially opening up new sources of financing. And these developments add more flexibility and optionality to the market, and will contribute to the development of new markets and the growth of portfolio players and traders who can play a role in enhancing the efficiency of the market.

DownstreamToday: What is the most surprising thing you learned while preparing your report?

Slaughter: Despite higher-than-accustomed levels of uncertainty about LNG prices, growth prospects and the viability of new supply investments, market participants maintain a high degree of long-term optimism about the future of LNG as a growing and strategic part of the world’s energy supply and trade. This is founded on the attractiveness of natural gas as a fuel in major and emerging markets, for which its lower carbon intensity than other fossil fuels plays a major role; and on the maturing of LNG market structures globally, to accommodate  new contractual options.

 

Copyright: Rig Zone

Exxon, Total, Chevron In Talks With Pemex On Gulf Prospects

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Petroleos Mexicanos is in talks with Exxon Mobil Corp., Total SA and Chevron Corp. as Mexico’s struggling state-run oil producer seeks partners to develop deepwater crude in the Gulf of Mexico.

Pemex may also start discussions with Oslo-based Statoil ASA, according to company press officials who asked not to be named because of policy. Pemex seeks Areas of Mutual Interest agreements to evaluate whether the companies have opportunities to work together in offshore areas.

The talks would indicate the world’s oil majors are interested in partnering with Pemex to produce the country’s underdeveloped crude reserves or bid with Mexico’s state-owned operator in the country’s first-ever deep water auctions in December. Pemex, which deferred investments in deepwater fields this year amid a $5.5 billion budget cut, has reiterated that it seeks to partner with the world’s largest producers to develop Mexico’s crude reserves, estimated by the country’s oil regulator at the equivalent of 10.24 billion barrels of crude at the end of last year.

«They will use the tools in the energy reform to do this,» Nymia Almeida, a senior credit officer for Moody’s, said at a conference in New York, when asked about Pemex forming partnerships and selling assets, which the company intends to do. «Any deal would be better than none, even if it starts little by little.»

Hakon Fonseca Nordang, head of communication for Statoil in the U.S. and Mexico, declined to comment on any discussions, saying that Statoil and Pemex have for years had a General Cooperation Agreement involving research and technology exchange between the two companies. Scott Silvestri, an Exxon spokesman, declined to comment, as did Isabel Ordonez, a spokeswoman for Chevron in Latin America.

Deepwater Auction

Mexico hopes to raise $44 billion in investment in its first-ever sale of deepwater areas in the Gulf of Mexico, scheduled for Dec. 5. The country will auction 10 areas in the Perdido area near the maritime border with the U.S. and in the southern gulf’s Cuenca Salina.

Seventy-six percent of the country’s prospective oil resources are located in the deep waters of the Gulf of Mexico, according to Energy Minister Pedro Joaquin Coldwell. Pemex, Statoil, Chevron and Exxon are among 16 companies that are in the process to qualify to bid in the deep water auctions

Oil Gulf prospects

Copyright: Rig Zone

Success through more efficient use of technology – DEA at EAGE 2016 in Vienna

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From 30 May to 02 June, DEA is presenting recent projects and technology highlights at Europe’s most important technology event of the oil and gas industry, the 78th EAGE Conference and Exhibition.

“In exploration and production of oil and gas, sustained quest for technical solutions and the constant search for efficiency-enhancing concepts are daily business”, says Manfred Böckmann, Senior Vice President Exploration DEA Deutsche Erdoel AG.

These measures are a prerequisite for a continuing assurance of our high safety and environmental standards on the one hand and the economic viability of the projects on the other. In times of low oil prices, this is becoming increasingly important and the EAGE offers an ideal platform for the essential exchange of ideas and the discussion of new approaches, together with the experts of other E&P companies, the service industry and the representatives of science”, Böckmann adds.

At DEA’s booth (Stand No. 2230, Hall B), the visitors can experience live presentations of case studies from international DEA projects and are invited to discuss current industry topics with the DEA experts during the coming days.

DEA Deutsche Erdoel AG is an international operator in the field of exploration and production of crude oil and natural gas based in Hamburg. Its focus is on safe, sustainable and environmental conscious exploitation of oil and gas. DEA has 117 years of experience working along the whole upstream value chain as operator or project partner. With a staff force of 1,400 employees DEA has shares in production facilities and concessions in, among others, Germany, Norway, Denmark, Egypt and Algeria. Moreover, in Germany, DEA also operates large subsurface storage facilities for natural gas.

