Exxon Mobil Corp. agreed to buy natural gas explorer InterOil Corp. for as much as $3.6 billion to acquire discoveries in Papua New Guinea that will feed the buyer’s existing gas-export plant.
Exxon will use its own stock to pay between $45 and $71.87 per share of InterOil, depending on how much gas InterOil’s Elk-Antelope field holds, Irving, Texas-based Exxon said in a statement on Thursday. With the range of potential payouts valuing the agreement at $2.5 billion to $3.6 billion, it represents Exxon’s biggest acquisition in almost four years.
The world’s largest energy producer by market value also agreed to pay a $60 million breakup fee on behalf of InterOil, which backed out of an earlier deal to sell itself to Oil Search Ltd. and Total SA for $2.2 billion.
Exxon said it plans to chill, liquefy and export the gas from the Elk-Antelope field in its PNG LNG complex on the coast of the South Pacific nation. Exxon’s statement made no mention of InterOil’s original plan to build a separate LNG facility known as Papua LNG from scratch. Exxon’s PNG LNG plant cost $19 billion to build and began exporting the fuel in 2014.
“Exxon Mobil will work with co-venturers and the government to evaluate processing of gas from the Elk-Antelope field by expanding the PNG LNG project,” the company said. “This would take advantage of synergies offered by expansion of an existing project to realize time and cost reductions that would benefit the PNG Treasury, the government’s holding in Oil Search, other shareholders and landowners.”
On July 20, 2016, the Mexican National Hydrocarbons Commission (CNH) published the drafts of the Bidding Terms and Production Sharing Contracts (PSC) for Round 2, Phase 1, for the Exploration and Extraction of Hydrocarbons in Shallow Waters. Below is a summary of the most important terms and conditions of the drafts of the bidding terms and the PSC.
Shallow Water Blocks
The CNH will bid 15 shallow water blocks, 4 of which are located in the Tampico-Misantla oil province, 1 in Veracruz and 10 in Cuencas del Sureste oil province.
Bidding Terms
-
Interested oil companies may participate in the bid of the 15 blocks, as individual bidders or in consortium.
-
Interested parties and bidders should not be in contact with any official from the CNH or the government that is in any manner related to the Round 2 bids, as bidding terms and contracts should not be subject to negotiation. However, any interested party should be able to make comments related to the bidding terms and contracts through the CNH’s webpage.
-
All stages of the bidding process will take place in Spanish, unless there is a specific provision that states the contrary.
-
Bidding and contract terms, excluding prequalification requirements, might be subject to change at any point in time before their final publication.
-
The bidding process will occur in the following stages: i) publication of bidding terms, ii) access to data rooms, iii) registration, iv) clarifications to the bidding terms, iv) prequalification, v) filing of proposals, vi) awarding of contracts and vii) execution of contracts.
-
The following payments will apply:
Registry fee – $750,000 MXP.
To have access to the data rooms – Information worth at least $8,000,000 MXP.
-
Bidding day is set for March 22, 2017. The chart below illustrates the timeline for the bidding process:
-
To prequalify for the bidding process companies have to demonstrate, among others, the following:
-
Legal origin of funds.
-
Organization Chart
-
Information regarding companies that have control of the company.
-
In case of SPVs, their corporate and business structure must be detailed, indicating who has significant control or influence. Also Tax Returns and Audited Financial Statements of those that incorporated the SPV, corresponding to the last 2 years, should be filed.
-
Some of the requirements will be waived for those that successfully prequalified to Round 1, Phases 1, 2 and 4, as long as they are still the same members of the successfully prequalified bidder in the past phases.
-
Technical requirements are as follows:
Experience as an operator in projects from 2011 to 2015 through (i) the participation in at least three projects of exploration and/or extraction of hydrocarbons, or (ii) capital investments in exploration and/or extraction projects that together amount at least USD $1 billion. . It is not required that the interested company participated as an operator in these projects.
2.Experience as (i) an operator in at least one project of exploration and/or extraction of hydrocarbons in shallow waters and/or deep water or (ii) having participated as partner in at least two projects of exploration and/or extraction of hydrocarbons in shallow waters and/or deep waters in the last 5 years.
3.Experience in industrial and environmental, health and safety programs during the last five years in exploration and/or extraction projects in shallow waters and/or deep wat
-
As for the financial requirements, the operator shall demonstrate economic capacity, meaning the contractor owns assets of at least USD $10 billion and have an investment credit rating or has shareholder’s equity of at least USD $1 billion. If the operator does not meet the above mentioned financial criteria on a stand-alone basis, the operator could participate in a Consortium demonstrating a shareholder’s equity of USD 600,000,000, as long as the other members of the Consortium demonstrate an aggregate shareholders’ equity of USD 400,000,000.
