Record levels of drilling and production – particularly in the US – were fundamental factors in the downturn that swept across the oil and gas industry over the last 18 months. Much of the crude oversupply has been sent into storage – either at refining bases, storage hubs, strategic reserves or moored in crude carriers.
Such is the scale of the crude flows that oil prices routinely track movements in inventories at the world’s largest storage and trading hubs. EIA data shows US crude oil stocks hit peak levels of 543 million barrels (excluding the strategic petroleum reserve) in late April, which has since contracted to 523 mmbbls (week ending 29th July).
US storage draws since April have resulted in an uptick in refinery utilization, rising from 89.7% to over ~93% by the end of July. Much of this spike in utilization is due to the summer driving season – typically resulting in a marked increase in gasoline consumption. This has been a feature of the US downstream sector for a number of years, however, current utilization at US refineries is markedly lower than the peak seen in 2015 (96.1% in late July-early August).
It may be surprising that US refinery utilization is down on the same point last year – given the sheer volume of cheap feedstock available – yet, it is not altogether unexpected.
Refining margins which were routinely reaching levels not seen since 2012, are now back to $3-4/bbl due to a saturated products market. Consequently, incentives to delay routine maintenance and sustain high utilization have evaporated.
Early indications from DW’s soon to be released World Downstream Maintenance Market Forecast suggest that this may provide opportunities for those involved in MMO activities. However, consumers at the pumps are not likely to see further falls in prices without large scale storage draws. Fundamentally, operators of refineries must balance the allure of cheap feedstock with the risks of an over-saturated products market.
Matt Adams, Douglas-Westwood London
As battle lines were drawn during Libya’s long civil war, Libya’s National Oil Company (NOC) was split between East and West, with opposing governments in Tripoli and Torbruk competing over oil revenues. Libya holds Africa’s largest proven reserves of crude, however, ongoing conflict has seriously disrupted oil production and exports – Libya currently produces just 350,000 barrels per day (b/d), significantly below the 1.65 million b/d produced prior to the unrest.
With oil revenues a key source of income, attacks on oil installations have been frequent by rival groups vying for power. A statement on July 2nd – announcing the reunification of the NOC – could indicate that recovery in the Libyan oil sector is on the horizon. An NOC spokesman, Mohamed Elharari, stated that reopening the blockaded export terminals at Es Sider, Ras Lanuf, Zawiya and Zueitina was a top priority for the company. The four ports have a total export capacity of 860,000 b/d, and would significantly boost global crude supplies. Any improvement to the situation could have a substantial impact on global markets – the opening of these terminals would likely lead to downward pressure on oil prices.
However, years of war have ravaged Libya’s oil infrastructure, the lack of maintenance represents a significant barrier to increased production in the near term. Both Es Sider and Ras Lanuf have been the focus of attacks, with Ras Lanuf’s storage tanks particularly badly damaged. Key to restarting exports will be Ibrahim Jathran, head of the Petroleum Facilities Guard (PFG) – who have been blockading Libya’s export terminals since 2013. Initially set up as a politically neutral force to protect Libya’s oil facilities during the civil war, the group have arguably acted as a private militia under Jathran’s leadership. A deal between Jathran and the Tripoli-based government on the 25th July was condemned by the chairman of the NOC, Mustafa Sanalla, who stated that the deal set a “terrible precedent” for further extortion by armed groups controlling oil facilities.
As the disagreements continue, it is clear without the support of the NOC, the prospect of ports reopening remains unlikely. The reunification of Libya’s NOC is certainly a positive step for recovery, however, tremendous barriers remain – in the short to medium term, oil is unlikely to flow at the levels seen in the days of Gaddafi.
Joel Hancock, Douglas-Westwood London
Historically, Gazprom has monopolized all gas exports in Russia. Complete control over gas sales to both east and west did not incentivize Gazprom to explore new ventures in LNG projects. Instead, the company focused on the development of a conventional pipeline network – including the Nord Stream, South Stream and East Siberia-Pacific Ocean pipelines. Consequently – in terms of the LNG market – Russia is lagging behind other global gas producers, such as Australia or Qatar who have heavily invested in infrastructure over the past decade.
Given Russia’s extensive gas reserves, the country has the potential to be a leading LNG exporter. Recent landmark changes to the country’s operating environment may finally allow for this potential to be realized – with amendments to gas export law expected to challenge Gazprom’s gas monopoly. Russia’s oil & gas production giant Rosneft, as well as country’s largest independent gas producer, Novatek, have gained licenses to export LNG independently from Gazprom and are pushing projects forward.
Novatek’s Yamal development is a key example, prospects here have been boosted by both a financial injection from China (3.6bn EUR) and changes in the Russian gas export landscape. The project is a potential game changer for gas export and is expected to come onstream by 2018 with three (5.5 mmtp) trains.
DW expects both LNG and pipeline exports from Russia to Asia to increase significantly in the mid to long term as the country reduces its reliance on pipeline gas exports to Europe. Growing demand for natural gas in Asia will likely incentivize Russian players to continue to invest in liquefaction for export. Novatek has recently announced plans for new Arctic LNG plants to expand production in the region, with a second plant in the Gydan Peninsula.
With these new projects, Russia is positioning itself to be a serious competitor to leading LNG producers. The country’s vast gas reserves and geostrategic position place Russia in a unique position to meet the growing demand for gas in both Eastern and Western hemispheres.
Iva Brkic, Douglas-Westwood London
Canadian Differentials Remain Strong Post-WildfiresCanadian oil sands supplies partially recovered in June, with production volumes approaching normal in early July. Canadian, Bakken and Rockies differentials remained strong, supported by the reduced supplies. A small Cushing crude stock draw in June will be followed by another small draw in July.
Gazprom is offering Ukraine’s Naftogaz somewhat lower gas prices than European suppliers for the third quarter, the head of the Ukraine's national oil and gas company Naftogaz has said. "The price offered by Gazprom is somewhat lower as of today than the one offered by European suppliers, though the market is very volatile and the price on the European market has started to lower," Andriy Kobolyev told reporters. Gas supplies from Europe are sufficient to provide Ukraine with reserves for the winter season.
Warmer weather so far during July has added 2 GWs of demand in Italy, with the week starting also with extra cooling needs of roughly 4 GWs. Day-ahead prices have, however, been generally in line with expectations so far in July, with maximum hourly prices also under check, most likely as thermal demand is being undermined by a weaker economy, generally healthy hydro levels, and more favorable gas pricing.
Coal pricing was mixed last week, although the fact that the market was able to hold onto sizeable gains posted in the prior week despite weaker oil prices illustrates that the market has found a vein of structural strength. Interestingly, deferred pricing for API#2 (Northwest Europe) and API#4 (South Africa) strengthened relative to the prompt, while the opposite was true of FOB Newcastle (Australia). PIRA continues to assert that 2017 prices are undervalued, although we are doubtful that prices can maintain the recent run in pricing. While China's thermal coal imports have turned positive year-on-year, India's imports remain notably below prior-year levels and do not look poised to emerge any time soon, particularly during the monsoon season.
The U.S. EPA finalized designations for the 2010 SO2 NAAQS, classifying 61 areas, compared to 66 areas from February’s proposal. The five areas where EPA has backed off for now (no final action is being taken) include four in Texas and one in Oklahoma — all of which had been targeted in February’s proposal (contrary to those states’ own recommendations). EPA’s final four non-attainment regions include areas with coal plants in Illinois, Maryland and Michigan. All but one of EPA’s finalized designations for Texas agree with state recommendations, bearish for longer-term gas demand and power prices in ERCOT, though Regional Haze regs still await the outcome of legal challenges.
With pollination in full swing for many, weather forecasts offer something for both the bull and the bear. Expected hot temperatures this week will be somewhat offset by additional precipitation for almost everyone in the Eastern Belt. Those west of the Mississippi River are forecast to receive even more rain on top of last weeks’ very impressive totals.
Production was over 1 MMB/D for the third time in four weeks. Corn prices tumbled after bearish USDA reports, boosting manufacturing margins. 2016-D6 RIN prices soar.
PIRA’s analysis of resource control policies around the world suggests a marked trend towards more investor-friendly policies in the upstream oil sector. Most notably, Saudi Arabia, Russia, and Nigeria all announced plans to sell stakes in state-owned upstream operators, and improved contractual terms could soon materialize in major producers, including Iran, the UAE, and Venezuela. The moves are being partially offset by prohibitive tax increases in some countries, in an attempt to support government revenues. But if prices remain below the levels of the past decade, as PIRA forecasts, we would not be surprised to see more widespread implementation of policies favorable for foreign or private investment.
This week’s economic developments highlighted the global economy’s resiliency as well as its potential vulnerabilities. The U.S. jobs data for June were constructive: they showed healthy gains in payrolls, but did not point to overheating in the labor market. The latest data on Chinese foreign exchange reserves were also positive for the outlook. At the same time, the U.S. dollar continued to strengthen, a fallout from the Brexit decision two weeks ago. In addition, the European banking sector remained under pressure.
