NYC-based PIRA Energy Group reports that Cushing crude stocks build on tight LLS-WTI spread. In the U.S., there was a rare December stock build. In Japan, crude stocks drew at year-end and remained low as the new year began. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Cushing Crude Stocks Build on Tight LLS-WTI Spread
As WTI prices continued to fall in December, plunging another $17/Bbl, improved takeaway capacity lent support to Canadian and Rockies crudes. Narrower Gulf Coast grade differentials kept the Cushing-Houston arb firmly shut, which, along with year-end tax incentives, contributed to a very large stock build at Cushing. A tightening LLS-WTI spread (currently less than $2/Bbl) will ensure that Cushing receives a major share of the large first quarter U.S. stock build — with stocks likely approaching 80% of capacity by this spring.

Rare December U.S. Stock Build
The last time the United States built inventories in December was in the middle of the financial crisis in 2008. Preliminary weekly data are pointing to a 23 million barrel December 2014 inventory build, 9 million barrels higher than the December 2008 stock build. The way things currently look, the United States did not draw inventories in the fourth quarter, nor did the three major OECD markets combined. Not surprisingly, the "creeping" stock surplus has already become quite apparent, and there will be more to follow. This fear of what lies ahead is damaging to an already extraordinarily weak demand for inventory, which will have to cope with increased inventory supply. A rare bullish catalyst will begin with index rebalancing, which should lead to net new purchases of some 60 million barrels of crude, mostly Brent.

Japan Weekly Oil Data Updates through Year-End and into January 2015
Two weeks of data were reported this past week. Crude runs rose at year-end and then fell back. Crude stocks drew at year-end and remained low as the new year began. Gasoline demand jumped higher due to the holidays and then eased a bit. Gasoil demand was slightly weaker at year-end and then plunged as the new year began, with economic activity off for the holidays. Kerosene demand posted a strong draw at end-year and then a contra-seasonal build. Refining margins remain relatively strong.

U.S. Drivers Buying Less Efficient Vehicles with Lower Fuel Prices
Recent U.S. vehicle sales data suggest that, with lower fuel prices, vehicle purchasers are placing less importance on vehicle efficiency and are buying fewer hybrid and alternative fuel vehicles. Vehicle sales in 2014 have been very strong, and relative to 2013 a higher proportion of these vehicles are SUVs and light trucks, rather than cars. Even a short period of high sales of low-efficiency vehicles can have a long-term impact on fuel demand since vehicles remain within the fleet for longer than a decade — often much longer.

European LPG Price Rout Continues
European LPG prices swooned as the market adjusted to significant discounts in contract prices from Algeria and Arabian Gulf exporters. February propane futures plunged 11.3% to $302/MT, while cash butane was a remarkable 20% lower week-on-week. Large butane cargo prices, at under $280/MT, are back below those for propane, as cracker outages and low blending demand continue to plague the feedstock. Low demand and poor olefin prices will continue to pressure LPG in Europe. High prices relative to naphtha in Asia and expectations of lower Saudi contract prices in February will keep buyers on the sidelines for the time being.

Saudi Arabia Announces Pricing for February Barrels
Saudi Arabia's formula prices for February were released. Differentials to Northwest Europe were lowered across the board $1.40-1.70/Bbl, with the greatest reductions on the lightest grades. Asian pricing was raised across the board $0.55-0.70/Bbl. For the U.S., pricing was raised on Arab Heavy but lowered on all the lighter grades: Medium, Light, and Extra Light. The February differentials appear to focus on individual market pricing particulars as opposed to sending a message of expanding Saudi market share. Economics favored tighter differentials for Asia, while Europe continues to be plagued by an oversupply of Atlantic Basin crudes, hence the cut.

U.S. Ethanol Prices Continued to Pull Back at the End of Last Year
The fuel additive remained above gasoline values, although the premium narrowed. Manufacturing margins declined for the fifth straight week.

Ethanol Inventories Soar
U.S. ethanol production fell to an eight-week-low 949 MB/D the week ending January 2 from 972 MB/D during the preceding week peaking. Inventories soared by 751 thousand barrels last week to a 96-week-high 18.845 million barrels.

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.

