Saudi Arabia was said to cut February crude sales to China and southern Asian nations while largely sparing countries including Japan and South Korea, as it curbs supply as part of a deal between OPEC and other producers.

Two Southeast Asian refiners received cuts of about 30 percent from the world’s biggest crude exporter, according to two people with knowledge of the matter who asked not to be identified because the information is confidential. Reductions to a buyer in India were about 20 percent, one of the people said.

Overall term supplies to Asia for next month declined between 5 and 10 percent, according to one of the people. The reductions will primarily be focused on the medium and heavy oil varieties as the producer concentrates more on sales of lighter grades to stay in the battle for market share against U.S. and African rivals.

Saudi Arabia is trying to implement its portion of promised reductions under a deal between global producers, the success of which will determine if a recovery in benchmark prices is sustainable. The Dec. 10 agreement between the Organization of Petroleum Exporting Countries and 11 others including Russia is aimed at ending a glut that’s battered crude and the economies of producing nations worldwide. Kuwait said on Monday that OPEC and its partners will fulfill their pledged cuts.

State-run Saudi Arabian Oil Co. curbed supply to some oil majors by about 18 percent for February, one of the people said. The company, known as Saudi Aramco, gave at least one Chinese processor lower contractual volumes for next month, said two refinery officials who asked not to be identified because the information is private.

But at least eight buyers in Japan, South Korea and Taiwan received full supply for next month, according to officials at the refineries who asked not to be identified because the information is confidential. Some heavier crude was replaced with a lighter grade for one of the processors in Northeast Asia which got all of the overall volume it requested.

Aramco’s press office didn’t immediately respond to an e-mail seeking comment.

Aramco was said to be planning cutbacks to Asia, its most valued market, for next month that would be relatively smaller than to other regions such as the U.S. and Europe. For January sales, supply to parts of Southeast Asia and South Asia including India was curbed while buyers in North Asia were largely spared. The reductions this month in Asia were also said to be relatively smaller than to other parts of the world.

The Asia Pacific region will use 33.87 million barrels a day of oil in 2017, accounting for more than a third of global consumption, data from the International Energy Agency show. That’s an increase from estimated demand of 33.03 million barrels a day in 2016. In the Americas and Europe, oil use is seen staying flat this year, according to the Paris-based IEA.

https://www.bloomberg.com/news/articles/2017-01-11/saudis-said-to-curb-oil-to-china-southern-asia-as-others-spared

 China's total refining capacity will increase 4.6 percent to 790 million tonnes in 2017 and net crude oil imports will rise 5.3 percent to 396 million tonnes, state-owned China National Petroleum Corporation (CNPC) forecast on Thursday.

In an annual report released by CNPC's research institute, it forecast net exports of diesel will grow 55 percent to 22.41 million tonnes.

http://www.reuters.com/article/china-oil-cnpc-idUSB9N1EN02K

European and Chinese traders are shipping a record 22 million barrels of crude from the North Sea and Azerbaijan to Asia this month, seeking to plug any supply gap left by OPEC production cuts.

Over 11 million barrels of North Sea Forties crude have either been offloaded or are on their way to Asia, adding to a record 11 million barrels of Azeri crude oil from Azerbaijan, Reuters oil trade flows data showed.

The record export volumes come on expectations of tighter Middle East crude supplies due to plans by the Organization of the Petroleum Exporting Countries (OPEC) to cut production in an attempt to prop up prices.

Seeing an opportunity to sell North Sea oil profitably in arbitrage deals to Asia, seven supertankers chartered by commodity traders Vitol and Mercuria, European oil major Royal Dutch Shell, and China's refiner Unipec, have either delivered or are expected to soon offload European crude to China and South Korea this month, according to trade sources and Reuters data.

"Asia needs the oil, Europe has it. The OPEC cut has raised prices, and that now makes it profitable to send European oil to Asia," said one senior trader with knowledge of the deals on condition of anonymity as he is not allowed to talk to media.

December's OPEC deal, in which the group agreed to cut production by 1.2 million barrels per day (bpd) in the first half of 2017, pushed up benchmark price Dubai against Brent and West Texas Intermediate, allowing Asia to pull more competitively priced supplies from the Atlantic Basin.

An ongoing Brent contango, a market structure where oil becomes more expensive in future months, also enabled traders to lock in profits for crude on long voyages.

Shipping North Sea Forties crude from its load port Hound Point in Britain to customers in North Asia, including Japan, South Korea and China, takes over six weeks.

BATTLE FOR ASIA

The deals highlight the predicament facing OPEC and other producers that have agreed to cuts, including Russia and Oman.

While cutting supplies may temporarily lift prices, this gives other producers like western oil firms an opportunity to fill the gap and sell oil to Asia, the world's biggest demand region.