Crude stocks drew just 320 MB/D this past week, about one third the level PIRA expected. We believe floating stocks in the Gulf of Mexico were reduced to support the high import level. With floating stocks now likely more normal, PIRA expects July imports to reflect FOB cargo loadings, which imply lower than June imports and larger stock declines. For next week, we have crude stocks falling 620 MB/D with imports at 7.85 MMB/D.
The prospects for heavy summer cooling loads should favor a market “buying the dips,” despite prices retracing last week’s gains. Indeed, a sea change in sentiment has been on display as of late, whereby expectations for expanding cooling degree days (CDDs) have positively colored speculative positioning and price. Certainly, the latest snapshot of open interest in NYMEX/ICE futures encapsulates the shifting environment, which has seen Henry Hub (HH) prices rally ~30% month-on-month. Most notably, the long-to-short ratio between non-commercial longs and shorts continues to push deeper into new high ground, rising to ~1.1, the highest level since 2014.
In recent months, several utility-scale solar PV projects have been announced at ultra-low prices, raising questions about downside risk to natural gas and other power sources. As a result, PIRA recently raised its 2025 U.S. solar generation outlook 41% above the previous outlook from fall 2015. However, PIRA does not see substantial downward medium-term flexibility for U.S. utility-scale solar PPA prices below current subsidized levels, assuming a link to fundamental economics. Nevertheless, in regions with strong insolation and meaningful incentive mechanisms, solar will continue to pressure other power sources as it continues to grow from its small base.
California carbon prices were up in June vs. May, but remained below the auction floor. Declines in open interest suggest that market players are not switching to the secondary market for procurement, but rather refraining from taking new positions altogether. There is little incentive to purchase allowances at the August auction. Re-offering of unsold consigned allowances raises the auction quantity and will require a higher bidding volume to clear. PIRA does see pricing once again exceeding the auction reserve this year. Cap-and-trade regulatory amendments will be released July 12th, addressing post-2020 caps and allocations, linkages and also unsold allowances.
Inventories build by 390 thousand barrels the week ending July 1. PADD V received approximately 2.9 million gallons of imported ethanol from Brazil, only the second week this year in which imports were reported.
The 2016/2017 corn and soybean acreage numbers have turned into “knowns” for the July WASDE, but higher-than-expected old crop corn and soybean supplies in the Quarterly Stocks report just a few days ago may have more than a few scratching their heads at the World Board. Add to the mix these extremely fragile markets, and Tuesday’s outcome is far from a certainty in PIRA’s opinion.
Financial stress continues to lessen post-Brexit. On the week, the S&P 500 flirted with record highs, while volatility declined and emerging market debt prices rose sharply. The dollar retains a mixed upward bias. It has continued to strengthen against the British pound and some of the Eastern European currencies. However, it has weakened against a host of Asian currencies.
Crude runs rose on the week as maintenance continues winding down. Crude imports moved higher by 0.9 MMB/D and crude stocks built 1.5 MMBbls. Finished product stocks built 1.1 MMBbls, with increases in all the products other than gasoline. Gasoline demand was relatively strong and stocks drew, while gasoil posted a significant stock build on lower yield and exports. Refining margins have remained soft with little barrel support other than fuel oil and naphtha.
Even with send-outs sputtering into the N.W. European market during the shoulder months of the late second and early third quarters, the need for access to the liquid pricing hubs at the Dutch Title Transfer facility (TTF) U.K. NBP has never been more pronounced. The Atlantic Basin market stands poised to absorb some 90-bcm/yr. of new supplies by 2020 (not including Yamal), and sellers are extremely active in securing a portion of this total.
The horizontal oil rig count reached a trough in mid-May. Despite this, shale production is not expected to immediately return to growth. PIRA expects the rig count to continue increasing at a gradual pace for the balance of the year and beyond. An estimated 400 horizontal oil rigs are currently needed to maintain production, which is 128 rigs higher than the current count of 272. Production is expected to shift to growth by 2Q17. On an annual basis, PIRA expects shale crude and condensate production to decline 330 MB/D in 2016 and 60 MB/D in 2017. This represents a 70 MB/D upward revision in 2017 versus our June Reference Case.
After gas demand in the U.K. finally grew last year for the first time since 2010, many hailed it as a case when demand finally bottomed out. Gas burn is now getting strong support in the U.K. in the form of a £18.08/ton carbon floor and coal-fired power stations are getting shut down. Future growth prospects hang on power sector growth, but the upside appears to be limited, particularly from the perspective of National Grid.
Mont Belvieu propane prices narrowly beat out broader energy markets by declining 5.7% on the week to settle near 50¢/gal (August). Butane futures fell in line with WTI (-7.3%) while ethane prices dropped nearly two cents to 21¢, the lowest level since May.
The overall global equity market was unchanged for the week, with U.S. market gains offsetting weakness elsewhere. Gains in the U.S. market were broad based across most of the tracking sectors, except energy. Housing, retail, and consumer discretionary were the strongest performers. Internationally, the performance was mixed and tended to be weaker. Asia and Europe both displayed aggregated declines on the week of 1.2-1.5%.
Oil prices fell $3.70/Bbl this past week with time spreads getting crushed on both sides of the Atlantic. There was not a specific story to point to but just a host of negative news. PIRA's outlook for the week ahead is that the market will continue to be range bound and should therefore find support within a couple of dollars from here.
In June 2006, PIRA put forward a simple model to approximate the method used by some major oil companies to evaluate long-term investment projects. We have updated the results and not surprisingly prices are a lot lower.
The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.
North American Crude Prices Fall as Canadian Production ReturnsCrude prices fell in July, as Western Canadian oil sands production recovered from recent wildfires. Stocks rebuilt in Canada, weakening differentials for Bakken and Rockies, as well as Canadian grades. Cushing stocks were unchanged in July, but a small draw is likely for August, as overall U.S. crude stocks decline sharply.
Attempts to support spot price will be on two fronts: lower production ramp ups and finding new non-European pockets of demand (i.e. India), even if it means lower netbacks. Among the larger producers and portfolio marketers, the logic goes that it's better to make less money off a few cargoes than demonstrably damage the benchmark for all cargoes. As such, PIRA adjusted the LNG volumes we’ve projected would land on European shores.
The U.K. supply picture for the upcoming winter remains very fluid, with Eggborough Power Ltd announcing this week that its unit 4 coal plant (495 MW) will be available again in the wholesale market over the winter 2016/17, starting from September 16. This announcement comes a few months after the signature of a Supplemental Balancing Reserve (SBR) contract with National Grid for the provision of 681 MW of de-rated capacity from units 1 and 2 during the coming winter. The additional capacity that we potentially see coming back for winter 2016/17 is only the remaining unit at Eggborough. As for the other coal plants currently closed, we see the decision to come back online technically much more difficult to implement.
The coal market lost significant ground this week, with the three major forward curves shedding between $4.00/mt-$6.00/mt along the curve. The headline development of the week was the announcement that Turkey will be adding a $15/mt tax on imported thermal coal for power generation. Before this announcement, Turkey's imports had been one of the sole remaining sources of potential growth on the demand side in the Atlantic. The process of rebalancing for the coal market will continue, particularly as the outlook for Chinese import demand remains bullish. However, limitations on import demand such as what was announced in Turkey this week limit the upside for pricing, although our bullish expectations on oil pricing will drag the market higher as production costs escalate.
Mt. Belvieu LPG prices followed broader energy markets by changing little. September propane at the market center eased by 0.1% despite a very weak inventory build, which pushed stocks back into deficit vs. the year prior. Meanwhile, butane futures gained 1.3% to the settle above 61¢/gal as markets anticipate higher blending demand next season. Prompt August ethane prices plunged as the EIA reported another huge increase in production in June and a substantial inventory increase.
Manufacturing margins also declined. RIN prices decreased after soaring 30% since May.
The August WASDE could very well put in the high for corn yields as the euphoria around the 2016 crop peaks due to crop conditions. The December 2016/December 2017 corn spread traded down to -40 Thursday suggesting the market may even be looking at a 172 yield come next Friday, while PIRA is looking for a 170-171 number for the report.
This week’s U.S. July activity data (such as nonfarm payrolls and the ISM manufacturing index) suggested that the pace of economic growth will pick up in the second half of 2016. While wage growth has accelerated, it is not expected to impact the Fed policy outlook. The Bank of England delivered an easing package that went far beyond market expectations. Japan delivered a one-two punch of fiscal and monetary easing, but the Bank of Japan muddled its message about the upcoming policy action. A directional correlation between China’s manufacturing confidence and Brazil’s industrial production has continued to hold.
Overall stocks built 2.1 million barrels this past week with crude inventories building 1.4 million barrels but gasoline stocks declining 3.3 million barrels. This should be the last of the crude stock builds with offshore floating inventories relatively depleted thereby resulting in lower imports and a forecast 3.6 million-barrel stock decline in next week’s data. Cushing crude stocks fell 1.1 million barrels this past week and should decline another 0.5 million barrels in next week’s EIA report. Another gasoline stock decline is forecast for next week, albeit more moderate than this past week, while distillate stocks build just slightly.