NYC-based PIRA Energy Group believes that it is too early to get long oil. In the U.S., the stock surplus jumps. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

It Is Too Early to Get Long Oil
The bulk of the first-half 2015 inventory builds will be in crude oil. As crude inventories build, more expensive storage will be required, which will relatively weaken prompt prices; that is, widen the contango. This can only be mitigated by an increase in inventory demand from currently depressed levels. PIRA believes that such an increase in demand is unlikely to be strong enough to offset the weight of the impending increase in inventory supply. In such an environment, it is very difficult for prompt crude oil prices to rally.

U.S. Stock Surplus Jumps
The global imbalance between supply and demand compared to last year is vividly apparent in the U.S. stock data. From a 9 million barrel excess in 2013, beginning the fourth quarter, it has now expanded to 85 million barrels as of December 26. This is an increase of around 10 million barrels versus the week earlier. 2013 stocks decreased this past week while in 2014 they increased. Crude stocks are now 25 million barrels higher than in 2013, having begun the quarter 7 million barrels lower. From deficits last year beginning the fourth quarter, gasoline and distillate stocks are now higher.

Latin American Oil Market Report
Latin American refinery runs will increase in 2H15 driven by the startup of a new refinery in Brazil and the restart of revamped capacity in Colombia. Latin American product imports will level off, breaking the growth trend of the last few years. The U.S. will remain the primary supplier of products for import into the region.

Closed U.S. Refineries Contribute to Overall Downtime
Permanently closed refineries in the U.S. have had a significant affect in lowering crude run demand and subsequent gasoline and distillate productionLatest market developments..

India Quarterly Oil Demand Monitor
India's recent economic performance was somewhat disappointing, as GDP expanded by an estimated 5.3% during 2014. Growth prospects have improved, however, as lower oil prices will allow households and businesses to increase spending and the central bank to loosen monetary policy. Vehicle ownership continued to rise, in spite of stagnant sales. End-user oil prices dropped sharply in recent months, including those for diesel. PIRA projects a moderate oil demand increase of 130 MB/D (3.3%) for 2015. But upside potential is significant, given how declining prices boosted India's oil demand in the past.

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.

CGG notes the announcement made by Technip that it no longer intends to file a tender offer for CGG.

Since the beginning of this unsolicited approach by Technip on November 10, CGG remained open to dialogue and studied all proposals of Technip taking into account the interests of its shareholders, clients and employees. The board of CGG considered that none of the proposed options were creating value for the Company and its stakeholders.

CGG remains confident in the ongoing execution and the success of its strategy as an independent company. CGG is showing a solid resilient operational performance as highlighted in the third quarter results with important progresses achieved and milestones met in the transformation plan and the strengthening of the balance sheet.

With this plan initiated one year ago, accelerated and intensified during the year 2014 and with priorities given to cash generation, CGG is in a position to weather current difficult market conditions while fully benefiting from future geoscience market rebound.

With oil prices falling to a four-year low, the development of two frontier basins in northwest Europe, the Barents Sea and the West of Shetland (WoS), is likely to be postponed and further progress will require cost reductions, according to an analyst with research and consulting firm GlobalData.

Both Chevron and Statoil, operators of the WoS Rosebank and Barents Sea Johan Castberg fields, respectively, are continuing to delay their Final Investment Decisions (FIDs) for the projects, which have 240 and 545 million barrels of oil equivalent of recoverable reserves, respectively.

Matthew Ingham, GlobalData's Upstream Analyst covering Europe, states that the sanction of these projects is crucial to permitting the construction of much-needed infrastructure that will provide an export route for the region's hydrocarbons, of which there are thought to be vast reserves.

Ingham says: "The implications of plummeting oil prices will be felt most heavily by the UK and Norway's governments, highlighting the ripple effect of petroleum production on state tax revenues.

"Although Rosebank is currently the only UK field to qualify for the large deepwater oil field allowance, further fiscal allowances may be required for the project to go ahead. As such, it would not be surprising to see further delays in the FID for Rosebank and Johan Castberg to 2016."

Despite this, the analyst notes that oil price volatility is expected to stabilize in the medium-to-long term and the development of the two projects is anticipated to begin, providing there are cost reductions and near field discoveries made in both projects.

Ingham continues: "The latest estimates put total development capital expenditure for Rosebank at $9.68 billion, but cost reductions of around 30% are required for the project to become economically viable. Assuming these reductions can be achieved and the project sanctioned, production seems likely to come on-stream in 2021, three years later than previously anticipated.