Copyright: Your Oil and Gas News

Mexico’s Pemex Approves Trion Field as First Farm Out

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Mexican state oil company Pemex has picked the deep-water Trion field near the U.S. border as the first one it will farm out to other operators to help it develop untapped resources, the firm said on Friday.

The search for private capital to boost areas previously discovered by Pemex is a major step in the opening up of Mexico’s oil and gas industry, a process enabled by an energy reform that ended the company’s monopoly in 2013.

Pemex Chief Executive Jose Antonio Gonzalez Anaya told a news conference the company’s board had approved the step and that Trion would likely be operated by a company other than Pemex.

«It’s a big, important field,» Gonzalez said.

The Trion field, located in the Perdido area, will require about $11 billion worth of investment and more farm outs will follow, Gonzalez said. In total, the Trion field contained some 480 million barrels, he added.

Pemex did not have a specific number of investors in mind for the Trion field, he said. The companies involved in the farm out should be announced in December, when Mexico has scheduled its first auctions for deep water fields.

Speaking at the same news conference, Energy Minister Pedro Joaquin Coldwell said the Trion farm out would be in the form of a license and that the field was 2,500 meters (8,202 feet) deep.

Two years of falling crude prices have hurt Pemex, which wants partners to boost output and improve margins.

In the first quarter of this year, Pemex ran up its 14th consecutive quarterly loss at about 62 billion pesos ($3.6 billion), as both crude prices and output fell.

Earlier, Pemex announced that Luis Rafael Montanaro Sanchez had been named as the new director of Pemex’s ethylene unit.

Source: Rig Zone

Raymond James: Get Ready for $80 Oil

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Rebounding after a two-year collapse, it’s only this month that oil prices have pushed up past $50 a barrel, but Raymond James & Associates says this is just the beginning for higher prices.

In a note to clients, analysts led by J. Marshall Adkins say West Texas Intermediate will average $80 per barrel by the end of next year — that’s higher than all but one of the 31 analysts surveyed by Bloomberg. 

«Over the past few months, we’ve gained even more confidence that tightening global oil supply/demand dynamics will support a much higher level of oil prices in 2017,» the team says. «We continue to believe that 2017 WTI oil prices will average about $30/barrel higher than current futures strip prices would indicate.»

The team went on to lay out three reasons for their bullish call, all of which are tied to global supply — the primary factor that precipitated crude’s massive decline.

Here’s how the rebalancing of the global oil market will be expedited from the supply side, according to the analysts:

First, the analysts see production outside the U.S. being curbed by more than they had previously anticipated, which constitutes 400,000 fewer barrels of oil per day being produced in 2017 relative to their January estimate. In particular, they cite organic declines in China, Columbia, Angola, and Mexico as prompting this downward revision.

«When oil drilling activity collapses, oil supply goes down too!,» writes Raymond James. «Amazing, huh?»

Adkins and his fellow analysts also note that the unusually large slew of unplanned supply outages will, in some cases, persist throughout 2017, taking a further 300,000 barrels per day out of global supply.

Finally, U.S. shale producers won’t be able to get their DUCs in a row to respond to higher prices by ramping up output, the team reasons, citing bottlenecks that include a limited available pool of labor and equipment.

Combine this supply curtailment with firmer than expected global demand tied to gasoline consumption, and Adkins has a recipe for $80 crude in relatively short order.

«These newer oil supply/demand estimates are meaningfully more bullish than at the beginning of the year,» he writes. «Our previous price forecast was considerably more bullish than current Street consensus, and our new forecast is even more so.»

The only analyst with a higher price forecast for 2017, among those surveyed by Bloomberg, is Incrementum AG Partner Ronald Stoeferle. He sees West Texas Intermediate at $82 per barrel next year. The consensus estimate is for this grade of crude to average $54 per barrel in 2017.

Over the long haul, however, Raymond James’ team sees WTI prices moderating to about $70 per barrel.

Copyright: Rig Zone

Guidelines for Drilling Wells for the Exploration and Production of Hydrocarbons in Mexico

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The National Hydrocarbons Commission (“CNH”) submitted a draft of the Guidelines for Drilling Wells for Exploration and Production of Hydrocarbons (“Lineamientos de Perforación de Pozos para las Actividades de Exploración y Extracción”; the “Guidelines”) to the Federal Commission for Regulatory Improvement (“COFEMER”).