Thursday’s 6 BCF U.S. storage pull was extremely rare — the last such cooling season event occurred a decade ago — driven by record-breaking gas power burn. Yet, barring a few transient spikes, NYMEX Henry Hub (HH) futures trading was relatively ambivalent. Part of this trepidation stems from looming shoulder season fundamentals that will weigh on gas burn for electric generation (EG). However, renewed production resiliency — until recently masked by transitory disruptions — may be even more influential in threatening balances in the weeks ahead.
The S&P 500 moved to another record high, though the Russell 2000 remained well short of its record high. Volatility moved lower, while high yield debt and emerging market debt indices generally moved higher in price. The UK long bond yield moved lower as the Bank of England lowered their overnight policy rate 25 basis points.
Inventories built to 20.6 million barrels the week ending July 29. About 10.6 million gallons of ethanol were imported. The production of ethanol blended gasoline increased to 9,439 MB/D the third highest on record.
Heading into the August WASDE this week there seems to be an inordinate amount of discussion around setting the lows “earlier than normal” this year. A lot of the discussion seems to center on reports from scouting farmers that this year’s corn crop is “good, but not great” and that it’s not as good as it looks from the road. More and more crop tours seemed to confirm these concerns last week, but the markets are “stuck” as the methodology employed by NASS for their August yield estimate solely counts stalks, which should not be an issue in any area with the exception of southern Minnesota and possibly far northern Iowa due to frost.
Crude runs rose 146 MB/D on the week, reflecting the restart of capacity previously in maintenance. Crude imports stayed sufficiently high to build crude stocks 0.77 MMBbls. Finished product stocks drew 0.57 MMBbls. Refining margins are poor and getting worse, which will prompt further discretionary run cuts that will ultimately tighten the market.
It’s probably safe to say that there really isn’t anything else left to delay this year with the exception of Australia Pacific LNG train 2, which PIRA has in its short term balance for October. The question then becomes should we should expect a similar number of delays in start-ups among the 12-odd trains on the books for 2017? The answer at this point is a firm maybe, as we have some evidence to suggest that this year’s flawed timing will be duplicated. One area where delays are mounting are on future projects. The rate of announcements delaying FIDs for the next generation of liquefaction is gathering force, as it becomes abundantly clear to even the most optimistic of project backers that lower oil prices are set to be a longer term feature of the market.
Global equities were broadly higher on the week. In the U.S., the growth indicator outperformed the defensive indicator as many of the growth sensitive sectors posted good gains. Banking and technology led the way higher, while utilities declined and underperformed. The international sectors performed even better than the U.S., and were led by Latin America, China, and emerging Asia. Europe fell back.
Over 70% of the gains in the rig count since May lows has been driven by private operators. Of these private rig additions, nearly 90% has come from operators that had been recently inactive. Many operators dropped to 0 rigs in the first quarter as WTI prices averaged $33/Bbl. As prices recovered, these operators have returned from 0 to 1 rig programs and they have been the primary driver of higher rigs. Now that a significant number of private operators have returned, PIRA thinks it is likely that gains in the rig count will slow.
The federal government has decided against raising the tariffs of petroleum related products despite Oil and Gas Regulatory Authority’s (OGRA) recommendation to raise prices, Finance Minister Ishaq Dar has said. Speaking to reporters in Islamabad, Finance Minister Ishaq Dar said that OGRA's summary was rejected after Prime Minister Nawaz Sharif directed not to raise the prices. He said that the current petroleum prices would remain unchanged until at least August 31, 2016.
EIA recently released their May oil balances. Domestic crude supply, which is domestic crude production plus the balancing item, was unchanged month-on-month and the year-on-year decline rate slowed from about 900 MB/D to 550 MB/D. Looking to June, based on PIRA's adjusted weekly data through July 22nd, domestic crude supply for June is estimated to have declined by 155 MB/D, month-on-month and the year-on-year decline rate has reaccelerated back to 735 MB/D.
The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.
As battle lines were drawn during Libya’s long civil war, Libya’s National Oil Company (NOC) was split between East and West, with opposing governments in Tripoli and Torbruk competing over oil revenues. Libya holds Africa’s largest proven reserves of crude, however, ongoing conflict has seriously disrupted oil production and exports – Libya currently produces just 350,000 barrels per day (b/d), significantly below the 1.65 million b/d produced prior to the unrest.
With oil revenues a key source of income, attacks on oil installations have been frequent by rival groups vying for power. A statement on July 2nd – announcing the reunification of the NOC – could indicate that recovery in the Libyan oil sector is on the horizon. An NOC spokesman, Mohamed Elharari, stated that reopening the blockaded export terminals at Es Sider, Ras Lanuf, Zawiya and Zueitina was a top priority for the company. The four ports have a total export capacity of 860,000 b/d, and would significantly boost global crude supplies. Any improvement to the situation could have a substantial impact on global markets – the opening of these terminals would likely lead to downward pressure on oil prices.
However, years of war have ravaged Libya’s oil infrastructure, the lack of maintenance represents a significant barrier to increased production in the near term. Both Es Sider and Ras Lanuf have been the focus of attacks, with Ras Lanuf’s storage tanks particularly badly damaged. Key to restarting exports will be Ibrahim Jathran, head of the Petroleum Facilities Guard (PFG) – who have been blockading Libya’s export terminals since 2013. Initially set up as a politically neutral force to protect Libya’s oil facilities during the civil war, the group have arguably acted as a private militia under Jathran’s leadership. A deal between Jathran and the Tripoli-based government on the 25th July was condemned by the chairman of the NOC, Mustafa Sanalla, who stated that the deal set a “terrible precedent” for further extortion by armed groups controlling oil facilities.
As the disagreements continue, it is clear without the support of the NOC, the prospect of ports reopening remains unlikely. The reunification of Libya’s NOC is certainly a positive step for recovery, however, tremendous barriers remain – in the short to medium term, oil is unlikely to flow at the levels seen in the days of Gaddafi.
Joel Hancock, Douglas-Westwood London
BP announced on July 14, that following significant progress in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill, it can now reliably estimate all of its remaining material liabilities in connection with the incident.
As a result, taking into account this estimate together with other positive tax adjustments, BP expects to take an after-tax non-operating charge of around $2.5 billion in its second quarter 2016 results.
This charge is expected to include a pre-tax non-operating charge associated with the oil spill of around $5.2 billion. This would bring the total cumulative pre-tax charge relating to the Deepwater Horizon incident to $61.6 billion or $44.0 billion after tax.
BP believes that any further outstanding Deepwater Horizon-related claims not covered by this additional charge will not have a material impact on the Group’s financial performance. It will deal with remaining claims in the ordinary course of business.
Brian Gilvary, BP chief financial officer said: “Over the past few months we’ve made significant progress resolving outstanding Deepwater Horizon claims and today we can estimate all the material liabilities remaining from the incident. Importantly, we have a clear plan for managing these costs and it provides our investors with certainty going forward.”
Gilvary reconfirmed that BP expects to continue to use proceeds of divestments to meet Deepwater Horizon commitments in line with the financial framework laid out in previous quarters.
A year ago, BP reached agreements to settle outstanding federal, state and local government claims arising from Deepwater Horizon. In the months since, BP has made much further progress in resolving outstanding claims arising from the incident.
PSC settlement - the Court and the Deepwater Horizon Court Supervised Settlement Program have been progressing the remaining economic and property damage claims relating to the 2012 Plaintiffs’ Steering Committee (PSC) settlement, including through simplified and accelerated procedures for processing certain claims. Today’s announced charge includes the estimated cost of settling all outstanding business and economic loss claims under that settlement, which are expected to be paid by 2019.
Opt-out and excluded claims - there has also been significant progress in resolving economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement. In February 2016, the US federal district court estimated that there were more than 85,000 valid opt-out and excluded economic loss plaintiffs. The vast majority of these claims have since been settled or dismissed as an order of the court today confirms. An estimate of the cost of the remaining claims, expected to be paid by the end of 2016, is also included in this charge.
Securities litigation - in June, BP announced a $175 million settlement of claims from a class of post-explosion ADS purchasers in the MDL 2185 securities litigation, payable during 2016 - 2017. This cost is also included in today’s announced charge.
Reducing drilling and development spend has largely been the focus of services and equipment providers in the Gulf of Mexico – with the aim of lowering costs at the most capital intensive period of asset lifecycles. Often overlooked, Opex costs have grown in line with other upstream costs – 7% CAGR from 2010 to 2014 in the Gulf of Mexico. The North American offshore market has some of the highest overall MMO costs per barrel – more than twice the global average.
Historically, offshore Opex has been largely ignored as a critical driver of deepwater project economics, yet this is beginning to change. The current rate of growth combined with the overall operational cost in the Gulf of Mexico is not sustainable. Operators are deferring and cancelling many historically routine operational objectives as long as they stay within safety and regulatory guidelines. Budgets for maintenance and modification projects are now being revisited and contractors will feel the impact. Within our offshore support sector clients, many firms typically point to the large proportion of revenue that is production-linked, implying that this insulates from the effect of oil price cycles. Whilst this may be true up to a point, the effect of the current prolonged downturn clearly reaches far further than exploration and development activities.