"For the Barents Sea project to progress, oil prices must return to levels of around $110 per barrel, if no tax allowances are forthcoming from the Norwegian government, to achieve a full-cycle net present value of $318 million and an internal rate of return of 11.1%. Assuming that Johan Castberg is sanctioned in 2015, Statoil will aim to commence production in 2020, two years behind schedule."

The global glut of crude oil is changing traditional storage dynamics by providing incentive for some of the world's largest oil traders to store crude at sea, according to a recent Reuters article.

"The shipping lists (provided to Reuters) indicate the trading firms have been able to hire the Very Large Crude Carriers (VLCC) for less than $40,000 a day - well below spot rates of between $60,000 to $70,000 a day," the article said.

With a contango carry of $8/bbl over the year, a VLCC of 2mbbls has inherent value of 16m$ over this period which equates to 44k$/day, i.e. well above the reported fixture levels (on these older less efficient units) of <40k$/day. The difference of c.5k/day totals c.1.8m$ over the year, which is sufficient to finance the port costs and (heavy) bunker consumption for a load/discharge voyage and for redelivery positioning.

It certainly makes sense, and if the carry continues at these levels, or edge even higher, then we can expect to see more similar VLCC storage fixtures. The units will most likely remain in the vicinity of the loading facility to maintain full discharge destination options. Oil on water numbers will escalate and vessel avails will suffer long term, supporting firm VLCC freight rates.

However, the carry would have to increase to c.15$/bbl over a year to support Suezmax storage and much higher before Aframax units could be considered.

The world's most accurate AIS satellite and antenna network power Genscape Vesseltracker's coverage of global maritime freight vessels, allowing market participants to track vessels of interest in real-time. In addition, the West Africa Crude Oil Report monitors crude loadings and intended destinations, providing insight into critical market drivers. Together, these unique services offer a way to monitor floating storage activity with accuracy to better understand today's evolving storage dynamics. Free trials of both services are currently available by visiting the Vesseltracker and WAF webpages.

CGG provides its vessel utilization and fleet allocation updates for the fourth quarter of   2014.

 Solid Vessel production rate for the fourth quarter of 2014:

• The vessel availability(1) rate was 87% due to typically high transit at this time of the year. This compares to an 83% availability rate in the fourth quarter of 2013 and a 92% rate in the third quarter of 2014.

• The vessel production(2) rate was 92%. This compares to a 90% production rate in the fourth quarter of 2013 and a 92% rate in the third quarter of 2014.

• During the fourth quarter of 2014, our 3D vessels were allocated 64% to contract and 36% to multi-client programs.

Record quarterly multi-client sales for the fourth quarter 2014:

CGG anticipates multi-client sales around $290 million during the fourth quarter of 2014, the highest ever quarterly revenue.

Significant client commitment for our StagSeisTM Gulf of Mexico program but also sustained multi-client sales in the North Sea, West Africa and Latin America drove multi-client revenue to this mark.

Jean-Georges Malcor, CEO, CGG, said: "Our outstanding level of multi-client sales this quarter is clearly positive news given the unfavorable context of current oil prices. It also confirms client recognition of our excellent technology and the unique strategic positioning of our multi-client library in key sedimentary geological basins."

Also expects $1 billion in Group-wide restructuring charges over coming year

BP will present to investors its strategy and plans to the end of the decade and beyond for its Upstream oil and gas business.

The day-long presentation, led by BP's Upstream chief executive Lamar McKay, will provide an in-depth and detailed account of how BP is managing its Upstream business and its distinctive strategy for the long term. The presentation will also review the macro-environment and the context of recent developments in oil prices.

McKay and senior members of his upstream management team will share further insights into the depth and quality of the Group's resource base and investment portfolio, which underpin BP's long-term value proposition through the changes in the price environment.

"Although the current environment is challenging, BP is well-positioned to respond and manage our Upstream business for the long term," said Lamar McKay. "We expect to see growth from our conventional and deepwater assets and an increasing contribution from gas. And we also have a quality pipeline of opportunities that we believe are capable of extending underlying growth well beyond 2020. Our focus throughout will remain firmly on safe operations, execution efficiency and greater plant reliability."

