Mexico's Pemex hedges oil output for first time in 11 years

Mexican state-owned oil company Pemex said on Tuesday it has hedged its output through December, the first time it has done so in 11 years, in a bid to protect its balance sheet from a potential drop in oil prices.

Petroleos Mexicanos, as the company is officially known, said the oil hedging program will run from May to December and guarantees a price of $42 per barrel for up to 409,000 barrels per day. It will cost the company $133.5 million.

The Pemex hedge is separate from the much larger oil price hedge undertaken by the finance ministry.

"For the first time in 11 years, Pemex has its own hedging program, which will favor the fulfillment of its operational and investment commitments and provide greater certainty to its income considering a possible drop in oil prices," the firm said in a statement.

Pemex said the hedge will provide protection if the average monthly price of the Mexican oil mix is between $37 and $42 per barrel, adding that if prices fall below $37, Pemex will receive the maximum amount of "contracted protection."

In its latest budget forecast, Mexico's Finance Ministry forecast average Mexican oil prices of $42 per barrel in 2017 and $46 per barrel in 2018.

While the Finance Ministry's hedging program "ensures the oil revenues of the Federal government, Pemex's hedging program protects the company's balance sheet," the company said.

Long used as a cash cow for the nation's government, Pemex now contributes less than a fifth of federal revenue, down from more than a third a few years ago.

The Mexican government is implementing an energy industry revamp finalized in 2014. It ended the decades-long production monopoly enjoyed by Pemex, which has led to the first-ever competitive oil auctions and joint venture partnerships.

http://www.reuters.com/article/us-mexico-pemex-idUSKBN17R2HE

Russia reclaimed its position as China's biggest crude oil supplier in March, customs data showed on Tuesday, displacing Saudi Arabia after two months in second place as Moscow fights to hang on to its slice of the Chinese market.

Russian shipments grew nearly 1 percent to 1.104 million barrels per day (bpd) from the same month a year earlier, as China's private refineries maintained high processing rates and restocked inventories after receiving fresh 2017 import quotas. China's crude imports rose to a record in March, overtaking the United States and shattering expectations.

Saudi shipments were 1.072 million barrels in March, up nearly 15 percent from a year ago, the General Administration of Customs said. For the first three months, Saudi arrivals stood at 1.165 million bpd, making it the top supplier on a quarterly basis.

March's record arrivals came as Saudi Arabia cut April prices of light crude as Europe and the United States ramped out supply to Asia.

The Organization of Petroleum Exporting Countries (OPEC) agreed to curb its output by about 1.2 million bpd from January to support prices. Non-OPEC producers, including Russia, agreed to cut another 600,000 barrels, but both OPEC and non-OPEC countries continued efforts to keep Asian markets vital for growth well supplied.

March also saw the United States ramp up shipments to 45,057 bpd. A year ago, China did not import U.S. crude.

Imports from Iran meanwhile rose 5.97 percent to 626,200 bpd.

http://www.reuters.com/article/us-china-economy-trade-crude-idUSKBN17R0P2

Iraq has launched the third and final phase of work to expand its southern Halfaya oil field, aiming to double its output capacity in 2018 to 400,000 barrels per day, a state-run oil company said.

Additional facilities to separate crude oil from associated natural gas will be set up as part of Halfaya's expansion, Adnan Noshi, head of Maysan Oil Co which oversees oilfields in Maysan province, told Reuters on Tuesday.

Halfaya, operated by PetroChina, is Maysan Oil's largest field, producing 200,000 of the company's total output of 380,000 bpd, Noshi said.

Expansion at Halfaya should raise Maysan's overall output to nearly 600,000 bpd in 2018, he said.

Iraq plans to increase its oil output capacity to 5 million bpd before the end of the year.

Output stood at more than 4.7 million bpd, Oil Minister Jabar al-Luaibi said on April 2.

OPEC's second-largest producer after Saudi Arabia, Iraq produced at a rate of 4.464 million bpd in March, down by more than 300,000 bpd from late last year.