-
Bidders will be able to participate as an individual bidder and/ or as part of one or more consortiums, however, the one bidder cannot participate in more than four consortiums. Proposals are limited to one per contractual area. There are no restrictions for any company to partner with major oil companies, international oil companies or national oil companies, including Pemex.
-
The weighted average of the offer or biding factor to determine the winner will be calculated considering the value of the Participation of the State in the Operating Profit, and the additional investment factor related to the minimum work program, according to the formula provided in the bidding terms.
-
The additional investment factor is related to the additional investment commitment during the exploration period. The variable corresponding to the investment factor could be 1.5 in case of making an additional investment commitment of working units equivalent to two exploratory wells, 1 in case of committing to working units equivalent to 1 exploratory well and 0 if no additional investment commitment is made.
-
Minimum values to be accepted will be determined by Hacienda before the CNH publishes the final version of the bidding terms and contracts, and at that point Hacienda will also define when such values will be public.
-
A USD $500,000 letter of credit should be submitted as bid bond for each offer.
-
Contracts will be awarded on March 24, 2017 and should be executed within 90 days after they are awarded.
Production Sharing Contracts for the Exploration and Extraction of Hydrocarbons in Shallow Waters
-
Production Sharing Contracts will be applicable. Contractors will perform Oil and Gas activities under the PSC, within the contractual area, at their own cost and risk, in exchange of a consideration from the State.
-
The term of the Contracts will be 30 years. The term may be extended for 2 more periods of 5 years each.
-
Contracts include an initial transition phase of up to 120 days. In such period the Contractors must document the status and integrity of the fields and equipment and initiate a social impact and environmental study to establish the base line.
-
Contracts include an initial exploration period of up to 4 years. In such period
-
Contractors will be obliged to finish the minimum work program. The exploration period may be extended for an additional period of 2 years (conditions apply). This additional period could be extended if for causes non attributable to the contractor he is not able to finish the corresponding activities.
-
Contractors will have to file an exploration plan for approval within 120 following the execution date of the contract. CNH will have 120 days to approve it. If the plan is not filed within the established term, a late fee USD 10,000 per day will apply The exploration plan may be adjusted subject to CNH’s approval.
-
Contractors shall file a performance guarantee to cover their obligations related to the minimum work program. The amount of said guarantee will be the result of multiplying the reference value of the work unit by 75% of the work units corresponding to the minimum work program and its increase, or by the number of working units corresponding to the increase of the minimum work program not performed in the initial exploration period and the additional commitment for the additional exploration period.
-
Contractors will have to inform the CNH in case of a discovery within the subsequent 30 days the discovery is confirmed. Once that the Contractors notify the CNH, they will have 60 days to file the appraisal plan.
-
The appraisal plan will have duration of up to 12 months, that could be extended for another 12 months when technical or commercial conditions require it, subject to CNH previous approval.
-
The appraisal plan in case of a nonassociated Natural Gas discovery will have last of up to 24 months that could be extended for 12 additional months when technical or commercial conditions require it, subject to CNH previous approval.
-
Within 60 days after the ending of any appraisal period, contractors will have to inform if the discovery is a “commercial discovery”.
-
Within 1 year after the confirmation of a commercial discovery contractors will have to file the corresponding development plan which shall be approved within 120 days Provisions related to the relinquishment of areas and unifications are included. These provisions will not be understood as a decrease in the Contractor’s obligations to comply with work commitments for the exploration period or its obligations regarding relinquishment activities and other activities set down in the Contract.
-
Contractors will have to keep an Operating Account where transactions related to the contract should be recorded. Additionally, contractors will have the obligation to file budgets of the costs to be incurred during the implementation of each work program and shall comply with the requirements set forth in the PSC.
-
Items included or excluded in the cost recovery and the applicable procedure are properly described in annex 4.
-
Costs resulting from the exploration and production activities will be considered as recoverable costs as long as they comply with the applicable legislation and the guidelines established by Hacienda.
Among the non-eligible and hence, non-recoverable costs established in the PSC, are the following: i)those not included in the budgets and work programs approved by the CNH or those in excess of the costs that were established in the budget elevate it in more than 5% or elevate the budget contemplated for the activity pursuant to the account catalogue over 10%, ii) financial costs, iii)donations, iv)costs for servitudes, rights of way and lease or acquisition of land, v) overhead expenses and vi) arbitration and dispute resolution costs, among others.
Overhead expenses related to services received or activities carried out outside the Mexican territory will be recoverable up to a 1.5% of the authorized budget.