The Guidelines regulate well permitting, design, construction, integrity, maintenance, and abandonment standards and requirements for all oil, gas, and injection wells in Mexico, whether on-shore or off-shore, conventional or non-conventional, and which apply to both private industry and state productive companies.  They regulate best oil field practices and standards for various activities; provide for inspection, audit, and enforcement; and, include provisions on operator and non-operator liability. Operators and non-operators are liable for all damages related to their activities (well drilling, design, construction, completion, and abandonment, etc.), regardless of whether their underlying exploration contracts with CNH or “entitlements” are in effect.

The Guidelines include the following attachments:

  1. Glossary of defined terms.

  2. Regulatory requirements on best practices for the design, construction, termination, integrity, maintenance, and abandonment of wells.  These requirements are considered to be hierarchically one step below official Mexican standards (NOMs), which means that the latter have control over CNH’s referenced regulatory requirements.

  3. Guidelines for registering oil and gas wells and reservoirs/fields.

  4. Guidelines for well-permitting applications.

  5. Guidelines for ensuring well integrity (e.g., casing and cementing requirements and standards).

  6. Format to request administrative registration of wells.

  7. Format to apply for drilling and completion well permits.

  8. Format for applications to modify previously granted well permits.

Copyright: Haynes boone

Russia’s giant Vankor oilfield reaches peak production level: ONGC

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Russia’s giant Vankor oilfield, where Indian state oil firms are acquiring a significant stake, has reached peak production level, but technology to increase oil recovery will optimise the output and delay its decline, the head of ONGC’s overseas arm said. 

Indian state firms hope to get 10.5 million tonne of crude oil from Vankor once deals are completed to acquire 49.9 % in Russia’s second-largest oilfield, whose output of 21million tonne a year is about the same as ONGC’s entire production from all its Indian fields. Rosneft had announced in March last year that Vankor’s output would decline slightly from the plateau level of 22 million tonne a year. 

«We had entered at the peak production level, and as it happens in all oil fields, this field too will undergo a decline. But with the application of enhanced oil recovery techniques, the decline can be delayed and production optimised,»

ONGC announced a deal to buy 15% stake in the Vankor last year, and is in talks to raise that to 26%. This month, a consortium of Indian Oil Corporation, Oil India and Bharat Petroleum struck a deal to acquire 23.9% in Vankor. Official sources said ONGC paid $1.27 billion, while the consortium spent $2 billion for the bigger stake, giving the same valuation to the giant field. 

Last week, Rosneft said the «achieved evaluation» of the Vankor project was $3.3 per barrel of reserves. Recoverable reserves of Vankor, the largest field commissioned in Russia in the last 25 years, stood at 361 million tonne of oil and condensate and 138 bcm of gas as of January this year.  

India and Russia have intensified energy engagement over the past year.

Copyright: The Economic Times

Oil Bulls Face Specter of Market Turmoil on Brexit Aftershocks

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Oil bulls could end up road kill following the Brexit ballot.

Crude tumbled as much as 6.8 percent June 24 after U.K. voters decided to leave the European Union. While some analysts said supply and demand still favor rising prices, Britain’s exit means there’ll be a period of uncertainty over Europe’s future, casting a shadow over the market.

“A vote for Brexit is a vote against globalization, against the free mobility of people and goods,” said Francisco Blanch, head of commodities research at Bank of America Merrill Lynch in New York. “Any reversal in the growth of trade and mobility is bad for the commodities, except gold.”

Global equities plunged after the decision, while haven assets such as the dollar and gold surged. UBS AG said traders will soon focus again on the fundamentals of the market as a global crude surplus fades. They’ll also have to weigh any lasting impact from the U.K.’s decision on the world economy and oil demand.

Money managers were bullish in the run-up to the British vote, boosting bets on rising crude prices in the week ended June 21, according to data from the Commodity Futures Trading Commission. West Texas Intermediate rose 0.7 percent to $48.85 a barrel on the New York Mercantile Exchange in the report week. Futures tumbled 4.9 percent on June 24 and were down 2.4 percent to $46.51 at 11:09 a.m.