"The real market battleground is East of Suez," said John Driscoll, director of Singapore-based energy consultancy JTD Energy Services, referring to the Suez Canal through which many tankers ship oil between Europe, the Middle East, and Asia.

The ships now carrying European oil to Asia have 11 million barrels of Forties crude loaded, beating a previous record of 10 million barrels in December 2015, Thomson Reuters Eikon trade flow data showed.

And more oil is to come. Two more Very Large Crude Carrier (VLCC) supertankers with 2 million barrels of Forties crude each are due to arrive in North Asia in February, while three VLCCs have been provisionally booked to load oil this month for arrival in Asia in March-April, the data showed.

http://uk.reuters.com/article/us-asia-oil-idUKKBN14V0K7

The FOB Korea benzene marker surged $102/mt, or 12.4% week on week, to be assessed at a 25-month high of $926/mt Tuesday, amid firm Chinese demand and few spot availability in the FOB Korea market.

It was last assessed any higher at $972/mt FOB Korea on November 27, 2014, according to S&P Global Platts data.

Benzene prices in Asia have been hovering below $700/mt through most of 2016, climbing above $900/mt only once in December at $910/mt on December 8, 2016, and averaging at $641.58/mt FOB Korea in 2016, according to Platts data. The surge in prices over the past month has been driven mainly by firm demand for prompt cargoes in China, as deliveries were delayed due to tight vessel availability and bad weather conditions at the main discharge ports in East China.

Benzene prices in East China's domestic market were last heard at Yuan 7,800-7,900/mt ($944.04-$956.14/mt) Tuesday, up from Yuan 7,100-7,200/mt ($862.23-$874.37/mt) last Tuesday.

Inventory levels in East China's onshore tanks were heard to be at around 33,500 mt on January 6 -- much lower than the typical 80,000-100,000 mt seen for most of 2016.

This prompted traders to seek more February and March loading material as they anticipated Chinese import demand would sustain even after the Lunar New Year holidays amid positive downstream margins.

The surge in buying interest, however, could not be met by supply as several traders had already allocated their spot cargoes in term contracts, while Northeast Asian producers were holding back on making spot offers, waiting for prices to peak.

Some sources, though, were less bullish about the domestic China market as an estimated 200,000 mt of Northeast Asian benzene and over 20,000 mt of deepsea-origin benzene were expected to arrive from second-half January onwards.

But for the current week, the upsurge in FOB Korea benzene prices was expected to remain even if China stopped taking in cargoes, as the FOB US Gulf Coast prices were rising which could open the arbitrage from East.

FOB USG Q2 benzene price rose 7 cents from Monday, but jumped 46 cents week on week to be assessed at 322 cents/gallon Tuesday, or $962.78/mt.

Tighter supply and a closed arbitrage to the US from the East had pushed the FOB USG marker to hit a 25-month high on Tuesday, Platts data showed.

But whether the East-West arbitrage window would open up remained uncertain, as downstream styrene monomer plants in the US were heard to be scheduled for consecutive turnarounds in the first-quarter of 2017.

http://www.platts.com/latest-news/petrochemicals/singapore/asian-benzene-hits-more-than-2-year-high-on-prompt-27748079

---

Attached Files

Oil and gas companies will increase spending in 2017 and more than double new project developments as they gain confidence that a two-year oil price slump is behind them, consultancy Wood Mackenzie said.

The upbeat outlook follows a more than 20 percent rise in benchmark crude oil prices in the past two months to around $55 a barrel on the back of an agreement by major producers to trim output.

"We've just come through two years of gloom and lots of costs cutting and now we are cautiously optimistic there will be a start of recovery in 2017," Malcolm Dickson, a principal oil and gas analyst at Wood Mackenzie, said.

According to WoodMac's global upstream outlook for 2017, exploration and production spending is expected to rise by 3 percent to $450 billion. This is still 40 percent below 2014 levels.

Geographically, the increased activity will vary hugely. U.S. shale oil production is expected to account for most of the gains because it is relatively cheap and quick to develop, in some cases it can take only 6 months.

Shale was the main driver of the recent supply glut and also experienced the sharpest declines in terms of output during the downturn.

Production in the most attractive shale areas, particularly in the Permian basin in Texas, is currently profitable with oil at $40 to $60 a barrel, according to WoodMac analyst Tom Ellacott.

U.S. shale oil production is expected to grow by around 300,000 bpd in 2017 to around 4 million bpd, according to WoodMac estimates.

WoodMac forecasts oil prices to average $57 a barrel in 2017 and gradually increase to $85 a barrel in 2020 as supplies decrease due to the investment cutbacks of the past few years.