BP also said that, as part of its wider ongoing Group-wide program to simplify across its Upstream and Downstream activities and corporate functions, it expects to incur non-operating restructuring charges of circa $1 billion in total over the next five quarters, including the current quarter. Details of these charges and further guidance on the program are expected to be given with each quarter's results.

Group Chief Executive Bob Dudley said: "We have already been working very hard over these past 18 months or so to right-size our organization as a result of completing more than $43 billion of divestments. We are clearly a more focused business now and, without diverting our attention from safety and reliability, our goal is to make BP even stronger and more competitive.

"The simplification work we have already done is serving us well as we face the tougher external environment. We continue to seek opportunities to eliminate duplication and stop unnecessary activity that is not fully aligned with the group's strategy."

As an integrated group, not all BP's businesses are equally exposed to the oil price. About one third of its Upstream projects around the world are operated under production sharing contracts and it is also investing in high quality gas projects which are typically less sensitive to oil price movements. Importantly, while BP approves projects at $80 a barrel, it also already tests each at $60 a barrel to understand the resilience of the portfolio at a range of prices. It will also continue to consider lower price sets as appropriate.

BP also has a strong balance sheet, with historically low gearing of 15% at the end of the third quarter of 2014, which provides time and flexibility to adjust to changes in the environment.

Across the Group, BP has said it will be looking to pare or re-phase capital expenditure without compromising safety or future growth. In October, BP told investors this could result in reductions of $1 billion to $2 billion in capital expenditure across the Group in 2015 against guidance of $24 billion to $26 billion laid out in March. This will be reviewed further as part of the 2015 plan, recognizing the current outlook for oil prices.

When oil prices fall, there is typically deflation in the industry as a whole. Together with its already greater focus on streamlining activity, this would be expected to further help BP align its cost base with its smaller footprint and reduced activity levels.

The Upstream team will today detail the business's track record of delivery as part of the Group's 10-point plan. Amongst the milestones, over the last three years, the Upstream has improved safety and reliability of operations; doubled exploration drilling activity; and rebuilt Gulf of Mexico production. It has also increased the rate of reinvestment; made $32 billion of divestments in the Upstream business alone; and, by year end, also expects to have delivered 15 new upstream projects with average operating cash margins double 2011 average.

Between now and 2020, the Upstream team's focus will be on delivery, through safe and reliable operations, strong execution in the existing base business, and the start-up of a suite of new projects which are expected to be capable of adding over 900,000 barrels of oil equivalent a day of net incremental production to BP's portfolio by 2020. BP will also be progressing opportunities expected to continue to drive underlying growth into the next decade as it builds out its well-established conventional and deepwater oil positions and a distinctive and material portfolio of gas options.

NYC-based PIRA Energy Group reports that China and India SPR to add Oil in 2015, Mostly in 2H. In the U.S., commercial stocks drew. In Japan, crude runs rose, crude imports were higher and crude stocks built. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

China and India SPR to Add Oil in 2015, Mostly in 2H
PIRA assumes in its global supply/demand balances that China and India will each add barrels to their respective SPRs in 2015. The limiting factor is capacity availability. In the case of China major new facilities are not expected until at least the second quarter while in India, after years of delay, the first facility is expected to start operating in 2Q15.

U.S. September 2014 DOE Monthly Revisions
DOE released its final monthly September 2014 (PSM) U.S. oil supply/demand data today. Demand came in at 19.04 MMB/D compared to 19.16 MMB/D PIRA had estimated in its balances. Compared with the weekly preliminary data, total demand was revised down 206 MB/D, with "other" lowered 495 MB/D, primarily due to an upward revision to exports. End-September total commercial stocks stood at 1,144.0 MMBbls versus the 1,140 MMBbls adjusted stock level that PIRA carried in its balances. Compared to the weekly preliminary data, DOE raised total commercial stocks 7.9 MMBbls, with 1.4 MMBbls being crude, and 6.5 MMBbls being products. Relative to year-ago, using final September PSA data, total commercial stocks are higher by 6.6 MMBbls.

Japan Crude Runs Rise, Crude Imports Higher, Crude Stocks Built
Crude runs rose incrementally out of turnarounds. Alignment with our planned turnaround schedules still looks good. Crude imports were higher and crude stocks built. Finished product stocks drew marginally due to draws on gasoline and naphtha. Gasoline demand was higher, as expected, due to the holiday. Gasoil demand was marginally lower, and stocks built modestly. Kerosene demand was slightly higher, but stocks still built a bit.