«We were calling for $44 oil in 2016 on average, now we expect it in the low $40s, roughly $41,» said Michael D. Cohen, an analyst at Barclays Plc in New York. “The 2017 forecast has been reduced by $3, from $60 to $57.»

The surprise Brexit outcome moved the greenback, with the Bloomberg Dollar Spot Index climbing 1.8 percent on June 24, the biggest gain since October 2011. A rising U.S. currency curbs investor appetite for dollar-denominated commodities.  Bookmakers’ odds suggested the chance of a vote to leave the EU was less than one in four.

Crude in New York had been on a bull run, climbing more than 80 percent from a 12-year low in February through early June as disruptions from Canada to Nigeria and falling U.S. production eased a surplus. Prices then dropped in three of the last four weeks as Canadian output rose after wildfires that disrupted production were extinguished and the U.S. rig count began to increase.

Re-Balancing Market

“There needs to be a fundamental re-balancing to the market to see sentiment turn bullish and that’s looking unlikely,” said Rob Haworth, a senior investment strategist in Seattle at U.S. Bank Wealth Management, which oversees $133 billion of assets. “The upside for oil was already limited given the rising rig count,” as well as “the fact that a number of OPEC countries plan to boost oil output,» he said.

The Organization of Petroleum Exporting Countries maintained its policy of unrestricted production at its June 2 meeting, and Iran has rejected any cap on output as it restores volumes following the removal of sanctions in January.

Not all analysts are forecasting that the Brexit vote will be bearish for oil. The period of up to two years for negotiations leading to a U.K. exit and the small relative size of the British market may act as a buffer for crude. 
 
“Any impact on the global economy should be limited,” said Michael Wittner, the New York-based head of oil-market research at Societe Generale SA. “The biggest impact will be on the U.K. itself.”  

Bullish Bets

Hedge funds’ net-long position in WTI rose by 21,586 futures and options combined to 213,075, the first gain in five weeks, CFTC data showed. Longs, or bets on rising prices, increased by 4 percent, while shorts dropped 10 percent.

In the Brent market, money managers reduced bullish bets by 9,153 contracts in the week, according to data from ICE Futures Europe. Bets that prices will rise outnumbered short positions by 362,765 lots, the London-based exchange said in a report.

In other markets, net bullish wagers on U.S. ultra low sulfur diesel rose 2.9 percent to 16,528 contracts, the highest since July 2014, as futures climbed 1 percent. Net bullish bets on Nymex gasoline surged 88 percent to 7,012 contracts, the biggest percentage gain since November. Gasoline futures increased 4.7 percent. 

Precious metals were the only commodities to rise after the vote as investors flocked to havens. Gold surged 4.6 percent, its biggest one-day gain since September, while the Bloomberg Commodities Index of 22 raw materials fell 1.6 percent.

“We all got it wrong,” said Michael Lynch, president of Strategic Energy & Economic Research in Winchester, Massachusetts. “This is strengthening the dollar, which is bad for commodities.»

Copyright: Bloomberg

Big Oil’s $45 Billion of New Projects Signal Spending Revival

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Two projects worth $45 billion announced this month show the world’s largest oil companies are regaining the confidence to make big investments, emboldened by rising crude prices and low costs that promise to trigger more expansion ahead.

Chevron Corp. gave the go-ahead to a $37 billion expansion in Kazakhstan, the industry’s biggest undertaking since crude started tumbling two years ago. BP Plc signed off on the $8 billion expansion of a liquefied natural gas plant in Indonesia. Two more big projects are likely to get a green light this year, according to industry consulting firm Wood Mackenzie Ltd. and Jefferies International Ltd. — BP’s Mad Dog Phase 2 in the Gulf of Mexico and Eni SpA’s Coral LNG development off Mozambique.

Crude’s recovery from a 12-year low and a decline in project expenses have emboldened executives to start spending again after cutting more than $1 trillion in planned investments planned investments amid sinking earnings. While protecting balance sheets is important, explorers need to at least begin a new phase of investment in exploration and production to ensure future growth.

“We have seen a recent pick-up, demonstrating that projects deemed strategically important are still going ahead,” said Angus Rodger, a Singapore-based principal analyst for upstream research at Wood Mackenzie. He expects about 10 decisions on midsize to large projects this year from fewer than 10 last year, though still well below the annual average of 40 before oil crashed.