Mergers and acquisitions are likely to be a result of this operational spending compression, but there are still many efficiencies to be shaken out. Practices such as consolidating projects and optimising contracting processes are already producing results in many cases. With breakeven economics at $70 per barrel or higher at some Gulf of Mexico prospects, recognition of operational costs and streamlining the value chain can no longer be overlooked.
Andrew Meyers, Douglas-Westwood Houston
There is a general consensus amongst industry analysts that the oil oversupply creating the current market downturn will narrow by the end of 2016. Douglas-Westwood (DW) data support this view, with our World Drilling & Production Market Forecast showing the first oil production decline in 2016 since 2009 – when OPEC strategically cut output in order to support prices. This is largely due to considerable reductions in oil production from the US shale plays as well as widespread outages in Nigeria as a result of militant attacks in the Niger Delta. Therefore, the oversupply will be eroded from the supply side with the demand side stuttering as a result of slowing Chinese economic growth and uncertainty surrounding the future of European markets.
DW’s 2017 view is less positive for the oversupply. The implementation of a host of offshore developments sanctioned before the oil price crash will lead to a 1.8 million barrels per day (mmbbl/d) increase in offshore oil output and a 2.1 mmbbl/d increase overall. Such projects include the ill-fated Kashagan project in the Kazakh Caspian. Kashagan alone is expected to contribute nearly 300 thousand barrels per day (kbbl/d) in 2017. Significant additions are also expected from the Middle East in the form of condensate output from the 24-phase South Pars development and around 300 kbbl/d Khafji field – previously shut-in due to environmental infringements and disagreements between joint operators Kuwait and Saudi Arabia. This pattern is expected to be seen globally, even mature plays in the North Sea and south-east Asia seeing increased output in 2017 as a result of the lag effect of offshore developments (the time between project sanctioning and first oil can be many years).
Demand outlooks from BP, EIA and IEA suggest 2017 demand growth around 1.2 mmbbl/d to 1.5 mmbbl/d, therefore it is highly likely the oversupply will increase once again next year. Whilst this is not certain to push oil prices down once more, it is likely to dampen the recovery until later this decade when a lack of project sanctioning in the last two years leads to a significant drop in offshore oil output additions towards to the end of the decade. This will cause offshore oil production to peak at 29.1 mmbbl/d in 2019 before declining slowly into the 2020s. Onshore oil production is unlikely to sufficiently offset this trend to keep pace with demand growth later this decade, therefore, this may be the point the market reaches equilibrium.
Matt Cook, Douglas-Westwood London
Exxon Mobil Corporation (NYSE: XOM) and InterOil Corporation (NYSE: IOC, POMSoX: IOC) announced an agreed transaction worth more than $2.5 billion, under which ExxonMobil will acquire all of the outstanding shares of InterOil (the ExxonMobil Transaction). “This agreement will enable ExxonMobil to create value for the shareholders of both companies and the people of Papua New Guinea,” said Rex W. Tillerson, chairman and chief executive officer of Exxon Mobil Corporation.
“InterOil’s resources will enhance ExxonMobil’s already successful business in Papua New Guinea and bolster the company’s strong position in liquefied natural gas.”
InterOil Chairman Chris Finlayson said, “Our board of directors thoroughly reviewed the ExxonMobil transaction and concluded that it delivers superior value to InterOil shareholders. They will also benefit from their interest in ExxonMobil’s diverse asset base and dividend stream.” Under the terms of the agreement with ExxonMobil, InterOil shareholders will receive:
When concluded, this transaction will give ExxonMobil access to InterOil’s resource base, which includes interests in six licenses in Papua New Guinea covering about four million acres, including PRL 15. The Elk-Antelope field in PRL 15 is the anchor field for the proposed Papua LNG project.
ExxonMobil’s more than 40 years of experience in the global LNG business enables it to efficiently link complex elements such as resource development, pipelines, liquefaction plants, shipping and regasification terminals, which it has demonstrated through the PNG LNG project, working closely with co-venturers, national, provincial and local governments, and local communities. ExxonMobil will bring to bear its industry-leading performance and strong commitment to excellence as it grows its business in Papua New Guinea.
The PNG LNG project, the first of its kind in the country, was developed by ExxonMobil in challenging conditions on budget and ahead of schedule and is now exceeding production design capacity, demonstrating the company’s leadership in project management and operations. ExxonMobil will work with co-venturers and the government to evaluate processing of gas from the Elk-Antelope field by expanding the PNG LNG project. 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.
The ExxonMobil Transaction has been unanimously approved by the boards of both companies. The InterOil board unanimously recommends that InterOil shareholders approve the ExxonMobil Transaction.
The ExxonMobil Transaction will be implemented by way of a court-approved plan of arrangement under the Business Corporations Act (Yukon) and will require the approval of at least 66 2/3 percent of the votes cast by InterOil shareholders at a special meeting expected to take place in September, 2016.
In addition to InterOil shareholder and court approvals, the ExxonMobil Transaction is also subject to other customary conditions. Subject to obtaining the aforementioned approvals and satisfaction of closing conditions, the ExxonMobil Transaction is expected to close in September, 2016.
Further information regarding the transaction with ExxonMobil will be included in an information circular, which will be mailed to InterOil shareholders in due course. Copies of the key transaction documents for the ExxonMobil Transaction (being the arrangement agreement and the information circular) will be available online under InterOil’s corporate profile at www.sedar.com.
The InterOil board of directors, in consultation with its independent legal and financial advisors, determined that the ExxonMobil Transaction is superior to the previously announced transaction with Oil Search Limited (ASX:OSH, POMSoX: OSH) and so advised Oil Search on July 18, 2016. Immediately prior to entering into the arrangement agreement with ExxonMobil, InterOil terminated its previously announced arrangement agreement with Oil Search, and ExxonMobil is paying Oil Search the termination fee in accordance with the requirements of the Oil Search arrangement agreement on behalf of InterOil. The previously scheduled Special Meeting of Shareholders to vote for the approval of the Oil Search transaction has been cancelled.
Davis Polk & Wardwell LLP and Blake, Cassels & Graydon LLP served as legal advisers to ExxonMobil in relation to the ExxonMobil Transaction.
Credit Suisse (Australia) Limited, Morgan Stanley & Co. LLC and UBS served as financial advisers to InterOil in relation to the ExxonMobil Transaction, and Wachtell, Lipton, Rosen & Katz and Goodmans served as its legal advisers. Morgan Stanley & Co. LLC provided the InterOil board with a Fairness Opinion.
Disappointing EIA DataThe large product stock build added to the market’s worry about excess light product stocks undermining crude demand and ultimately reducing the size of crude stock declines. While PIRA sees crude stock declines accelerating onshore U.S., with this week’s EIA data showing 630 MB/D stock decline, the market is, not surprisingly, skeptical given recent EIA reports and the crude weakness in Northwest Europe and Asia. Oil markets are stuck in a $43-$53/Bbl trading range, and visiting the lower end on occasion is to be expected, especially with lots of fear and data like the July 13 EIA report.
The market is having second thoughts about the industry’s ability to cope with surplus supply despite the atypical heat expected to persist well into the second half of July, as suggested by NYMEX futures brief expedition to ~$3.00/MMBtu and subsequent V-shape reversal back towards ~$2.70/MMBtu. Thursday’s relatively flat price action following a neutral-to-consensus stock build further reinforced the market’s at least temporary hesitation to push prices back toward those July highs. Indeed, weather forecasts and projected seasonal restocking in July certainly appear favorable to sentiment; a post-summer acceleration in refills has called into question the viability of $3.00/MMBtu gas during the upcoming shoulder season.
U.K. winter power prices have jumped in response to the recent tumultuous development in NBP prices, but spark spreads have softened in the past 10 days or so, in spite of the latest Winter Outlook by National Grid confirming that the power market will remain exceptionally tight.
Coal prices shot up last week, with all three major forwards tacking on $3.00/mt or more across the curve. Higher oil pricing, more positive signals coming out regarding Chinese coal demand, and stronger European gas prices all factored into the strength in coal pricing last week. FOB Newcastle (Australia) prices rose by the greatest extent, perhaps due to increased buying activity out of China and weather-induced cuts to Indonesian exports. PIRA would not be surprised if the rally in pricing starts to fade, as additional support on the fundamentals side will be needed to keep prices on an upward trajectory.
Near-term EU ETS fundamentals are poor, but no worse than they were before the Brexit vote. EUA prices rebounded after the January 2016 price decline (which was far more severe) and could do the same now. Auction demand data from June was somewhat positive, and there is historically a price bump in August, when auction volumes are lower. Also, the currency impact from the Brexit vote results in lower compliance costs for U.K. coal-fired generators, potentially supporting emissions demand. However, there is increased market uncertainty.