OPEC Will Let the Market Set Prices for Now
There is just too much supply relative to demand at anything near $100/Bbl Brent. Hence OPEC will let the market set prices for now and see what price the market needs to inevitably balance supply and demand. PIRA believes initially the market needs to see a 6 handle for WTI and the low 70's for Brent. This should slow supply growth and help to rejuvenate demand. The price experiment has been unfolding for some time but now the world will know. It should have some interesting twists and turns.

Let the Market Rule: Why Saudi Arabia Didn't Want to Cut Output
Under current and expected market conditions, cutting output to support price would be self defeating, making the structural imbalance even worse. The oil market has lost its price anchor; so markets will dictate prices.

The Saudi Dilemma
While the global price elasticity of oil demand and supply is extremely low, the price elasticity faced by the Saudis, as a swing producer, is much higher. In fact, if they are required to absorb 100% of the swing in the call on OPEC, the medium term elasticity faced by the Saudis is likely greater than 1 meaning that their export revenue will fall in response to a price increase. Thus in an environment like now, where it is hard to see the Saudis getting cooperation from other OPEC (and/or non-OPEC) members, a decision to cut production will likely prove to be a revenue loser after several years. Of course, the Saudi decision on production volumes will not be based solely on export revenue maximization.

LPG Feedstock Economics in Asia Mixed
Propane's discount to naphtha in Asia improved by $1 to $27/MT in last week's turbulent trade. At these levels propane remains expensive relative to other feedstocks for petrochemical usage. As in Europe, PIRA's spot generic cracking margins indicate that butane is currently the most economic feedstock in NE Asia. Naphtha's cracking economics fell by 5¢ to 32¢ while butane's improved to 41¢. Propane remains at the back of the pack at 31¢/lb ethylene produced.

U.S. Ethanol Production Sets New Record
The week ending November 21, U.S. ethanol manufacture reached 892 MBD, shattering the record 892 set the week ending June 14. The manufacture of ethanol-blended gasoline jumped to a four-week high 8,724 MB/D.

U.S. Ethanol Prices and Margins Soar
U.S ethanol prices and manufacturing margins skyrocketed during November despite record ethanol production. Inventories had gotten extremely low as output had been light for several months when companies shut down for maintenance turnarounds.

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.

With so much speculation surrounding the plummeting oil price, the state of the natural gas market has largely taken a backseat. However, gas prices are falling too, but the extent and impact of this varies around the world more than in the case of oil.

Natural gas is a fast-growing source of global energy – in their 2015 Outlook for Energy, ExxonMobil forecast gas demand growth to outstrip oil and coal significantly to 2040. In Asia, where the majority of demand growth is expected, we have seen tumbling prices in recent months. Spot prices in South East Asia have fallen by as much as 50% over the last seven months to around $9/mmbtu at the time of writing, but here is where the story diverges from crude. Existing long-term supply agreements linking gas prices to oil stifle the reaction felt by exporters, while at the same time lead to strenuous renegotiations. The impact of supply agreements – particularly in Asia – exacerbated the decoupling of regional gas prices in 2008/9 where European hubs leant on their greater liquidity and as a result prices rose at a slower rate to 2014.

Even with long-term agreements in place, it will be exporters of natural gas, particularly LNG, that are most concerned. In Japan, the highest priced consumer, LNG prices are widely expected to fall to below $13/mmbtu in 2015. In this environment the arbitrage opportunity for Middle Eastern, American or African producers evaporates. LNG spot trade is perhaps most-exposed and significant volumes are now traded as spot cargoes – amounting to some 30% of the total. Furthermore, Chinese importers have stated their preference for regional production and pipelined imports where the infrastructure is in place – and the infrastructure continues to grow. It's the LNG exporters that face the most pressure in strenuous times.

Natural gas and LNG have a bright future as economies move towards cleaner energy sources. But the next 18 months will be a serious test of the LNG value chain if Asian prices return to European levels once again.