Iraq has reduced its output alongside other oil exporters this year as part of an agreement aimed at boosting crude prices.

http://www.reuters.com/article/us-iraq-oil-halfaya-idUSKBN17R10Q

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Following the sharp decline in Far East Russian crude premiums last month, suppliers of Sokol, Sakhalin Blend and ESPO Blend crude found some respite in recent weeks, as demand from North Asian end-users improved, market participants said on Tuesday.

Regional crude traders indicated that low-sulfur Russian crude feedstock requirements from Asian end-users should increase towards the latter half of the second quarter, as many of the key refineries in the area are expected to wrap up their seasonal maintenance works around that period.

"I think bids were generally stronger for those [Far East Russian crude] cargoes due to load late in June," said a North Asian sweet crude trader.

India's ONGC Videsh Ltd. awarded its tender offering a 700,000-barrel cargo of Sokol crude for loading over June 11-17 to Trafigura at a premium of around $2.15/b to the June average of first-line Dubai and Oman assessments, on a CFR North Asia basis, a company source told S&P Global Platts.

The traded level was higher than OVL's previous tender concluded last month, when the Indian supplier received a premium of around $1.83/b for a similar-sized cargo for loading over May 19-25.

Market talk also indicated that the Japanese consortium Sodeco and ExxonMobil could have each sold a cargo of Sokol crude for loading in June to North Asian refiners at premiums close to $2.5/b to Platts front-month Dubai crude oil assessments on a CFR North Asia basis.

Meanwhile, Sakhalin Energy was said to have sold, via spot tender, 730,000 barrels of Sakhalin Blend crude for loading over June 28-July 4 to a Japanese company at a premium of around $1.40/b to Platts front-month Dubai crude oil assessments, on a CFR North Asia basis, sharply higher than the premium of 10-50 cents/b paid for May and early-June cargoes in the previous trading cycle.

"[Far East Russian sweet crude] premiums fell a lot [last month], so some buyers probably find them cheap now," said a North Asian crude trader.

Last month, price differentials for Sokol and Sakhalin Blend slumped to record lows, according to Platts data. Sokol was assessed as low as at a premium of $1.40/b to the average of first-line Dubai and Oman assessments, on a CFR North Asia basis, on March 21. Sakhalin Blend was assessed at an all-time low of Platts front-month Dubai plus 5 cents/b on March 22.

http://www.platts.com/latest-news/oil/singapore/far-east-russian-crude-oil-premiums-recover-as-26719420

Baker Hughes revenue falls 15 percent on lower offshore spending

Baker Hughes Inc posted a 15 percent slide in revenue, in contrast to rivals Schlumberger and Halliburton Co, as sluggish activity offshore U.S. Gulf Coast dampened gains from increased drilling on the U.S. shale patch.

The oilfield services provider on Tuesday reported a bigger-than-expected loss and said growth in its well construction business onshore North America was more than offset by increased competition for pressure pumping services and reduced customer spending in the Gulf of Mexico.

Spending on capital-intensive and time-consuming offshore projects has remained sluggish at a time when shale producers have ramped up investments to take advantage of oil prices stabilizing at over $50 per barrel.

The company, which is being acquired by General Electric Co  said quarterly revenue fell to $2.26 billion in the first quarter ended March 31 from $2.67 billion.

Analysts' on average had expected revenue of $2.27 billion, according to Thomson Reuters I/B/E/S.

Net loss attributable to Baker Hughes narrowed to $129 million, or 30 cents per share, in the first quarter ended March 31, from $981 million, or $2.22 per share, a year earlier.

According to Thomson Reuters I/B/E/S, the company lost 24 cents per share, on an adjusted basis. Analysts' on average had estimated a loss of 21 cents.

GE said last week the merger of its oil and gas business with Baker Hughes remained on track to close in mid-2017.

http://www.reuters.com/article/us-baker-hughes-results-idUSKBN17R16E

Baker Hughes Inc  said on Tuesday it expects revenue from North America to rise in the current quarter from the first as oil producers drill more onshore wells, helping the oilfield service provider make up for a fall in demand in the Gulf of Mexico.