Aside from onshore U.S. production, oil companies globally have also been able to reduce costs of field developments sharply by simplifying engineering plans and lowering contractor and rig rates.

Costs have fallen by 20 percent since 2014 and are expected to decline by an additional 5 percent this year, according to Dickson.

The savings are having a profound impact on project profitability, including costlier deepwater projects, some of which are profitable at oil prices of $50 to $60 a barrel.

The number of final investment decisions for projects with resources bigger than 50 million barrels of oil equivalent will more than double in 2017 to 20 to 25 from only 9 in 2016.

Projects most likely to get the nod include Exxon Mobil's Liza discovery offshore Guyana, deepwater projects in Brazil and in the Gulf of Mexico. BP late last year approved the development of the second phase of the Mad Dog field in the Gulf of Mexico and its partners will decide on it this year.

But the pick up in activity is still not enough to cover a growing supply/demand gap, which WoodMac expects will widen to 20 million barrels per day by 2025, based on current development plans.

"You need the new projects to be sanctioned by 2020 to meet future supply gap," Ellacott said.

http://www.reuters.com/article/oil-production-spending-idUSL5N1F03US

---

Attached Files

Brazilian oil giant Petrobras has reported that its average oil production in Brazil reached an annual historical record in 2016.

Namely, the company’s oil production in 2016 reached 2.144.256 thousand barrels per day (bpd), 0.75% above the results for the prior year and in line with the 2,145 thousand bpd target forecast for the period.

For the second year in a row, the company has met forecast plans, reinforcing its commitment to the predictability of its projections, Petrobras said on Wednesday.

The company also informed that its average annual production operated in the pre-salt layer in 2016 was also the highest in the company’s history, reaching 1.02 million barrels of oil per day and surpassing the 2015 production by 33%.

If Petrobras’ own natural gas production, which reached in 2016 an unprecedented 77 million m³ per day, is considered, total production in the country reaches 2.63 million of barrels of oil equivalent per day (boed) – 1% more than the levels for 2015, also a new record for Petrobras.

The main highlights for production expansion in 2016 were the significant production growth in the Lula field (Iracema Norte and Iracema Sul areas, with FPSOs Cidade de Itaguaí and Cidade de Mangaratiba) and in the Sapinhoá field (FPSO Cidade de Ilhabela), located in the Santos Basin’s pre-salt layer, in addition to the Parque das Baleias area (P-58), in the Espírito Santo state section of the Campos Basin.

Additionally, operations for three production systems started, two of which in the Lula field (FPSO Cidade de Maricá and FPSO Cidade de Saquarema) and one in Lapa (FPSO Cidade de Caraguatatuba), located in the Santos Basin’s pre-salt layer.

The utilization rate for Petrobras’ gas in Brazil also achieved its annual record in 2016, reaching 96%, a result of the efforts undertaken by the operating efficiency improvement and gas use optimization programs.

Record productions in December

In December 2016, the company also surpassed its monthly and daily production historical records: average oil production in Brazil for the first time exceeded 2.3 million bpd, 3% above the record registered in September 2016, and production on December 28 achieved 2.4 million barrels of oil.

In gas production, there was a 2% increase in comparison to the previous month, achieving 81.8 million m³/day. As such, oil and natural-gas production in Brazil in December were 2.82 million boed, 3% higher than what was recorded in November 2016 and 6% higher than December 2015, which also represents a new monthly production record for the company.

Oil production operated by Petrobras in the pre-salt layer reached in December the new monthly record of 1.27 million bpd, a 9% increase in comparison to production in November, which was 1.16 million bpd. Moreover, Petrobras reached a 1.34 million barrels daily record on December 29.

Meanwhile, oil and natural-gas production operated in the pre-salt layer were 1.58 million boe/d, displaying a significant 45% increase between December 2015 and December 2016, also representing a new monthly record.

Internationally, average oil production in December was 61 thousand bpd and average natural gas production was 10.3 million m³/day. As such, in December, 122 thousand boe/d were produced globally.

If oil and gas production in Brazil and internationally are consolidated, production in December 2016 was 2.94 million boed, which also represents a new monthly record.

International oil and gas production in 2016

Internationally, average oil production in 2016 was 80 thousand bpd, 19% below the volumes in the previous year. Average natural gas production reached 13.7 million m³/day, 11% below 2015 production. Reduction occurred mainly because of divestments executed, such as the sale of Petrobras Argentina.

If production in Brazil and internationally are consolidated, average oil production in 2016 was 2.22 million bpd, while average annual production of oil and gas was 2.79 million boed, the same level as in 2015.

http://www.offshoreenergytoday.com/petrobras-boasts-with-new-annual-oil-production-record/

---

Attached Files

Driven by the success of Eni’s major Zohr field gas discovery offshore Egypt in 2015, companies are rethinking the Eastern Mediterranean region’s gas potential, according to a new analysis from IHS Markit, an information and analytics group.