-
The volume of hydrocarbons will be measured at the measurement point which may be inside or outside the blocks. Simultaneous to the filing of the development plan, contractors will have to propose the procedures to store, measure and monitor the quality of the hydrocarbons.
-
Assets generated or acquired by the contractors to carry out the exploration and extraction activities should be transferred to the Government when the contract is terminated. Movable assets, lease assets or assets owned by subcontractors are exempted from the transfer to the extent the transactions were not carried out with related parties.
-
Contractors will be able to commercialize the production by themselves or through third parties.
-
Government take will include the i) Contractual quota for exploration phase, ii) royalties and iii) the percentage of the operating profit that will be adjusted according to an R-factor included in the Contracts.
-
The amounts corresponding to royalties will be determined pursuant to the formulas and values established in the Hydrocarbon Revenue Law (HRL) and will depend on the type of hydrocarbon.
-
The PSC includes a sliding scale system based on IRR (before tax) with an initial benchmark of 25% that starts decreasing the Contractor share until the IRR reaches a benchmark of 40%, leaving a final Contractor share to 25% of the bid value. For computing the IRR, the PSC allows the Contractor to recognize four times its costs linked to the minimum work program and to the increase of the minimum work program.
-
The consideration for the contractor will include i) cost recovery and ii) remaining percentage of the operating profit.
-
The percentage of cost recovery will be 60%. However, if in the contractual area only non-associated natural gas discoveries are made, the percentage will be 80%.In addition, for the determination of the recoverable costs, the eligible costs established in the minimum work program and its increase will be recognized at an additional 25% value.
-
The Contracts include provisions to determine the value of hydrocarbons similar to the ones included in prior rounds.
-
Decommissioning provisions are included. Contractors will have to incorporate an abandonment fund once the development plan is approved. The contractor shall deposit ¼ of the annual amount at the end of each quarter.
-
Local content obligations are included: 15% during the exploration period; 17% during appraisal period and for the development period the percentage will start at 26% and will increase yearly until it reaches 35% in 2025.
-
Contractors shall have insurance policies that cover civil liability, well control and damage to the materials generated or acquired during the exploration and production activities.
Administrative and contractual rescission clauses are included in the Contracts as well as provision related to dispute resolution mechanisms under ICC rules as in prior rounds.
Exxon Mobil Corp. is doubling down on Papua New Guinea, topping a rival offer for InterOil Corp., a gas explorer focused on the Southeast Asian nation.
The energy giant’s offer values InterOil at $2.5 billion, including debt, beating an earlier bid from Oil Search Ltd. and Total SA. Exxon already runs Papua New Guinea’s only liquefied natural gas terminal and buying InterOil, which has gas fields and a stake in a second gas export project in the country, would give it a new source of the fuel for its exports. Oil Search and Total have three days to decide whether to counter Exxon’s offer.
“This was widely expected by the market and looks at first glance to be in line with our estimates that Exxon’s bid would be 10 percent higher than the original Oil Search bid,” said Neil Beveridge, an analyst at Sanford C. Bernstein in Hong Kong. “The key question now is whether we see a counter-bid from Total and Oil Search.”
InterOil said Exxon is offering it a fixed price of $45 per share, and values the company at $2.5 billion, including $188 billion in net debt. As part of Oil Search’s $2.2 billion bid with Total in May, it offered 8.05 shares for each of InterOil’s, valuing InterOil’s share at $40.25.
The bid from Exxon also includes a higher initial so-called contingent-value right, offering $7.07 per share for each trillion cubic feet of likely gas reserves above 6.2 trillion found in InterOil’s Elk-Antelope fields, capped at 10 trillion cubic feet. Oil Search offered an additional $6.05 per share for each trillion cubic feet more than 6.2 trillion, with no cap.
Oil Search said in a statement it’s talking with Total about its options and that it’s entitled to a $60 million break-up fee, with 20 percent going to Total, if the deal doesn’t go through after InterOil changed its recommendation.
“InterOil has advised that it intends to make a change in its recommendation and enter into an Arrangement Agreement with ExxonMobil,” Oil Search said in a statement.
Exxon is targeting gas fields that hold enough reserves to supply the U.K. for three years. The company already operates the existing $19 billion PNG LNG gas-liquefaction plant in Papua New Guinea. InterOil and its partners have planned the nation’s second export project, Papua LNG. Oil Search is a shareholder in both ventures and has encouraged a tie-up to lower development costs.
Lower Cost
“ExxonMobil has submitted an offer to acquire InterOil Corporation, which we believe represents a superior proposal,” Exxon said in a statement.