Chinese economic data for the second quarter surprised on the upside — GDP growth came in above expectations; the manufacturing sector appeared to be picking up steam; consumer spending expanded solidly; and the housing sector remained red-hot. Data on total social financing and local government debt indicated that policy makers have maintained an easy stance on credit creation. In the U.S., growth in consumer spending accelerated in a major way during the second quarter, but other sectors were more subdued. Industrial production disappointed, though capital-intensive manufacturing industries reported encouraging results. The latest inflation data did not set off an alarm bell.
Asian LPG prices were lower last week, with front-of-the-curve contango spreads flattening, indicating that markets are less optimistic of autumn price gains than they had been previously. Cash continues to trade at a significant discount to paper, with August physical Far Eastern propane being called near $310/MT, some $15 below futures. Butane continues to trade narrowly above C3, ending this week at just $14/MT above propane — the tightest premium thus far this year.
Manufacturing margins reach 18-month peak. RIN values soar.
Traders inherently love this sort of volatility, but it’s plainly obvious that these moves, overnight especially, have many backing away. This should continue to be the case in corn until early August, when pollination is close to being finished. For beans, we expect the volatility to continue until at least the end of August as late-August/early-September moisture will make or break this year’s crop. PIRA always believes that fundamentals will win out, but it’s going to be a long and wild ride until true fundamentals take over once again.
Crude runs rose again on the week as maintenance continues winding down. Crude imports eased slightly, but crude stocks still built 0.3 MMBbls. Finished product stocks built 2.1 MMBbls, with increases in all the products other than gasoil and fuel oil. Refining margins have remained poor with little barrel support other than fuel oil and naphtha.
Last week’s regional election in Japan brought to power a decidedly anti-nuclear governor in the very region that houses the only two operating nuclear power reactors in Japan, reigniting questions as to the future of Japanese nuclear power generation. While this development is a decidedly bullish one for Japanese LNG imports, it is unlikely that even a completely nuclear-free Japan will result in a resurrection of Japanese gas demand for power generation.
With the release of the report to the French minister Ségolène Royal on "Proposals for the Carbon Price," together with the Minister's press release of July 11, the French domestic carbon floor is now shaping up as a tax on coal. Assuming the policy starts from Jan. 1, 2017, which is looking optimistic, French 1Q 2017 baseload contract is well priced in the mid €30/MWh and the 2017 annual baseload contract is well priced in proximity of €32/MWh, or €2/MWh below our latest outlook, in line with current market quotes. In the medium term, the decision to penalize the coal units poses risks of earlier coal closures, making the French system more vulnerable during the winter months (similar to the U.K.). In addition, the revised policy still leaves unsolved the longer-term issue of the needed investments in EDF's existing nuclear units.
Draft amendments include a tightening of the cap post-2020, adjustments to the Price Containment Reserve and provisions for unsold allowances — and do not appear to send overly ambitious market signals. After 2020, the Price Containment set-asides are smaller, leaving more of the cap readily available to sources. The high single price tier for Reserve allowances demonstrates that CARB does not expect it to be a factor in regular pricing. The proposal to move unsold allowances to the Price Containment Reserve takes into account the quantitative limits on their return to auction. Quebec is, and Ontario soon will be, a partner in this market, and California policies are looking to serve the broader market.
The S&P 500 set a new record on the week. The strongest gains were posted by the banking index, along with materials, while the “growth” indicator far surpassed the “defensive indicator." Only the defensively oriented utilities tracking index declined on the week. Internationally, all the tracking indices advanced, with Latin America, emerging markets, emerging Asia, China and BRICs all out surpassing the gains seen in the U.S.
Inventories draw, decreasing in four of five PADDs, but there was a large build in PADD I. Output of ethanol blended gasoline dipped to the lowest level in a month.
After jumping 17%, to 32% last week, corn silking should increase at least that amount again for the week ending Sunday, July 17th. The heat is on this week, but the percentage released this afternoon should have pollinated in fairly benign temperatures in the "I" states and Minnesota, according to mean deviation statistics for the first half of the month.
Recent press reports suggesting that bolt failures could cause significant production shutdowns appear to be overstated. There have been a number of failures of bolts that are used to connect blowout preventers, risers, and other subsea equipment in the Gulf of Mexico since 2003. A task force, with representatives from the U.S. Bureau of Safety and Environmental Enforcement (BSEE), API, oil industry and manufacturing companies, is currently reviewing the root causes of the failures and developing a strategy to fix the existing problems. For producing platforms/structures, fixing the problem may require shutting in production for several days to replace the defective bolts. However, it appears at this time that the issue affects primarily drilling operations and to a much lesser extent existing production.
Both the Netherlands and the U.K. are shifting toward market balancing that will rely more on higher seasonal imports and working gas storage. As of now, the way these two markets are managing this inherently riskier position could not be more different. Operating problems in U.K. storage at Rough have created a vast winter risk premium, so vast that PIRA has a difficult time seeing it sustained on an outturn basis. The U.K. will certainly need to rely on more Continental, Norwegian, and LNG supply this winter. As we have emphasized in past years, the U.K. counting on Continental storage to balance some of its peak needs is often at odds with the mandate of Continental storage owners to place the home market as a greater priority no matter how full storage may be. This risk has been particularly egregious in the fourth quarter, given the Continent’s tendency to hoard storage volumes just in case the first quarter produces colder-than-normal weather. Add in real and perceived Brexit fallout and one has to assume the risks to the U.K. are somewhat greater.
Following temperatures and gas markets higher, June on-peak energy prices rose month-on-month in nearly every market in the Eastern Interconnect and ERCOT. Gas prices continued to rise through late June with Henry Hub spot topping the $2.90 mark as the July NYMEX contract expired. Eastern coal prices have also seen a modest advance, but western markets remain weak with supply rebounding. A gas price recovery over the balance of 2016 also implies that heat rates will likely struggle to keep pace with the high levels set in 2015. First half of 2017 is also likely to have lower gas burn and heat rates year-on-year in most markets.
In our 2016 Reference Case, PIRA increased its projections for BEV market growth which reflects greater progress in battery development. In this report PIRA analyzes lithium-ion batteries and examines lithium and cobalt, the raw materials crucial to lithium-ion battery production, and find that in the near term, supply shortages for lithium are possible, but long-term supply for lithium should be available at reasonable prices. Cobalt supply is more difficult to predict, but it appears more likely to be volatile than lithium in both the short term and the long term. Overall, PIRA’s expected EV market penetration rate should not be hindered by a lack of raw materials used in battery production.
Riding on continued efficiency gains and modestly improved prices, producers in Canada grew output by 4% quarter-on-quarter, or ~550 BCF in 1Q16. Production gains were strongest in Alberta and British Columbia; the former reached highs not seen since 2010, and the latter set new records in quarterly volumes. Both the companies within and outside of the surveyed “PIRA Group” grew production, although this quarter, the non-group significantly outpaced the survey group.
The S&P 500 set a new record high. Again, volatility declined and emerging market debt prices rose sharply. Financial stress continued to lessen post-Brexit. The dollar was mixed on the week.
Britain's shale gas industry could get a helping hand from a falling pound and a supportive new prime minister just as it is gearing up for its first production this year, after facing economic and political challenges that slowed its start. The British pound's weakness since the Brexit vote has made it more expensive to import gas, helping the case for shale gas, which had been hurt in the past by weak oil prices and by opposition to planning approval from local campaigners.
The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.
Laden by corruption scandals and falling oil prices, Petrobras is struggling to repay $130 billion (bn) worth of debt – nearly $24bn will mature by 2017. Efforts to sell non-core assets (pipelines, powerplants, bonds etc.) have been slow going and any attempt to divest upstream operations impeded by red tape. Mandatory operatorship (30%) for Petrobras in the pre-salt basin not only limits the company’s options for raising cash from existing upstream assets but also increases the NOC’s capital outlay. Foreign investment in upstream operations has been made less appealing due to Brazil’s unitization rules, which can make outside operators susceptible to additional financial risks.
Offshore Brazil was once known as a “safe haven” for oil field service companies, yet almost half of all indigenous companies are now facing insolvency issues according to KPMG (e.g. Queiroz Galvao, OGX). Macro-economic factors, inefficiencies (low quality of goods and services, failure to fulfil contract deadlines etc.) and stringent local content rules have created a number of obstacles to growth in the sector.
However, despite these challenges, new opportunities may emerge as the national government and Petrobras re-think the O&G industry’s growth strategy. In early 2016, the government launched the ‘PEDEFOR’ program – relaxing local content rulings and incorporating new financial incentives for foreign companies. The response from industry participants has been largely positive – with Aker Solutions opening another subsea manufacturing center in April 2016.
As Petrobras puts upstream assets (Bauna, Golfinho and Tartaruga fields) into the market, it appears further amendments to pre-salt requirements and licensing methods may take place. If implemented, these changes could lead to another wave of foreign investment. Drawing parallels to the mooted IPO of Saudi Aramco, NOCs are beginning to reevaluate their relationship with both national governments and foreign E&P investors. In the current price environment, experimenting with various options and methods of collaboration is likely to be the most sensible approach to dealing with the challenges of today’s oil & gas market.