Oil producers are spending more on lucrative shale fields to take advantage of oil prices stabilizing at over $50 per barrel, while clamping down on expensive and time-consuming offshore projects.

"Activity growth in the U.S. onshore well construction product lines is forecast to more than offset the seasonal decline in Canada and ongoing activity reductions in the Gulf of Mexico," Chief Financial Officer Kimberly Ross said in a post-earnings call.

Baker Hughes is much more exposed than Halliburton to international markets, where activity and pricing for oilfield services has remained persistently low.

About 31 percent of Baker Hughes' total revenue comes from North America, with operations in the Gulf of Mexico account for 15 percent of its revenue from the region.

http://www.reuters.com/article/us-baker-hughes-results-idUSKBN17R16E

As crude prices stabilise and drilling rigs dig into shale plays again, oil field service costs are beginning to rise back up. That could squeeze drillers’ margins later this year.

Energy research firm Wood Mackenzie believes oil field service costs could jump 15 percent this year overall, with prices for some equipment and services possibly rising as high as 40 percent, it said in a recent report.

Though oil field service companies aren’t likely to charge the same prices they got in 2014, before oil prices collapsed, they will probably get back market pricing power, Wood Mackenzie said.

Oil explorers all “voice the best intentions to keep a laser eye on costs,” said Jackson Sandeen, senior research analyst at Wood Mackenzie. “But continued productivity and drilling efficiency gains over 2016 will be difficult to achieve as operators pivot to a more aggressive development mode.”

The firm estimates U.S. oil companies will hike spending 60 percent this year on average, but drillers expect service prices to rise on average 10 percent to 20 percent, even though service companies forecast 15 percent to 40 percent price increases this year.

Oil fields in which companies can pump crude profitably below $40 a barrel will still turn a profit even with service cost inflation. But the more active oil plays in West Texas will likely see the biggest increases in oil field service prices, Wood Mackenzie said.

“Many difficult contract negotiations will be had in the coming months as operators look to honor growth targets shared with investors at the start of the year,” Sandeen said. “It is clear that service sector margin recapture will be a key feature in 2017 as the industry turns the corner on activity.”

http://fuelfix.com/blog/2017/04/24/oil-service-costs-could-rise-15-percent-this-year-wood-mac-says/

The American Petroleum Institute (API) reported a build of 897,000 barrels in United States crude oil inventories, compared to analyst expectations that markets would see a bit of relief with a crude oil draw of 1.6 million barrels.

The API’s report on gasoline inventories—a 4.4-million-barrel build, hit markets even harder, which follows a blow last week when the markets were shocked when gasoline inventories saw a build of 1.374 million barrels, while analysts were expecting a 2.2-million-barrel draw for the fuel instead.

Last week, the API reported a 840,000-barrel draw for crude oil inventories for week ending April 7, while the EIA reported a 1-million-barrel draw.

While the API and EIA crude oil inventory reports seldom match barrel-for-barrel, and sometimes even contradict each other on a significant level in any given week, the trendlines of the builds or draws since the beginning of 2017 tell roughly the same picture

http://oilprice.com/Latest-Energy-News/World-News/Oil-Markets-Whipsawed-As-API-Reports-Crude-Unexpected-Build.html

The Department of Energy has granted an approval for Qatar Petroleum’s Golden Pass project to export liquefied natural gas (LNG) to countries that do not have a free trade agreement with the United States.

Golden Pass has been authorized to export LNG up to the equivalent of 2.21 billion cubic feet per day (Bcf/d) of natural gas from the Golden Pass terminal near Sabine Pass, in Texas.

The Golden Pass joint venture, owned by Qatar Petroleum (70 percent) and ExxonMobil (30 percent) proposed to build and operate three liquefaction trains with a total production capacity sufficient to produce 15.6 million tons per annum at the at the existing import terminal onshore at the Sabine-Neches waterway, on the existing Port Arthur ship channel.

The permit has been granted for a period of 20 years, as DOE determined these exports are “not inconsistent with the public interest.”