Total’s announcement that it will drill a 2017 exploration well in its deepwater Block 11 located offshore Cyprus indicates the growing interest in the wider region, IHS Markit said on Wednesday.

“The Zohr gas discovery in Egypt was a play opener for the region—it has caused companies to rethink the region’s gas potential and take a closer look at the geology,” said Graham Bliss Ph.D., senior director of plays and basins research at IHS Markit, and lead author of a series of analyses examining upstream energy competition in the Eastern Mediterranean.

“Zohr’s success clearly encouraged Total leadership to re-examine Block 11’s potential, since it is contiguous with the Egyptian Shorouk Offshore Block, which is home to Eni’s Zohr Field.”

‘One of the most critical wells’ in 2017

IHS Markit believes that Total’s exploration well will be one of the most critical wells drilled globally in 2017 for the E&P industry, especially given the slowdown in exploration drilling worldwide. The IHS Markit analysis, Bliss said, underscores the potential impact that this well and the changing competitive landscape could have on the future development trajectory of the hydrocarbon sector in the Eastern Mediterranean.

Total’s Offshore Cyprus Block 11 is located to the north of Zohr’s Egyptian Shorouk Offshore Block, which, Bliss said, is the first time in the region that a carbonate, rather than a sand, reservoir was targeted. “The carbonate reservoir that comprises Zohr is of particularly high quality,” Bliss said. “As such, it will likely enable development using a minimum number of wells and, therefore, reduce costs and enhance project economics.”

The Zohr Field is one of the largest conventional gas discoveries of recent years. It has in-place resources of 32 trillion cubic feet (TCF) of dry gas, with possible recoverable resources of about 20 TCF, according to Eni’s statements. To date, Eni has drilled five wells on the Zohr structure, which have confirmed a large gas accumulation and the existence of a very high-quality reservoir, IHS Markit said. The Zohr Field Phase 1 project is due to come on-stream in 2017.

“The existence of a carbonate reef play, which Zohr has proven to be, is very different from the turbidite sand-play discoveries in the Israeli Levantine Basin and the Egyptian Nile Delta Basin,” Bliss said.

Potential for ‘significant’ discovery in Block 11

Bliss further added: “If the Zohr carbonate play extends northward into Total’s Block 11, then the potential for a significant discovery in Block 11 exists, resulting in profound implications for the region. A major find would provide competition with offshore Israel gas fields to fulfill Egypt’s rising gas demand, and within the complex jigsaw puzzle of gas supply and demand in the Eastern Mediterranean, could even potentially lead to gas exports to Turkey.”

IHS Markit research has also concluded that direct pipeline exports from the Eastern Mediterranean to Greece are potentially commercially viable.

Competitive landscape

The competitive landscape in the region has already begun to change in anticipation of the potential, the IHS Markit report said. In November 2016, BP purchased a 10 percent equity stake in the Shorouk Offshore Block (including Zohr) from Eni, with the option to acquire a further 5 percent stake.

This purchase consolidated BP’s strong position along the northern margin of the Nile Delta Basin, but by itself did little to diversify the range of players in the Nile Delta offshore where BP, Eni and Shell dominate, according to Catherine Gifford, Africa plays and basins research lead at IHS Markit.

“The transaction does nothing by itself to vary the number and type of companies active in the basin,” Gifford said. “The success of this basin, and its subsequent further contribution to Egypt’s economy, largely depends on the continuing commitment of these few companies. There is little open acreage that could be offered in future licensing rounds, subject to acreage relinquishments, but of course there is the potential for farm-ins.”

Gifford said that a Total discovery in Block 11 would add Total to the list of leading players in the region. Further, in December 2016, Rosneft (in which BP holds a 19.75 percent interest) purchased a 30 percent interest in the Shorouk Offshore Block from Eni with the option to acquire a further 5 percent stake.

The December 2016 announcement of results from Cyprus’s Third Offshore Licensing Round confirmed the interest of established and new companies in the Eastern Mediterranean region’s growing gas potential. Eni extended its key role in the region with its award of Offshore Cyprus Block 6 (northwest of Block 11) with partner Total, as well as for Offshore Cyprus Block 8 (northeast of Block 11). ExxonMobil won the bid for Offshore Cyprus Block 10 (which Total had previously relinquished).

The ranks of larger companies in the region have now swelled to include Total, ExxonMobil and Rosneft, in addition to the established players—Eni, Shell and BP.

While gas is the primary target for the Total Cyprus Block 11, the IHS Markit analysis said there is some potential for a deeper, but unproven, Cretaceous target, which could have oil potential.