Chen Wei, Douglas-Westwood Singapore
Current Prices Near Lows Even Though Surplus Stocks Revised HigherGlobal macro landscape is brighter, especially with dovish central banks. Oil market rebalancing has temporarily stalled in 3Q16, but it should resume strongly in 4Q with much more robust demand growth. Global supply is declining with sharp declines in non-OPEC crude/condensate more than offsetting increases in non-crude liquids and OPEC crude production. Prices are currently too low and should rally from here. Political risks to supply have turned higher. U.S. crude exports should pick up and contribute to substantial U.S. crude stock draws in August and September. Refinery margins will be weak this autumn as ample light product stocks will be slow to work off.
Conventional wisdom suggests that the cure to low natural gas prices ultimately rests with producers. Yet, despite the record slump in cash prices, Canadian production appears to be defying convention, increasing ~0.3 BCF/D year-on-year during the first half of this year, with producer and midstream companies guiding toward a relatively stable supply outlook ahead. Robust Canadian production underscores the general resilience of North American supply, with slowing WCSB production growth more than offsetting declines from other conventional resources. In contrast to the Lower 48, where take-away pipeline has limited shale growth, only modest declines are taking hold this summer with Canadian production poised to rebound this winter.
An unusually high number of French nukes are offline for maintenance, bringing the load factor of French nuclear down to a multi-year low during July. Assuming nuclear stays at minimum levels of the historical range would bring French prices up to the low €40/MWh during the winter months. The current proposal of the carbon floor is shaping up as a penalty on coal units, which would have a very limited impact on shorter-term prices, but it increases the risks of retirements. The risk of plant closures, with oil units already being retired, makes French prices more likely to move toward Spain and Italy in the medium term. We see the UK market unable to balance for at least 90 hours in the upcoming winter, without calling CBR. Base and peak spark spreads for the winter ahead have surged in anticipation of these risks.
There is wide range in views on the optimal price of carbon — often based on price levels needed to achieve emissions reduction goals. U.S. government estimates of the social cost of carbon utilize a methodology based on academic models that calculate avoided damages. Already used for federal cost-benefit calcs, more recently these estimates have been used in international agreements, for state-level policy, and as a carbon price standard with commercial implications for energy market players. PIRA's report discusses how the social cost of carbon is calculated and used and how modeling choices lead to an estimate that reflects political realities as well as scientific calculations. Implementation of carbon prices generally ends up well below estimates of carbon’s social cost.
While most traders remain focused on production estimates for U.S. corn and soybeans, the wheat market quietly made a 10-year low of $4.035 for the prompt contract last week, and quietly is exactly the way the Non-Commercial shorts like it. The Non-Commercial short in SRW is quickly approaching 145K contracts according to last week’s COT, while the HRW short is nearer 37K contracts. Depending on how you look at some of these numbers the SRW short is probably the third largest in history and may even be at a record currently.
The latest U.S. GDP release disappointed, as it showed the pace of year-on-year economic growth slowing in recent periods. But underlying data suggested that a growth pick-up will materialize soon — after all, a large portion of the recent weakness was due to an inventory drawdown, and this will not continue; and outside of business investment, key activity sectors are in good shape. In the euro area, the pace of second quarter GDP growth matched expectations, and the resilience in business confidence surveys paints an encouraging picture for near-term growth. In South Korea, second quarter growth exceeded expectations, and a recent strengthening in industrial activity is encouraging for the outlook.
Rates in all the major tanker sectors in July have already hit or are fast approaching 2016 lows. Rates are unlikely to improve before the fourth quarter, although fleet capacity growth this year will also limit prospects for a meaningful winter rally.
U.S. ethanol manufacturing margins worsen. RIN generation increases. D6 values near $1.00.
Far East destination markets are rioting against an avalanche of LPG supply in-flows. Cash propane and butane cargo prices plunged last week, well below the newly printed Saudi Contract Prices. The prompt paper arbitrage to the Far East from the Arab Gulf plunged to near zero, indicating that even if freight was free, little money could be made by bringing cargoes to the region. Even more troubling, cash Far East prices are performing even worse, with physical C3 and C4 being called well below August CPs. PIRA believes that the recent glut may be partly due to the recent opening of the new lock system at the Panama Canal. Asia is now being barraged by USGC cargoes, arriving from both the east and west, and canal cargoes (with their significantly shorter voyages) are arriving before cargoes that set out earlier on the Horn of Africa route.
Crude stocks disappoint again, showing a 1.7 million barrel build as imports approach high of year at 8.44 MMB/D. Cushing crude stocks have largest build (1.1 million barrels) since early May. Reported product demand continued to improve, rising 150 MB/D on the week to a strong 20.8 MMB/D.
The prospect of new record-high storage in the U.S. and western Canada raises the risk for a “hard landing” for prices this season. While it appears unlikely that the market will once again probe sub-$2 prices, weakening fundamentals are at odds for sustained $3 prices — with the likelihood of a relapse looming ahead.
On-peak price levels and volatility soared in July amid strong cooling loads. Palo Verde on-peak prices averaged above $40/MWh, up more than $10/MWh from June. Mid-Columbia also gained $10/MWh to average in the low $30s. California hubs saw more modest ($5-6/MWH) gains to the high $30s. Bullish price action at the front of the curve has had relatively little impact on price forecasts with the exception of Palo Verde, where we believe a more bullish stance is justified, particularly for spring/summer 2017. In the near term, however, prices and heat rates are likely to ease as short-term weather forecasts indicate below-normal temperatures in the inland Southwest. In contrast, California heat rates are likely to increase as the call on gas generation reaches its annual peak in August/September amid ongoing gas storage constraints.
The S&P 500 was little changed on the week. Volatility remained low. Emerging market debt and high yield debt pulled back on the week. The dollar was generally weaker, particularly against the yen. It was noticeably stronger against the Russian ruble.
Cape demand is being boosted by improvements in 2Q16 Chinese steel industry numbers and the expansion in Guinean bauxite trade to China. Cape utilization is set to tighten notably in 2H17 and into 2018. Along with stronger bulker prices, PIRA expects a surge in freight rates in 2H17.
Emissions from aviation make up a small share of total global emissions, but they are growing quickly. The International Civil Aviation Organization is expected to unveil a program to keep post-2020 emissions at 2020 levels at its upcoming triennial assembly in September. PIRA estimates that, based on the most recent draft, it could cover at most 60-65% of total global aviation activity — requiring around 2 billion metric tons to be offset between 2021-2035. The main UNFCCC offsetting mechanism (CDM) should meet demand for offsets, but supply risks are related to the need to avoid double-counting of emissions reductions. Compliance costs are expected to make up a small share of jet fuel prices.
The week ending July 22, stocks draw to less than 21 million barrels for the first time in seven weeks. Production drops to 988 MB/D, falling from a record 1,029 MB/D the prior week.
Year-over-year price action similarities in corn have been hard to ignore. Last year, Dec. ’15 corn made a high of $4.5425 in early July. This year’s high of $4.49 was made in mid-June. Last year’s selloff was 97 cents from the highs. This year’s selloff, so far, has been 115.75 cents. Not a perfect match either timing-wise or price-wise, but close enough that a look at last August’s price action is warranted as July comes to a close.
Crude runs rose 81 MB/D on the week, reflecting the restart of Hokkaido. Refinery capacity continues to look underutilized, which suggests discretionary run cuts are occurring. Crude imports moved higher and crude stocks built 1.45 MMBbls. Finished product stocks built by 0.9 MMBbls, mostly due to a rise in naphtha. Refining margins remain very poor and should be inducing discretionary run cuts.
Although the forecast heat will likely limit August stockpiling for the first half of the month, less constructive fundamentals developing in the second half increases the risk of regional congestion. The prospect of new record-high storage in the U.S. and western Canada raises the risk for a “hard landing” for prices this season, with the month-on-month gains recorded in July likely reversing by September.
The emerging growth in Australian LNG output will make less and less room for other LNG supply to push its way into Asia from distant regions. Australia is still only producing 160-mmcm/d (up 90 mmcm/d year-on-year) and remains at a mere 51 % of the total production capacity (315-mmcm/d) it will have in place by 2019.
EIA just released its final monthly May 2016 (PSM) U.S. oil supply/demand data. May 2016 demand came in at 19.20 MMB/D, which showed growth of 85 MB/D, or 0.4%, versus year-ago. Gasoline, kero, and resid all outperformed. Distillate and “other” underperformed. Versus the weeklies, demand was revised lower by 1.1 MMB/D, with "other" revised lower by 627 MB/D, distillate lower by 257 MB/D, and gasoline lower by 213 MB/D. This comes on the heels of an 800 MB/D downward revision in the final April figures, when reported last month. Versus PIRA's Reference Case outlook, May is 450 MB/D less than forecast. End-May total commercial stocks stood at 1,384.1 MMBbls, which was 17.2 MMBbl higher than the preliminaries and 20 MMBbls higher than PIRA had assumed in its balances.
Thursday’s lighter-than-expected U.S. storage build, coupled with an anticipated single-digit addition to inventories for next Thursday’s report, should register as the lightest additions to working gas inventories for the remainder of the cooling season. These relatively low builds have helped propel the newly minted prompt contract beyond $2.90/MMBtu but bely weekly injections thereafter that could easily average 35-40 BCF, as cooling degree days seasonally decline in August.