Oil Search rose as much as 4.2% to A$7.27 in Sydney before trading at A$7.22 at 3:43 p.m. local time.
Papua New Guinea has lower costs than rival LNG sources, making it a more-attractive place to invest in an oversupplied market for the seaborne fuel. A deal for InterOil could speed up a boom in fuel sales from the nation, which began exporting LNG in 2014.
InterOil’s gas fields are closer to the coastal site of its proposed LNG plant and the pipeline that would feed it cuts through a less densely populated region than Exxon’s, which pipes its supply down from the country’s highlands, according to a presentation published on InterOil’s website.
Project Partners
“PNG’s lower costs are largely driven by the downstream. The cost of constructing the LNG facility is lower because labor is cheaper and site preparation is easier,” Matt Howell, a Perth, Australia-based research analyst for energy consultant Wood Mackenzie Ltd., said by e-mail. “In the case of Elk-Antelope, the fields are also nearer to the LNG facilities and the conditions in that area are a lot kinder, which lowers midstream and upstream costs.”
Oil Search is already a partner in both Exxon’s PNG LNG venture as well as Papua LNG. The Oil Search deal may save the country’s two projects as much as $3 billion and speed up development if they cooperate, according to Managing Director Peter Botten. After buying InterOil, Oil Search planned to sell 60 percent of the assets to Total.
InterOil’s appraisal of the fields found 10.2 trillion cubic feet of likely reserves at the end of 2015. Oil Search released results Friday of a separate analysis of those fields that estimated likely reserves at 6.4 trillion cubic feet. Oil Search said it would do a different analysis if it were to purchase InterOil that would include gas condensate volumes and another appraisal well that could unlock an additional 1 trillion to 2 trillion cubic feet of gas.
Exxon has pursued InterOil’s assets in the past. In May 2013, the energy explorer entered into exclusive talks to acquire a stake in InterOil’s Papua New Guinea discoveries, estimated at the time to hold the equivalent of 9 trillion cubic feet of recoverable gas. The talks collapsed later that year for undisclosed reasons.
Oil and gas companies are continuing to invest in safety research despite the current oil price downturn, DNV GL representatives told Rigzone during a recent trip to the firm’s Spadeadam testing and research facility in Cumbria, England.
“Business is tough in the oil and gas sector but committed customers are still investing in safety improvement. They’re still conducting research into major hazards,” said Gary Tomlin, DNV GL UK’s vice president of safety and risk.
Naturally, the level of this investment was slightly hampered by the drop in crude prices, but investment has started to increase over the last couple of months.
“We saw a hiccup and to be honest, it’s inevitable. When the oil price drops from $110 a barrel to $27, you’re kidding yourself if you’re not going to see a hiccup,” said Hari Vamadevan, DNV GL – Oil & Gas’ regional manager for the UK and West Africa.
“We’ve seen a pickup I would say over the last couple of months … oil recovery to $50 has helped a little bit, I think there’s positive cash flows for some companies, but many companies haven’t stopped [investing],” he added.
Investment in this type of research is expected to rise even further over the not too distant future, as the oil price achieves an anticipated rise and oil and gas firms gain more access to expendable income.
From an industry perspective we think … we’ll see an upturn 2017-2018,” said Tomlin. “I think that we’ve plateaued. We are a cyclical oil and gas industry … I think we’ve hit the low point, but we do need to be aware that we still need to control costs,” said Vamadevan. “I think companies will become profitable at $50 and $60 per barrel, and as the price rises I think there will be more investment. So I am hopeful that we will see more activity going forward,” he added.
Oil, Gas Safety Testing ‘Critically Important’
Oil and gas major hazards testing and research was described as critically important by Tomlin, who outlined the significance of Spadeadam for the hydrocarbon sector.
“It’s a unique facility worldwide. There are other facilities like this, but none that do the breadth of the work we do, so it’s something we’re incredibly proud of. The work we do here is of critical importance,” said Tomlin.
DNV GL Spadeadam Testing and Research is designed to carry out full-scale hazardous trials and simulate real-world environments. Situated in 120 acres (50 hectares) of Ministry of Defence land in the north of England, it offers the opportunity to test equipment, components, products, techniques and processes, and to provide data to validate computer models.
aff at Spadeadam have recreated a number of major accidents at their facility – ranging from the Piper Alpha platform explosion to the Buncefield oil storage terminal fire – to find out exactly what went wrong and help prevent future incidents in the oil and gas industry.
“We’re undertaking research here that helps … [oil and gas companies] understand hazards that they manage in their facilities, so that they can take measures to limit the risk to their people and their infrastructure,” said Tomlin. “We get people to experience large scale fires and explosions so that they can see and feel the power of these events. They can’t get that anywhere else in the world.”