Cyprus & Israel to compete for gas sales to Egypt?

In terms of commercialization of natural gas, while a number of options exist, Bliss said the most likely outcome for a significant Block 11 discovery is export to Egypt to supply its growing domestic demand. Historically, gas prices in Egypt have been low, but recent deepwater developments like Zohr suggest a likely gas price of between $4 per million cubic feet (MCF) to $6 per MCF for a Block 11-type of development if gas was to be exported to Egypt.

“There is the potential for competition between Cyprus and Israel for gas sales to Egypt,” Bliss said. “A new, substantial gas discovery would also provide additional options for Cyprus to commercialize its Aphrodite discovery, since infrastructure investments could support multiple discoveries.”

Bliss said that, technically, Cyprus could export any gas finds to Turkey, but given the split between north (Turkey) and south (Greek), Cyprus, this is, at present, unlikely, but the regional geopolitical landscape is not static. Turkey’s desire to reduce reliance on Russian imports and Turkey’s interest in importing both Israeli and Cypriot gas could provide an important boost to the island’s reunification discussions. The reunification meetings this week in Geneva mark the first time since 1974 that Turkey and Greek Cypriots have sat down together at the negotiating table.

“More natural gas in Cyprus, coupled with Cyprus-Turkish risk and Israeli gas-monetization options, favors the creation of Egypt as the regional commercialization hub for all the Eastern Mediterranean,” Bliss said.

“This is due to both its domestic market potential, and its established liquefaction capacity, which enables export of incoming gas. Depending on the outcome of Total’s drilling program in Block 11, 2017 could be a significant year for the region, and we could see competition and investment really begin to heat up.”

http://www.offshoreenergytoday.com/ihs-markit-totals-block-off-cyprus-to-compete-with-enis-zohr-discovery/

Argentina has clinched a deal with labor unions and energy companies aimed at luring investors to the Vaca Muerta formation in Patagonia, one of the largest shale reserves in the world, the government said on Tuesday.

Vaca Muerta has attracted investment from Chevron Corp and Exxon Mobil Corp. But the formation, which is about the size of Belgium, remains mostly unexplored, largely due to high production costs and a lack of labor flexibility, oil major executives have said.

As part of the pact, Argentina will offer a subsidized price of $7.50 per million British thermal units of natural gas produced at new wells through 2020. The price, which is more than double that of front-month natural gas futures on the New York Mercantile Exchange, is "indispensable for attracting long-term investment," the government said in a statement.

Companies including state-owned YPF SA, Chevron, Total SA, Royal Dutch Shell Plc and BP unit Pan American Energy LLC [BPPAE.UL] will invest $5 billion to tap the formation in 2017 and double that in coming years as part of the deal, President Mauricio Macri said in a televised address.

YPF now plans to invest $2.3 billion in Vaca Muerta in 2017, 20 percent to 30 percent more than it would have without the deal, chairman Miguel Gutierrez told reporters after the announcement.

The other companies either declined to comment or did not immediately respond to requests for comment on their specific plans.

YPF shares on Argentina's Merval stock index jumped 10.5 percent on Tuesday to 321 pesos ($20.25), their highest level since August 2015.

Argentina suffers from a substantial energy shortage, a major cause of its wide fiscal deficit. The government has calculated Vaca Muerta would need total long-term investment of $200 billion to reverse the country's sustained energy shortage.

Neuquen province, where most of the formation is located, will stabilize taxes as part of the deal and labor unions have signed on to more flexible contracts. Strikes are common in Argentina, where high inflation often strains relations between powerful unions and management.

The $7.50 per mmBtu price matches the subsidized price under Argentina's "Gas Plan" launched in 2013 to stimulate production at existing wells.

The government also subsidizes locally produced oil to encourage domestic production. But employment in the sector had been affected by an increase in fuel imports spurred by world crude prices that are well below local prices.

Of the 19 concessions awarded in Vaca Muerta so far, just two have started producing. The government hopes the agreement will spur development in the remaining 17.

While initial additional production would likely go toward closing the domestic energy gap, last weekend Argentina allowed a 15-year-old export duty on oil and oil products to expire.

Vaca Muerta contains 308 trillion cubic feet of shale gas and 16.2 billion barrels of shale oil, according to the U.S. Energy Information Administration.

http://www.reuters.com/article/us-argentina-gas-idUSKBN14V03N

U.S. crude oil refinery inputs averaged 17.1 million barrels per day during the week ending January 6, 2017, 418,000 barrels per day more than the previous week’s average. Refineries operated at 93.6% of their operable capacity last week. Gasoline production increased last week, averaging about 9.7 million barrels per day. Distillate fuel production remained unchanged last week, averaging over 5.3 million barrels per day.