In the face of sharply warmer-than-normal cooling conditions across most of the eastern and southern U.S., PIRA estimates that U.S. coal stocks are near flat year-on-year at 156 MMst. Though this remains above-normal target levels, some regions are drawing very close to normal seasonal target levels.
Global equities were modestly mixed on the week. Outside the U.S., the markets moved, on balance, higher. The international sectors were led by Japan and Europe, though Norway declined as oil prices weakened. In the U.S., the market was largely unchanged, though technology, retail, and housing moved noticeably higher. Energy lagged and declined on the week.
PIRA's latest update of Asian product demand shows a slowdown in growth from last month but still strong. The deceleration is concentrated in both China and India, but other Asian countries showed improvement, with either stronger growth or smaller year-on-year declines. Data actuals cover the three month period April-June for China, India, Korea, and Japan so this snapshot picks up the most timely data in the largest countries. Overall Asian demand growth slowed from 1.35 MMB/D in the June assessment to just over 1 MMB/D in the latest snapshot.
“New natural gas prices for industrial consumers and other business entities have been increased by 9% on average compared with the prices in June-July 2016, taking into account the price situation on the European natural gas market,” Naftogaz reports. The natural gas prices from the company’s resource are differentiated depending on the volume of purchases, payment conditions and the state of previous payments.
Despite weaker oil prices, the coal market rallied strongly this month. A sizeable drop in China’s domestic coal production from planned curtailments and wet weather saw its thermal coal imports increase again year-on-year in June, while exports supply from other major producing nations has been held in check largely by the weather. PIRA continues to believe that 2017 prices are undervalued despite the increase in pricing this month as stronger oil prices next year will push the curve higher.
Saudi Arabia's formula prices for September were just released. Prices were cut most aggressively to Asia, while U.S. customers saw cuts on the two lightest grades. Prices for delivery into Northern Europe were raised on all grades but the lightest, Arab Extra Light. The adjustments reflect weaker refining economics and narrower light product cracks, particularly in Asia, while the increase in Europe reflects a narrower discount on Urals vs. Dated Brent. The cut in the U.S. was in keeping with a narrowing of the LLS-Mars spread. The bottom line is that Saudi Arabia continues to respond to market conditions so to maintain its market share.
Seasonal gas demand will reach its low point in August, which will relieve some of the pressure on prompt prices and offer additional options for injecting gas on the Continent. Despite this, the run-up in gas prices has not turned away power sector gas demand, helped by strong coal and poor availability of the French nuclear fleet. Power production across France is up by 90% year-on-year in July. Breaking this down by gas grid, we are seeing a 60% rise in PEG-Nord power plant production and an amazing 340% rise in PEG-TRS production. This is particularly amazing given that southern French gas prices have been trading 7% higher, or €1.07/MWh, than their northern neighbors.
The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.
Refinery Margins Soften and Focus Shifting from Gasoline to DistillateOil prices have moved lower in their current trading range on bearish news, but they will increase as the global stock surplus falls significantly in 2H16 and 2017. Refinery margins have softened and may prompt some trimming of discretionary runs, especially this autumn. Product stock levels are high with gasoline inventory coverage relative to local/export demand near the top of the historical band. Middle distillate stocks are well above their historical range, but rising seasonal demand will tighten inventory in terms of days of supply forward coverage. Product markets are getting an early start on the seasonal price shift from gasoline toward distillate, with gasoline cracks starting their seasonal decline earlier than normal. Diesel cracks will gradually recover and take the lead from gasoline.
A stout national cooling degree-day (CDD) count (more than 10% higher year-on-year) has spurred an expansive role for gas in electric dispatch this month, enabling further recovery in cash prices. To be sure, widespread heat and a host of supply-side maintenance issues culminated in setting the ~$2.80/MMBtu month-to-date price for Henry Hub (HH) deliveries. Yet, despite the one-two punch of weather-aided demand and production disruptions, only a few regional price points managed to outpace the benchmark, with the vast majority significantly underperforming. Generally, during July regional prices have displayed similar discounts recorded last month.
After a number of strikes hitting output during June (- 3 GW year-on-year), French nuclear output has further deteriorated in July, hitting a low since at least 2012 and leading to a sharp contraction in French net exports and higher utilization of French gas units. The detection of an anomaly in the steam generators channel head is also contributing to undermine availability and will continue to do so in the upcoming months, as outages are likely being extended. In a PWR reactor design as for the EDF units, the replacement of the steam generator channel head can be done during a planned outage, typically lasting from one to three months, whereas a typical shutdown for refueling, which is carried out once a year, takes only 35 days. For the time being, for the units that are not offline and are being affected by this specific anomaly, a temporary solution is likely to be a steadier operation of the plants.
Stronger weather-driven power demands and an upward shift in natural gas forwards has boosted our coal burn expectations. This is offset in 2016 by increased coal production levels in the quarter just ended. In 2017, however, we are projecting growing tightness in the PRB, as a call on incremental coal supply may be challenging to meet.
Spot VLGC freight rates have plunged to new cycle lows below $24/MT on the benchmark Ras Tanura to Chiba, Japan, route. Freight rates on these vessels are now trading well below breakeven economics for even the most efficient operators. Rates look to continue to suffer for the foreseeable future as the trinity of peaking LPG trade, rising tonnage, and the expanded Panama Canal plagues these freight markets.
Manufacturing margins decrease the week ending July 15. RIN prices slide after peaking Monday.
The S&P 500 continued to push to new highs. Again, volatility declined and high yield debt prices rose. Emerging market debt prices, however, pulled back after having posted strong gains in the previous weeks. The dollar was generally stronger. The Turkish lira was noticeably weaker in the wake of the failed military coup. Commodities were mostly lower, both total, energy and ex-energy.
The situation in Libya shows no real improvement despite the recent swell of optimism over a near-term ramp in Libyan crude production. On July 7, Ibrahim Jathran, commander of the central Petroleum Facility Guards (PFG), announced exports would resume from the long-shuttered Es Sider and Ras Lanuf terminals within a week. The military push to clear ISIS out of the region near Sirte has also been making territorial gains. However, the announced merger of the two rival NOC’s seems to have broken down. PIRA acknowledges the possibility that terminals may reopen shortly. But in our view, the chaotic political and security situation could derail any production gains just as quickly. The UN-backed unity government (the GNA) has been unable to exert control, stark divisions remain between the rival governments and their affiliated militaries, and the myriad of militias on the ground will act in their own interests.
The 5th Circuit Court has decided that they (as opposed to the more EPA-friendly DC Circuit) are the appropriate venue to decide legal challenges to EPA’s TX Haze FIP that would have required costly scrubbers on 14 coal units. They also stayed implementation of the rule, offering a good preliminary sense that the Court has issues with EPA’s arguments and approach — as PIRA has been highlighting. This decision comes on the heels of EPA’s final One-Hour SO2 designations, where EPA declined to take action on four areas where Texas coal plants were proposed to be in Nonattainment, offering an environmental reprieve for coal/lignite units in Texas and pushing off any near to mid-term expectations of EPA-induced retirements.
Oil market rebalancing continues, but initial onshore stock decline has been less visible. India’s oil demand remains strong but with growth easing in 2H16 due to a heavy monsoon season and moderating economic growth. China’s net exports of gasoil, jet fuel and gasoline is set to increase by some 25% from last year. Asia embraces crude supply diversification with rising crude imports, but the share of Middle Eastern crude imports in the region is expected to remain high as Middle Eastern countries will strive to maintain market share. Asia-Pacific net crude imports are expected to rise in 4Q16 and 2017. Asian refinery margins are expected to stay modest due to high product inventories.
The strong move upwards in 1Q17 pricing is not just a story of NBP overreaching to the upside, but is a story of how the Continent is not. Spreads in the first quarter of next year have widened by over €1/MWh — meaning, the Continent is showing confidence that the U.K.’s tightness is a local story not a Continent-wide one. PIRA believes that this confidence is well-founded and will eventually lead to a significant move downward in winter pricing.
The coal market moved lower last week, on the back of weaker oil and gas prices and perhaps a hangover from the sizeable rally observed in the prior few weeks. The decline in pricing was particularly acute in the Atlantic Basin, while FOB Newcastle’s (Australia) price declines were more muted. With China’s import demand showing signs of strength, exacerbated by wet weather impeding production in some key areas, it is not surprising that FOB Newcastle prices have held up relative to API#2 and API#4. The weather-related disruption to China’s production (on top of the drive to rein in overcapacity) skews the risk to the upside for FOB Newcastle over the next 90 days.
Global equities moved higher on the week, with gains concentrated in the Americas, of which the U.S. and Brazil performed the best. In the U.S., the strongest sectors were retail and technology, while energy was the worst performer. Internationally, Latin America did the best, while China and BRICs also outperformed.
U.S. ethanol production jumps to an all-time high of 1,029 MB/D for the week ending July 15, breaking the previous record of 1,008 MB/D set last November. Inventories were slightly higher.