Matt Loffman,

Douglas-Westwood Houston

NYC-based PIRA Energy Group reports that the creeping stock surplus continues. In the U.S., overall commercial stocks built last week with the build in both products and crude.. In Japan, crude runs and imports are higher and crude stocks built fractionally. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Creeping Stock Surplus Continues
Preliminary data is now in for end November and it shows that commercial oil inventories in the three major OECD markets – United States, Europe and Japan – drew just 12 million barrels (400 MB/D) compared to a year earlier 37 million barrel (1.2 MMB/D) decline. Commercial stocks in these markets began the fourth quarter 22 million barrels, or 1%, higher than the year earlier and have now ended November 76 million barrels, or 3.5% higher. This stock profile is consistent with PIRA's balances showing year on year supply growth outpacing demand growth by over 1 MMB/D. This imbalance grows even larger in 2015.

Data Issues Likely an Important Factor in Big U.S. Stock Build
Overall commercial stocks built last week with the build in both products and crude. Re-benchmarking occurred this week indexing the December 5 stock levels to the September PSM, which resulted in substantial upward revisions to stocks. Part of this adjustment could have inflated inventories and correspondingly deflated reported demand. An added factor could be the stock data for the prior Thanksgiving holiday week was underreported, thus distorting this week's stock change. Probably both factors are to blame but, nevertheless, this week's reported inventories reflect a growing surplus of inventory relative to last year.

Japanese Crude Runs and Imports Higher and Crude Stocks Built Fractionally
Crude runs were marginally higher on the week. Alignment with our planned turnaround schedules still looks good. Crude imports were higher and crude stocks built fractionally (0.2 MMBbls). Finished product stocks drew due to draws in all the products but jet.

Re-Weighting of Major Commodity Indices in January 2015 Boosts Brent but Lowers Natural Gas and European Gasoil
The S&P GSCI and the Bloomberg Commodity Index (BCI), the two major indices for passive investment in commodities, have recently announced the new weighting schemes that they will apply to their respective commodity indices effective January 2015. The BCI index will see $2.6 Billion flow into energy against a $0.5 Billion loss for GSCI. Natural gas is the big loser down $1.2 Billion in January 2015 vs. current levels, while Brent is the big winner picking up $2.6 Billion. WTI increases only $334 Million. Oil products over the same time period increase $407 Million. European gas oil is the other major loser in the re-weighting down 7 MMBBLs or $575 Million.

When Will the Bloodletting Stop?
Saudi Arabia's relinquishing its role as oil price anchor has caused a catastrophic decline in the demand for inventory which has resulted in oil prices collapsing. Both physical and financial "inventory" holders have been selling. The selling has had a snow ball effect because of a lack of liquidity, one of the consequences of Dodd Frank regulations, and ongoing producer hedging. With many U.S. shale oil producers under hedged in 2016, with say 15% coverage, versus 40-50% for 2015, the selling pressure will not end until prices drop to the level where hedging is uneconomic.

NGL Prices to Continue Falling
With crude oil prices likely to continue to push lower and U.S. LPG export economics continuing to flash negative, the path of least resistance seems to be lower for U.S. prices. Internationally, recent LPG gains on naphtha in Europe and Asia come at the expense of less attractive petrochemical feedstock margins. LPG's discount to the refined product will need to widen for higher consumption to occur.

Ethanol Output Reaches All-time High
U.S. ethanol production soared to a record 988 MB/D the week ending December 5, up 26 MB/D from the previous week. Stocks built by 461 thousand barrels to a seven-week high 17.75 million barrels.

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.

NYC-based PIRA Energy Group reports that crude prices fall as Cushing stocks rise. In the U.S., stocks drew slightly. In Japan, crude runs rose, crude imports were lower and crude stocks drew. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Crude Prices Fall as Cushing Stocks Rise
Crude prices continued their downward spiral in November, with WTI dropping below $70/Bbl. Regional grades in the Rockies and West Texas strengthened vs. WTI, on new pipeline takeaway capacity. Canadian crude differentials weakened slightly. Cushing crude stocks rose 3 million barrels in November, ending the month at 24 MMB.

U.S. Stocks Draw Slightly
This past week crude runs soared to the highest level since peak summer runs. This ended nine weeks of product stock declines during the fall maintenance season, and product inventories increased. Not surprisingly, crude stocks flipped to a draw from mostly builds. The resulting overall stock decline was 6 million barrels less than last year's inventory decline for the same week, widening the year on year inventory excess.