While the price slump hit profit hard, it has also driven down costs of services and equipment, including rigs. Drillers have renegotiated contracts to get better deals from suppliers as reduced demand creates a buyers’ market. 

BP has knocked more than half the cost off its Mad Dog Phase 2 project. Estimated at $20 billion four years ago, it’s now expected to cost less than $9 billion, Chief Executive Officer Bob Dudley said last month. Rig-rental rates are likely to stay down because of an oversupply, while low steel prices are reducing the cost of other equipment, he said.

Chevron and its partners including Exxon Mobil Corp. approved the Tengiz expansion after postponing the decision last year as oil prices were falling. Like BP, Chevron estimates it has been able to bring costs down far enough to make the investment viable. Output is expected to start in 2022. 

Tengiz “has undergone extensive engineering and construction planning reviews and is well-timed to take advantage of lower costs of oil industry goods and services,” Jay Johnson, executive vice president for upstream at Chevron, said in a statement. 

Protecting Dividends

Chevron’s and BP’s investment decisions “are a signal that they’re more confident of their ability to pay their dividend,” said Jason Gammel, a London-based analyst with Jefferies. “It’s showing more confidence” in cash flows.

As earnings fell, companies faced a choice between protecting dividends and cutting investment. The biggest opted to protect payouts, canceling projects and firing thousands of people. While some analysts criticized that strategy, bosses including Ben Van Beurden of Royal Dutch Shell Plc said they were doing what shareholders wanted. 

Brent crude rose 0.8 percent to $46.76 a barrel on the London-based ICE Futures Europe exchange on Friday. That’s less than half what it was two years ago. It means earnings remain under pressure and companies are still planning to keep overall expenditures low expenditures low to preserve their balance sheets.

“Big Oil is still going to be conservative in their spending,” said Brian Youngberg, an analyst at Edward Jones & Co. in St. Louis, Missouri. “Those days of several of these big projects going on at the same time are in the past.”

Crude Turnaround 

Some, including Ian Taylor, CEO of Vitol Group, the world’s largest independent oil-trading house, believe crude’s recent rise is unlikely to last as demand growth slows. Brent also climbed in the first half of 2015 before sliding more than 40 percent by year-end. 

Chevron’s and BP’s plans are for expansions of existing projects rather than something built from scratch. They are easier to push through because they maximize existing infrastructure, said Brendan Warn, a managing director at BMO Capital Markets in London. 

By contrast, Eni’s plans to exploit its giant Coral gas discovery off Mozambique include the first newly built floating LNG plant in Africa. Eni CEO Claudio Descalzi said in April he is “practically sure” the company will make a final investment decision this year.

“Unless oil prices do something very drastic and go lower, these companies now have many projects in their portfolios to pick from,” said Iain Armstrong, a London-based analyst at Brewin Dolphin Ltd. “Times have improved.”

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Copyright: Bloomberg

KKR’s Mexican Oil Deal Kicks Off New Era in Funding for Pemex

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The biggest corporate issuer of bonds in emerging markets appears to be taking a breather.

Petroleos Mexicanos, the state-owned oil company known as Pemex, is finding new ways to raise cash – including a deal with private-equity firm KKR & Co. – as it seeks to limit how much in liabilities it takes on. The company has sold just $8.15 billion in peso and foreign-currency bonds in 2016, and its chief executive said late last month that it’s almost done with selling notes for the year, putting it on course for its lowest issuance in four years, data compiled by Bloomberg show.

It makes sense that Pemex would scale back its bond issues, analysts say, given that its $95 billion debt load is already raising red flags after 14 straight quarterly losses and 11 years of falling output. But the shift in its financing strategy comes with a price.

Pemex agreed to an implied interest rate of 8 percent in a $1.2 billion sale-leaseback deal with KKR last month, according to a person familiar with the deal. While that allows it to raise capital without technically adding to its liabilities, it compares with a 5.125 percent coupon on its most recent issue, a seven-year 900 million-euro bond. The yield on that bond has since fallen to 3.73 percent.

“If things were perfect, they wouldn’t have gone down this road,” said Luis Maizel, who helps manage $5.5 billion of assets, including Pemex bonds, as co-founder of LM Capital Group in San Diego. He said the KKR deal and others like it take seniority over bonds. Even so, “at the end of the day, we all want the company to move forward, keep selling, keep producing and so we bite the bullet.”

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Copyright: Rig Zone