U.S. crude oil imports averaged about 9.1 million barrels per day last week, up by about 1.9 million barrels per day from the previous week. Over the last four weeks, crude oil imports averaged over 8.2 million barrels per day, 6.3% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 683,000 barrels per day. Distillate fuel imports averaged 103,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 4.1 million barrels from the previous week. At 483.1 million barrels, U.S. crude oil inventories are at the upper limit of the average range for this time of year. Total motor gasoline inventories increased by 5.0 million barrels last week, and are at the upper limit of the average range. Both finished gasoline inventories and blending components inventories increased last week. Distillate fuel inventories increased by 8.4 million barrels last week and are above the upper limit of the average range for this time of year. Propane/propylene inventories fell 4.5 million barrels last week but are in the upper half of the average range. Total commercial petroleum inventories increased by 13.4 million barrels last week.

 Total products supplied over the last four-week period averaged over 19.5 million barrels per day, up by 1.3% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged 8.9 million barrels per day, up by 0.7% from the same period last year. Distillate fuel product supplied averaged over 3.6 million barrels per day over the last four weeks, up by 7.5% from the same period last year. Jet fuel product supplied is up 7.1% compared to the same four-week period last year.

Cushing down 600,000 bbls

http://ir.eia.gov/wpsr/wpsrsummary.pdf

                                                    Last  Week  Week Before  Year Ago

Domestic Production '000............ 8,946           8,770           9,227
Alaska .................................................. 515             529              521
Lower 48 ........................................ 8,431           8,241           8,706

http://ir.eia.gov/wpsr/overview.pdf

---

Attached Files

Debt-laden energy companies that still don’t have a financial escape plan in place are running out of time and willing lenders even after oil doubled from its February lows.

Crude prices topping $50 a barrel helped to ease pressure on distressed energy companies, allowing at least 27 issuers to sell $16 billion of junk-rated bonds in last year’s final quarter, according to data compiled by Bloomberg. That still leaves about $44.5 billion maturing by the end of 2020, according to Fitch Ratings. A “mountain” of more than $18 billion in credit-line commitments comes due in 2019, said Spencer Cutter at Bloomberg Intelligence.

Those still vying for new capital such as Vanguard Natural Resources LLC and Pacific Drilling SA need prices above $55 to $60 to win over lenders, according to credit analysts. What’s more, banks face tougher limits from U.S. regulators on energy loans, spurred memories of previous of booms and busts.

Creditors remain mindful that drillers “get very happy about their cash flow” during good times, Evercore ISI analyst James West said. “And when financial markets become wide open, they spend like drunken sailors.”

Borrowers are trying to avoid the fate of more than 230 exploration, drilling, production, servicing, transportation and storage companies that have gone bankrupt since the start of 2015, affecting about $96.2 billion of debt, according to data tracked by the Haynes and Boone law firm.

Despite last year’s rally, oil prices are still down from more than $107 a barrel in mid-2014, making debt loads based on those near-record levels unaffordable. Lenders may want to see sustained prices of at least $55 a barrel before agreeing to extensions, Cutter said.

Even then, bankers may hesitate because regulators issued stricter leverage guidelines last year on energy lending that suggests limiting debt to four times adjusted earnings. Approach Resources Inc., a Fort Worth, Texas-based producer, cited the cap as one motive for its pending debt-for-equity swap, telling investors it could chop leverage to 3.5 this year from 9.6 in 2016’s fourth quarter.

Last year’s oil price rally spurred some investors toward the “junkier names,” said William Costello, senior portfolio manager and research analyst at Westwood Holdings Group Inc., but he doesn’t see that as a winning formula. Companies without a foothold in the most profitable drilling areas, especially the Permian shale basin in Texas and New Mexico, will still struggle to perform, he said.

SEEKING SOLVENCY

Vanguard had about 6 percent of its oil and gas acreage in the Permian as of October. Banks cut the company’s credit line a second time late last year, leaving it overdrawn, and Houston-based Vanguard has said bankruptcy “may be unavoidable.” Pacific Drilling, the ultra-deepwater driller with operations headquartered in Houston, said debt talks stalled after creditors demanded a bigger equity stake, and S&P Global Ratings is predicting no recovery for offshore contract drilling services until 2019.

Representatives for Vanguard and Pacific Drilling didn’t respond to messages seeking comment. Pacific Drilling has said it expects cash will last through 2017.