With the increase in domestic natural gas production, the United States is transitioning to become a net exporter of natural gas. The Department of Energy has authorized a total of 19.2 Bcf/d of natural gas exports to non-FTA countries from planned facilities in Texas, Louisiana, Florida, Georgia, and Maryland.

Commenting on the approval, U.S. secretary of energy Rick Perry said it is the part of the Trump administration’s effort to make the US an energy force and boost to the country’s economy while providing energy security to other countries.

http://www.lngworldnews.com/us-approves-golden-pass-lng-exports-to-non-fta-nations/

Coming off a two-year period of belt-tightening the first-quarter earnings of some North American exploration-and-production companies are expected to reflect the first signs of new gas production growth, but that growth is conditional upon the basins where the producer operates and the individual company's economic circumstances going into the quarter.

In addition, the quarterly results are apt to show a continuation of the trend of producers increasingly focusing on basins with better economic returns -- chiefly oilier and more liquids-rich plays -- while downplaying efforts in the drier gas basins.

US drilling activity has been on the upswing, particularly in the Permian Basin of West Texas and southeastern New Mexico, the hottest oil and gas play in the country.

Producers in recent months have flocked to the Permian, which boasts some of the highest initial production (IP) rates for oil and gas of any basin in the country. The Permian hovers around a 30-day average oil IP rate of 600 b/d, and for the gas the IP rate is closer to 1,400 Mcf/d, according to Platts Analytics.

Crude-focused producers such as Anadarko Petroleum are expected to post strong Q1 results as a result of investments in the oil-rich Permian as well as the DJ Basin of Colorado, another oily province.

Anadarko said last month it expected a 25% increase in oil sales volumes over the prior year.

Meanwhile, some gas producers could see production growth in the quarter as well. Appalachian producers operating in the liquids-rich portions of the basin -- chiefly the southwestern Marcellus and Utica plays -- are largely expected to increase drilling and production in the quarter compared with the same period last year.

Consol Energy recently said it expects to double its capital expenditures in full-year 2017 to an estimated $555 million, versus $205 million last year, while it expects to increase its production by about 5% to 1.14 Bcfe/d in 2017 compared with actual production of 1.08 Bcf/d in 2016.

Appalachian producer Range Resources also provided guidance that it would increase its capital expenditures to $1.150 billion versus $513 million in 2016, while the producer estimated it would increase its production for full-year 2017 to 2.07 Bcfe/d versus 1.54 Bcfe/d in 2016.

To drill a well in the Marcellus costs around $6 million with a gas IP rate of 10,000 Mcf/d, according to Platts Analytics. Producers drilling in the Utica Shale in eastern Ohio have mentioned gas IP rates around 20,000 Mcf/d with a well cost around $10.6 million.

Chesapeake Energy, which operates in a number of basins across the country, is expected to drill and produce less oil and gas than last year, largely as a result of the sale of some of its non-core assets, such as the Barnett Shale of North Texas last year, according to its most recent guidance.

The producer will operate fewer rigs and drill fewer wells in 2017 than it did last year. The company said in February it plans to operate an average of 16-18 rigs in 2017, compared with 28 in 2016, and complete 420-480 gross wells, compared with 547 last year.

For Q1, the company expects production of 515,000-535,000 b/d of oil equivalent, of which oil production is expected at 80,000-85,000 b/d, which is consistent with prior guidance, Chesapeake said.

Meanwhile, other producers, such as Gulfport Energy, have already posted positive results by pursuing a diversified basin strategy.

Earlier this month the producer reported that Q1 production of 850 MMcf/d came in above expectations, "driven by the continued strong performance of our Utica Shale assets."

In addition, the producer said in the quarter it closed on the acquisition of assets in the SCOOP play of central Oklahoma from Vitruvian II Woodford, and since the closing in mid-February has been running four operated rigs on the acreage.

Among other trends expected to surface in the E&P companies' quarterly reports are an increase in the cost of drilling services, particularly the percentage of drilling costs that go toward the purchase of fracking sands.