Japanese Crude Runs Rose, Crude Imports Were Lower and Crude Stocks Drew
Crude runs rose out of turnarounds. Alignment with our planned turnaround schedules still looks good. Crude imports were lower and crude stocks drew 2.1 MMBbls. Finished product stocks drew due to draws on fuel oil and naphtha. Gasoline demand was slightly higher, the yield increased and stocks built. Gasoil demand was lower, and stocks drew. Kerosene demand fell and stocks built.

PADD Crude Balances Show Different Reactions to Production Growth
By now, the story about the increase in U.S. crude production and the resulting decline in crude net imports is a familiar one. How these changes played out in individual PADDs, however, is a different story. Parts of each regional crude balance have followed quite a different path than the national aggregation. Changes to internal logistics and flows are a key part of the story, with rail both contributing to, and benefiting from, the growth in shale crude production. A prolonged period of low prices, especially low wellhead values in the Bakken and Canada, could dramatically reduce the need for infrastructure growth, and slack infrastructure utilization would be reflected in additional narrowing of regional price differences.

Freight Market Outlook
OPEC's decision to leave their production target unchanged at current levels signals the start of a new era for the oil markets. While the oil sector is now in crisis mode, the tanker sector is experiencing a seasonal rebound. Bunker prices have declined by more than $185/ton since July while tanker rates have generally firmed in most trades, leading to sharply higher vessel earnings. The new normal seems to be characterized by more frequent tanker rate spikes and higher volatility in the Atlantic Basin as trading patterns have yet to fully adjust to the growing volumes of crude and products that must move from the Atlantic to Asia. Longer term, higher OPEC output, lower growth in non-OPEC supplies and inexpensive bunker fuel are highly beneficial to the tanker sector.

U.S. NGL Prices Crushed
It's becoming increasingly clear that LPG supply is outpacing demand globally. While crude prices have stabilized for the moment, LPG has had no such luck, with prices remaining in freefall mode. U.S. prices were crushed across the board, with the Saudi CP cut a major catalyst; Mont Belvieu propane fell 15% to 58¢/gal and butane lost 17% to 81¢. But the ethane price deterioration was even worse. C2 prices fell a massive 23% as the feedstock struggles to compete with cheap propane in the U.S. steam cracker pool.

Ethanol Manufacturing Margins Soar
U.S. ethanol assessments were mixed during the holiday-shortened week ending November 28; prices in Chicago and the Gulf Coast continued to climb as the market was tight, while New York and Southern California ethanol tumbled from lofty levels. Manufacturing margins were the highest since March as inventories remained low.

Ethanol Stocks Build
U.S. ethanol manufacture declined to 962 MB/D during the holiday-shortened week ending November 28, down from a record 982 MB/D in the preceding week. After falling for two consecutive weeks despite record output, stocks built by 217 thousand barrels to 17.3 million barrels.

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.

The recent fall in oil prices not only brings the obvious benefits of a boost to the global economy but also an opportunity to address the eye watering costs of energy subsidies.

The IEA estimated the cost of global fossil fuel subsidies in 2012 was $544bn and renewables $110bn. It has been suggested that the total cost in 2014 could be approaching $1 trillion. Designed to deliver benefits to citizens, petrol and diesel fuel subsidies are mainly found in existing and former producer countries and constitutes a real and growing problem, particularly for some Asian economies. Governments are buying oil at the global market price then selling at below cost, with massive economic consequences and what is more, low prices encourage growing consumption. The reality is that a very small proportion of subsidies reach the really poor. However, cutting off the subsidies causes major local opposition and indeed civil unrest. But the supply of the drug of cheap fuel must ultimately be halted.

So it was refreshing to see Malaysian minister, Hasan Malek announce its government's plan to abolish subsidies for petrol and diesel from today, December 1. This follows on from Indonesia's new president Joko Widodo keeping his election promise and announcing that fuel prices will rise by 30% to tackle the growing budget and current account deficits, a move expected to save the government more than $8 billion in 2015. Their timing is good as the low oil price reduces the impact on their people. The previous Indian government also started to increase prices from January 2013 and central bank Governor Raghuram Rajan recently said that it must take advantage of the low oil prices to reduce the subsidies that contribute to one of Asia's largest budget deficits.