Latin American product demand is improving but is still down year-on-year. Consumption of the four main refined products trends higher in 2H16 but lag 2015 levels. PIRA forecasts that 3Q16 gasoline demand will be lower year-on-year but higher vs. 2Q16. Diesel demand in 3Q16 is expected to be below 3Q15 but higher than 2Q16. Regional refinery crude runs still disappoint with 3Q16 by ~70 MB/D lower than a year ago.
The tighter balances that have fueled price support in Asian and European spot markets are simply not sustainable. The less ramp-up that occurs in 2016, the more ramp will occur in 2017. The possibility of Asian supply reaching the Atlantic Basin in the year to come cannot be dismissed, particularly if Nigerian and Angolan production continue to run into operational problems. Length in Asia balances will easily front run any tightness in the Atlantic Basin. It will be more apparent when Qatari volumes begin to shift west.
Economic data out of the emerging world have turned stronger of late. Encouraging signals include: trade volumes turning positive on a year-on-year-basis; widespread improvements in industrial sector output; solid readings for vehicle sales; and constructive financial sector sentiments. In Europe, a preliminary July business confidence reading suggested that the Brexit decision has not yet disrupted economic activity. Next week’s economic calendar is filled with significant events.
The U.S. GHG Inventory shows 2014 emissions up year-on-year but down 7% vs. 2005. It does contain large write-ups to historic methane emissions from oil and gas production and landfills. Methane regulations for oil/gas and landfill sectors have been finalized, a draft technical report for the auto CAFE review has been published, and an endangerment finding for aviation and an international agreement on HFCs are expected later this year. The U.S., Canada and Mexico set a challenging regional goal of generating 50% of electricity from non-emitting resources by 2025. 2016 elections will impact the survival of the Clean Power Plan and the arc of climate policy for the next four years. PIRA revised our long-term federal carbon prices/costs expectations given the CPP stay.
Product demand strongly rebounded this past week, narrowing the product stock build, while crude stocks fell less than expected despite very high crude runs as imports stayed elevated. Light product imports were very high and these should substantially decline in next week’s data. Cushing crude stocks were up slightly and month to date are roughly flat and near our forecast. Another small build is expected next week. PIRA is forecasting continued strong light product demand for next week, which should cause major light product stocks to show a slight draw. Crude stocks decline sharply next week as runs stay high and imports back off.
PIRA does not expect autonomous vehicles (AVs) to have a meaningful impact on the oil, electricity demand or emissions outlooks over the next 20 years. Fully autonomous vehicles, which would allow the driver the flexibility to pursue other activities, are still likely at least a decade or more away from a technology standpoint. If and when this technology arrives, its impact on gasoline demand is not clear cut. If there is a synergy between AVs and electric vehicles (EVs) it could accelerate electrification of the fleet, for both cars and some trucks. It may also improve the fuel efficiency of the operation of vehicles. However, the impact on miles driven could very well be positive, particularly if there is substitution for some portion of train, plane or public transport travel.
Commercial gas production from the Jubilee field, which is processed at the Ghana National Gas Company’s gas processing plant at Atuabo raised the prospects of a price war in the supply of gas for power generation when it debuted on the market last year. However, the Atuabo gas is now one of the priciest in the world — even more expensive than its regional competitor from Nigeria, the West Africa Gas Pipeline Company (WAGP). This year it is estimated that the Atuabo gas price will remain uniform but that of the average annual delivery price of WAGP gas to Volta River Authority (VRA) will drop slightly.
Crude runs rose slightly on the week as maintenance continues winding down. Even so, capacity looks underutilized, which suggests discretionary run cuts are occurring. Crude imports fell to low levels and crude stocks drew. Finished product stocks also drew. Refining margins have remained poor with little barrel support other than fuel oil and naphtha cracks.
In assessing where the costs of oil are likely to head in the future, it is extremely important to distinguish trends from cycles. Historically, costs to operate existing oilfields and to develop new supplies correlate closely with oil prices. Using the Bureau of Labor Statistics (BLS) Drilling Oil & Gas Wells Index as a proxy for cost changes, our model predicts deflation may be about over with costs expected to increase in 2017 in line with an expected increase in oil prices. A similar cycle took place in 2008-2010, when prices collapsed in late 2008 and started to recover in mid-2009. The model also predicts continued increase in costs as prices continue to rise.
Policy developments over the past quarter were mixed. A federal judge ruled the Bureau of Land Management (BLM) overstepped its authority in its proposed fracking regulation on federal/Indian lands. The Colorado Supreme Court decided that municipalities can’t ban fracking. The North Yorkshire council approved a permit to frack a well in the United Kingdom. On the other hand, the EPA issued new methane standards although implementation costs are expected to be non-material, Pennsylvania passed sweeping new oil and gas rules, and the EPA’s SAB has decided its draft study that concluded fracking causes no systemic adverse impacts on drinking water needs quantification. Going forward, we expect limited federal policy changes as the current administration comes to an end and a continuation of generally favorable state policies, particularly with the sector financially struggling.
Deferred futures are currently below long-run equilibrium levels because producers are under pressure from their bankers to hedge future production. To search out speculative interest for this supply of paper futures, producers are selling future production below long-run equilibrium values. As long as this forced selling persists, the burden of raising deferred futures will fall on speculators. As the balances tighten and surplus stocks are drawn down, there will be an increase in speculators' expectations and confidence that higher prices are justified. Backwardation will likely increase, although the back of the market will go up as well. This will continue until a long-run equilibrium between demand and supply is reached.
The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.
This year has seen US land drilling activities fall to the lowest levels on record. Globally we are seeing a very nuanced and regional reaction to the current oil price downturn. Examination of the global land rig fleet (which Douglas-Westwood tracks on a rig-by-rig basis) reveals some key themes.
Having dominated the global land drilling market for living memory, the number of US rigs drilling has been eclipsed by activity in other regions. In terms of absolute rigs working, Eastern Europe and the Former Soviet Union now occupies the top spot.
In terms of rate of growth (or otherwise) there are other bright spots of activity. Activity in the Middle East has remained robust and a 2% growth is expected in 2016. This compares to a 49% decline this year in the US. The comparative robustness of NOC spend is also evident in the rig data. We see that current NOC operators are responsible for 34% of the identified fleet vs 31% a year previously.
Like the operators, rig contractors themselves are focused on free cash flow. Efficiency of operations and uptime are critical, and key rig components are being recycled from one rig to another to minimize spend on new hardware. Where new rig components are required, our clients are reporting a trend towards increasing adoption of Chinese-manufactured parts. Efficiency and safe operations are also boosted by the continued uptake in automated rig equipment.
Older and less efficient rigs are being scrapped. Our data suggests that 16% of the North American fleet has been scrapped since January 2015.
Whilst we do not expect activity levels to return to the highs of 2014 anytime this decade, we do anticipate recovery from the present levels (just over 3,400 rigs) at a compound rate of 8% to reach over 4,700 by 2020.
Michael Green, Douglas-Westwood London
BHP Billiton has outlined its value-focused approach to exploration which will see the Company target opportunities across copper and oil to enhance its long-life, tier 1 portfolio.
Speaking at Citigroup’s Mining Exploration Day in Sydney, BHP Billiton Head of Geoscience, Laura Tyler, said the Company is focusing its exploration approach through targeted analysis and the establishment of a Geoscience Centre of Excellence.
Ms. Tyler said exploration is seen as a key source of value creation for BHP Billiton.
Laura Tyler, Chief of Staff, Head of Geoscience. Photo credit: BHP Billiton
“We are investing at a time when most in our sector continue to reduce discretionary spend,” she said.
“Next financial year, we intend to invest approximately US$900 million dollars in exploration, which represents 18 per cent of our overall capital budget.
“We are also challenging existing paradigms with a scientific based and disciplined approach to exploration. We have reduced exploration operating costs by 70 per cent since 2013, and this year we have increased the targets tested by 44 per cent.”
“Over the last four years we have developed a new approach to Petroleum exploration that is much more focused,” Ms Tyler said.
“We have commenced drilling in Trinidad and Tobago and have secured an additional rig which will soon commence drilling in a prospective block north of our Shenzi operations in the Gulf of Mexico.”
BHP Billiton’s Copper exploration program is targeting tier 1 greenfield mineral deposits, with a particular focus on:
copper porphyry and skarn deposits in Chile, Peru and the south west of the United States,
sedimentary hosted copper deposits in the north of Canada, and
Iron Oxide Copper Gold deposits in South Australia’s Stuart Shelf, adjacent to Olympic Dam.
“We execute our Copper exploration both directly and through investment in joint venture opportunities and we continue to seek partnerships with junior explorers,” Ms. Tyler said.
The Company’s regionally based exploration teams are supported by a globally integrated geoscience team to facilitate a faster adoption of best practice and new technology.
“Internal collaboration is very important and we are leveraging our Petroleum business geoscience to identify prospective sediment hosted copper deposit basins,” Ms. Tyler said.
“Similarly, we are adopting technology from Petroleum and applying directional drilling techniques to copper exploration.”
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