As producers drill ever-longer laterals and pump greater volumes of proppants, the cost of the sand is expected to increase, taking up a larger portion of producers' drilling budgets.

http://www.platts.com/latest-news/natural-gas/houston/north-american-eampps-seen-likely-to-post-modest-26719500

U.S. refiners have become a powerhouse of distillate exports, causing the supply-demand balance for fuels from the middle of the barrel to tighten in the United States despite a very warm winter.

Exports of distillate fuel oil rose to a record 1.4 million barrels per day (bpd) in the week ending April 14, according to the U.S. Energy Information Administration.

So far this year, exports have averaged almost 1.1 million bpd, during what is normally a seasonal lull, and will likely accelerate over the summer months.

The result is that U.S. stocks of distillates, such as home heating fuel and diesel fuel, have emerged from the end of winter looking somewhat tight despite heavy levels of refinery processing.

Distillate stocks stood at 148 million barrels on April 14, which was 19 million barrels above the 10-year average but 13 million barrels below the level at the corresponding point in 2016.

Stocks have been tightening against both the prior-year level and the 10-year average since the start of February and only high levels of refinery processing have kept them from drawing down even further.

Even so, stocks have fallen by almost 15 million barrels since the start of 2017 compared with an average decline of about 10 million barrels and a build of more than 2 million barrels in 2016.

Stocks have fallen even though heating demand has been 2 percent lower than in 2016 and 17 percent below the long-term average because of the unusually mild weather across the country this winter.

Most distillate is being exported to Mexico, Brazil and other countries in Latin America and the Caribbean, where ageing local refineries are struggling to keep up with growing demand.

Smaller volumes have also been shipped to markets in Europe, according to U.S. customs data analysed by the EIA.

Exports are set to remain strong given the chronic shortage of distillate refining capacity across Central and South America.

But U.S. domestic distillate consumption is also forecast to rise again in 2017 after falling significantly in 2016 and 2015 which will tighten the supply-demand balance even further.

EIA forecasts that domestic consumption will rise by 70,000 bpd in 2017 and another 120,000 bpd in 2018 (“Short-Term Energy Outlook”, EIA, April 2017).

Hedge funds and other money managers have responded by building one of the largest bullish positions in distillate since crude oil prices crashed in the middle of 2014.

Hedge funds have accumulated a net long position in New York No.2 heating oil futures and options contracts equivalent to 34 million barrels, according to an analysis of regulatory data (tmsnrt.rs/2oGlPoE).

Fund managers hold almost 3.6 long contracts betting on a further increase in prices for every short contract betting on a decline, up from a ratio of 1.6:1 at the same point last year (tmsnrt.rs/2oGy7xb).

Distillate prices remain buoyant and refining margins are the highest for the time of year since 2015, increasing the incentive to process as much crude as possible.

http://www.reuters.com/article/usa-distillates-kemp-idUSL8N1HX4ZD

Valero Energy Corp Chairman and Chief Executive Joe Gorder said he expects costs for renewable fuel credits to drag on the company's returns in the second quarter of 2017.

"While RIN (Renewable Identification Number) prices have declined relative to 2016, there is still a significant headwind for the quarter," Gorder said in a conference call to discuss first quarter earnings. "At this level, RINs expense remain an issue for us, so we continue to work with regulators."

Valero's costs for biofuel blending were $146 million in the first quarter of 2017, $15 billion below blending costs in the same period of 2016.

During the conference call, Gary Simmons, Valero's senior vice president of international operations and system optimization, said the company was not ready to revise its forecast for RINs for 2017.

"We're not really ready to revise our guidance at this time," Simmons said. "We're going to keep our guidance where it is. And we'll just see how successful we are on some of these things about moving the point of obligation and what happens to RINs."

The company has said it expects to spend an amount similar to the $749 million spent in 2016 to meet the federal renewable fuel requirements.

Refiners trade RINs to comply with federal law requiring transportation fuels sold in the United States contain minimum amounts of renewable fuels.

D6 RINs traded on Monday between 47 cents and 49 cents a piece.

Valero is part of a lobbying effort to change the point of obligation where renewable fuels are blended into motor fuels from the refinery to the distributor's terminal.

http://www.reuters.com/article/refineries-valero-rins-idUSL1N1HX0S1