For those that do find a solution, the rewards can be substantial. Bonds issued by Chesapeake Energy Corp., which conducted more than a dozen debt deals, accounted for six of the 10 best-performing energy sector bonds in the Bloomberg Barclays U.S. Corporate High Yield Index in 2016, with each returning over 240 percent, according to BI calculations. S&P, which had added Chesapeake to its list of “weakest links” last year, now has the CCC+ rated company on its roster of issuers it might upgrade.

http://boereport.com/2017/01/11/energys-drunken-sailor-legacy-hangs-over-plans-for-debt-rescues/

Delphi Energy Corp. Announces 2017 Budget and Development Plan to Significantly Accelerate Drilling Activity and Production Growth

Delphi Energy Corp. is pleased to announce that the Company’s Board of Directors has approved the 2017 capital and operating budget following the closing of the previously announced $50.0 million Bigstone Montney Transaction and the announcement of a new $80.0 million senior secured credit facility with Alberta Treasury Branches, as syndicate lead, which also includes the Bank of Nova Scotia.

Delphi’s drilling program in 2017 will more than double as compared to 2016 with the addition of a second drilling rig. The Company’s production growth profile through 2017 is largely weighted to the second half of the year, with fourth quarter of 2017 production expected to average approximately 11,000 to 11,500 barrels of oil equivalent per day (“boe/d”), representing approximately 60 percent growth (absolute and per share) over production in the fourth quarter of 2016.

Condensate production is forecast to more than double in the fourth quarter of 2017 as compared to the fourth quarter of 2016, with average production levels increasing to approximately 2,800 barrels per day (“bbls/d”).

Fourth quarter 2017 run-rate funds from operations (“FFO”) are forecast to increase approximately 145 percent (absolute and per share) to $72.0 to $80.0 million from fourth quarter 2016 levels.

2017 Budget and Development Plan

Delphi’s 2017 capital program is forecast to be $65.0 to $70.0 million targeting an increase in annual production of approximately 25 percent (absolute and per share) to 9,000 to 9,500 boe/d. Annual 2017 FFO are forecast to increase approximately 82 percent (absolute and per share) based on an average West Texas Intermediate (“WTI”) oil price of US$55.00 per barrel and an average New York Mercantile Exchange (“NYMEX”) natural gas price of US$3.25 per million British thermal units (“mmbtu”). As a result, the Company’s increasing cash flow is expected to reduce bank debt to annualized fourth quarter 2017 FFO of 0.8 times and total debt to annualized fourth quarter 2017 FFO of 1.5 times. The contemplated 2017 capital program is net of an estimated $10.6 million of carried capital remaining from the total joint drilling commitment of $20.0 million relating to the Transaction.

The 2017 development plan contemplates the drilling of 13 gross (8.4 net) Bigstone Montney horizontal wells and the completion, tie-in and well site equipping of 14 gross (9.0 net) wells. A second rig commenced drilling operations in December 2016 and is expected to remain active throughout our 2017 drilling program, allowing the Company to proceed with pad drilling that will realize further cost savings.

The Company continues to innovate field operations, greatly reducing costs while significantly improving well results. Well stimulation design innovations continue to enhance well productivities, field condensate yields and well economics. Continued Montney drilling to the west at Bigstone is resulting in ultra-rich field condensate yields. Field condensate yields of the most recent wells have increased two to four times compared to the average yields realized from the previous 25 wells. Increased condensate yields of this magnitude on new wells, combined with higher forecast condensate prices in 2017 have the compound result of doubling revenue per boe and increasing unhedged field operating netbacks per barrel of oil equivalent (“boe”) by a factor of three times to $30.00 to $35.00 per boe compared to 2016 netbacks.

Cash costs are forecast to decrease by approximately ten to twelve percent over 2016, with a continued focus on cost saving initiatives and significant production growth. Crown royalties are forecast to increase with higher prices largely offset by a decreased percentage of production relating to prior years gross overriding royalties arrangements.

The Company has the required firm service transportation for 100 percent of forecasted 2017 natural gas production growth. The contracted Alliance full path service to Chicago with its incremental priority interruptible service, together with the existing and incremental 2018 contracted firm service on TransCanada Pipeline Limited, will provide the Company with sufficient firm service to handle Delphi’s growth plans beyond 2017. Delphi’s Bigstone Montney field compression and dehydration facilities are also sufficient for the forecasted growth in 2017.

To efficiently increase future natural gas processing capacity through 2019, the Company is continuing its evaluation to utilize approximately 35 mmcf/d of owned under-utilized sweet gas processing capacity in the greater Bigstone area. Coincident with the Company’s plans to pursue richer Montney production to the west, the production also becomes less sour and even turns sweet into the West Bigstone Montney area. Sweetening of sour Montney production would allow for processing at both the Bigstone West gas plant located at 14-28-59-22W5, where the Company owns a 25 percent working interest and at Delphi’s 100 percent owned and operated Negus gas plant at 11-3-60-25W5.