Most safety lessons in the oil and gas sector come from real world events, said Vamadevan, who highlighted how experiences of this nature can be more useful than theoretical work.
“If you … felt a jet fire, you experience what happens in an explosion, it means you understand it much better than reading in a textbook, seeing a colour contour on a map or seeing a percentage,” Vamadevan told Rigzone.
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.”
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.”
GRACIELA ÁLVAREZ HOTH
CEO of NRGI Broker
The country is developing in a new direction, so it only makes sense for companies to align themselves with this new phase. This was exactly the motivation behind Grupo Vitesse’s decision to create a specialized Energy Insurance Broker “NRGI Broker.” With over 25 years of acquired experience from PEMEX’s marine operations, the company has now chosen to reinvent itself in line with the new trends in onshore production and gas pipelines. The experience present in NRGI Broker dates back to the days when Cantarell was booming and the company has contributed in an active way by attracting international market leaders to the country.
The importance of a guide to help companies comply with the new Mexican procedures implemented by the Energy Reform is often overlooked, according to Graciela Álvarez Hoth, the company’s CEO. She explains that, before the reforms, PEMEX provided its contractors with wide coverages, so their only concern was the deductible, and as a result, clients became accustomed to the buffer that PEMEX represented. “Now, most of the companies are no longer contractors and have become operators, and naturally they need a broader experience in negotiating administrative hurdles with the authorities,” Álvarez explains.
NRGI Broker takes a proactive approach to the new regulations, allocating time to dialogues with risk managers to discuss the new market rules that will be launched, even if these have not yet been released. “Over the past year we have closely worked with the regulatory agencies in order to participate in the processes of issuing regulations that are new to the country,” Álvarez Hoth asserts. By becoming part of this group, she is confident that NRGI Broker can provide clients with integral and adequate solutions. “In this way, we can inform the regulators of global trends, and analyze how we can apply this information to Mexican laws and norms,” she suggests.
Accidents are unavoidable, but despite the fact that this constitutes a core part of NRGI Broker’s business, the company takes measures to mitigate risks. “When the insurance sector works with the regulatory agency as
a team, everyone’s experiences are enriched because every participant has something to offer,” expresses Álvarez Hoth. Guidelines are currently being established that will require operators to conform to certain security regulations involving studies that have to be carried out before initiating production, with the objective of ensuring production is as safe as possible.
“Due to the low oil price, the insurance sector is working in a soft market where there is plenty of capacity and few players due to companies that are unwilling to lose money having shut down their activities, which has generated an appetite and a surplus that has not been seen in the last 15 years,” Álvarez Hoth continues. This will allow new operators in Mexico access to a wide variety of coverage at extremely competitive prices.
Providing insurance for new deepwater projects will not be without its challenges, assures Álvarez Hoth, but she does not expect these to overwhelm NRGI Broker. “At the end of the day, insurance companies are more worried about onshore platforms than offshore platforms because onshore activity in Mexican territory entails various factors that can affect operations,” she points out. Dealing with social aspects is difficult and the onshore segment will require a gradual learning process because operations will vary greatly across regions. On the other hand, offshore operations are identical all over the world, and although some regions like the North Sea present higher risks due to the tides. From this perspective, the Gulf of Mexico presents relatively low risks. Deepwater operations are relatively expensive but the players are also bigger, and Álvarez Hoth predicts that companies like Shell and Exxon will enter the market when it makes sense for them from a financial perspective. “These operators will enter with international sophistication and experience from working in places with varying levels of infrastructure,” according to Álvarez Hoth. “The goal is to keep track of the country’s obstacles while keeping in mind that these types of situations have already been encountered in other parts of the world.”
Due to NRGI Broker’s breadth of experience in helping companies enter new markets, Álvarez Hoth believes that the company is uniquely positioned to welcome new players that will be attracted by the Energy Reforms. “NRGI Broker can offer these players an advisor that can speak their language and that deeply understand the country, including its laws and regulations in insurance and surety topics,” she argues.
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.”
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.
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:
-
Glossary of defined terms.
-
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.
-
Guidelines for registering oil and gas wells and reservoirs/fields.
-
Guidelines for well-permitting applications.
-
Guidelines for ensuring well integrity (e.g., casing and cementing requirements and standards).
-
Format to request administrative registration of wells.
-
Format to apply for drilling and completion well permits.
-
Format for applications to modify previously granted well permits.
Scroll to top
Fundamental factors to strengthen Pemex12 August, 2019
Offshore Project Development: The Road to First Oil26 July, 2019