Delphi continues to maintain a strong risk management position on both volumes and pricing. The Company believes that reducing commodity price volatility through an active and strategic hedging program both reduces downside cash flow risk while protecting the economics of new capital being deployed. Protecting simple payouts for new wells of approximately one year through a strategic hedging program ensures the ability to effectively reinvest post-payout free cash flow. The Company has approximately 20 million cubic feet per day (“mmcf/d”) of its 2017 forecast natural gas production hedged at an average price of CDN$4.21 per mmbtu and approximately 1,000 bbls/d of condensate hedged at an average WTI price of CDN$66.70 per barrel (“bbl”).

Operational Success Continues

The ongoing drilling and completion operations and continued favorable results meeting or exceeding the Company’s expectations are providing validated increased support for the 2017 forecast. The combination of new development moving further to the west on the Company’s Bigstone Montney property, along with Delphi’s third generation frac design, has resulted in a significant improvement in field condensate to gas rate yields and increasing condensate yield assumptions from 40 barrels per million cubic feet (“bbls/mmcf”) to 100 bbls/mmcf over the life of the well.

http://boereport.com/2017/01/11/delphi-energy-corp-announces-2017-budget-and-development-plan-to-significantly-accelerate-drilling-activity-and-production-growth/

---

Attached Files

Evercore ISI’s most recent US Drilling Permit Monthly update shows that new well filings have returned the Gulf of Mexico’s permit numbers to an upward trajectory, with deepwater in particular filing a strong increase.

Overall, December’s permit numbers showed a gain again after falling in November.

Evercore ISI’s Oilfield Services, Equipment & Drilling group reviews and compiles drilling permit data numbers from a number of sources, including state boards and the Bureau of Safety and Environmental Enforcement, for the report. Given the costs, time, and effort invested before drilling or re-entry even begins, the group finds the permit numbers to be a leading indicator for near-time drilling activity.  

December’s total of 11 new permits grew 57% from seven in November, which had broken a string of three sequential monthly gains. December’s total was down just 27% from permitting year-over-year, Evercore ISI found.

Shallow-water permitting held at two permits in December, with one new well and one side track approved.

One ultra-deepwater well was filed in December, up from zero ultra-deepwater permits filed in the previous two months.

Midwater permitting showed “a modicum of resilience,” the report noted, falling just two permits month-over-month to a total of three for the month of December.

Deepwater permits experienced the largest sequential growth, expanding from zero permits in November to five in December.

New well permits grew from one in November to six in December, while side track permits fell 50% to two and bypass permits increased 33% to three.

Despite this good news, the analyst continues to see the area of shallow-water permitting as an area of concern and continues its feelings of what it has previously called “cautious optimism” regarding the offshore market overall.

“The sharpest decline year-over-year has come from shallow-water permitting, down 73% in 2016 from full-year 2015. We believe that offshore drilling will continue to languish as long as shallow-water permits remain at historically low levels,” the report said.

“Offshore planning from last month suggests more GoM weakness moving forward, with just three mid-water plans filed in the month of December. Overall, we remain cautious in allocating optimism to the offshore space, but permitting trends have certainly shown upward momentum over the past quarter.”

http://www.offshore-mag.com/articles/2017/01/new-report-shows-monthly-rebound-in-gom-drilling-permits.html?utm_source=feedburner&utm_medium=feed&utm_campaign=Feed%3A+offshore-rss+%28OS+-+Latest+Articles+RSS+Feed%29

---

Attached Files

Texas LNG executed non-binding term sheets with four independent buyers in South East Asia and China for a volume of 3.1 million tons per year from its project to be located at the Port of Brownsville’s deepwater ship channel.

According to the company’s statement, buyers include a mix of state-owned and private entities that currently own, or plan to construct LNG receiving facilities in the next few years.

With options included in the term sheets, the offtake volumes could rise to approximately 4 mtpa, as the company is currently marketing the Phase 2 capacity.

The project’s Phase 1 (Train 1) capacity, of 2 million tons per year has been oversubscribed, which is necessary for attaining the final investment decision.

The term sheets provide the commercial foundation for Texas LNG to continue negotiating definitive 20-year liquefaction tolling agreements and sale and purchase agreements.

Under the terms of the LTAs, Texas LNG will be paid monthly capacity fees to liquefy natural gas, store it, and deliver it onto LNG ships arranged by the LNG buyer.

Texas LNG is also promoting an SPA structure, whereby it is responsible for delivering LNG on an FOB or DES basis.

Langtry Meyer, Founder & COO of Texas LNG noted that securing the customers for Phase 1 capacity of the project is sufficient to reach FID in 2018.

Texas LNG expects the production from its first liquefaction train to start in 2021-2022.

http://www.lngworldnews.com/texas-lng-pens-deals-with-four-asian-buyers/