Despite all the well-meaning green rhetoric, history shows that it is high prices that really focus consumers thoughts on energy efficiency and reduce the growth of energy demand. We are witnessing a rare international outbreak of common sense.

www.douglas-westwood.com

BP's business activities in the US helped generate close to $143 billion in economic impact in 2013 and currently support nearly 220,000 American jobs, according to the company's US Economic Impact Report 2014.

BP's new report provides a detailed, state-by-state look at the breadth and impact of the company's activities in America. Since 2009, BP has invested nearly $50 billion, making it America's largest energy investor. In 2013 alone, BP spent $22 billion with vendors across the country on products and services, ranging from offshore drilling rigs to gasoline-producing equipment for its refineries.

"No energy company has invested more in the US over the past five years than BP," said John Mingé, BP America chairman and president. "Our investments not only provide the energy to power the nation, but they also support hundreds of thousands of jobs that fuel the economy."

BP's business investments in the US include oil and natural gas exploration and production, fuel and chemical refining, lubricants, shipping, trading, renewable energy production and cutting-edge technology research and development. The US also is home to a number of operations that serve BP's global businesses, such as the Center for High-Performance Computing in Houston, which houses the world's largest supercomputer for commercial research.

BP produces more than 628,000 barrels of oil equivalent a day – enough to light nearly the entire country. The company's three northern-tier refineries in Indiana, Ohio, and Washington are together capable of processing more than 742,000 barrels of oil per day. Also, BP's chemical and lubricant facilities supply materials necessary for modern life, including greases and engine oils marketed under the Castrol brand and chemicals used in fabrics and packaging.

In addition to physical assets and energy production, the US is home to nearly 40 percent of BP's publicly traded shares and more BP employees than any other nation. The US also is a center for BP research and recruitment. The company will spend $60 million this year on academic research, educational initiatives, and recruitment activities at more than 50 US universities.

At the corporate level, BP contributes more than $30 million a year to charitable and nonprofit organizations such as United Way of America and the National Multiple Sclerosis Society. This includes contributions through BP's unique Fabric of America program in which BP employees may annually designate $300 of corporate funds to a nonprofit organization of their choice within the United States. Since the fund's 2007 inception, BP has given more than $26 million on behalf of our employees, helping to support roughly 19,000 organizations in all 50 states.

The investments and spending detailed in the report do not include costs associated with cleanup and restoration activities in the Gulf of Mexico, or claims payments related to the Deepwater Horizon accident.

To view or download BP's full US Economic Impact Report 2014, please visit: www.bp.com/EIR.

BP in the US - By the Numbers:

Employees: More than 18,000 employees

Total Jobs Supported: Nearly 220,000 jobs

Employee Payroll and Benefits: $5 billion, including pensions and other post-employment costs

National Economic Impact Nearly: $143 billion in 2013

BP U.S. Investment since 2009: Nearly $50 billion – the most of any energy company

Money Spent with Vendors: More than $22 billion in 2013

Community Investment: $30 million in corporate contributions annually

Short-term investment models for shale make it more vulnerable to project cuts

With oil prices plummeting to a five year low, and project cut backs likely in 2015, short-term funding for US shale may lose out to the country's higher cost deep water developments, the latest article by leading petroleum industry advisor Gaffney, Cline and Associates (GCA) suggests.

The current low price of oil has been blamed on reduced demand and a global oversupply. Much of that oversupply is due to the huge increase in oil production from the US unconventional or shale industry.

New analysis from GCA indicates that where companies have the flexibility to choose, shale activity will most logically suffer first as a result of the price crash, leaving activity in other areas such as the Gulf of Mexico relatively more protected. However actual cuts will be influenced by a large number of individual company factors, and the squeeze on cash flow will undoubtedly cause cuts to be felt everywhere.

"Whilst high cost environments such as the deep water Gulf of Mexico would appear to be vulnerable, and undeniably cuts should be expected there, economic rationality suggests that the brunt of cuts should be directed at onshore unconventional investments. However, in the short term there is not always the operational flexibility to make decisions based solely on fundamentals," says the article's author Bob George, Executive Director and Senior Strategic Advisor at GCA.

Another key difference for deep "water projects is their longer-term investment lifecycle. In the Gulf of Mexico (GoM) for example, where a company's investment in a typical project may be US$1 billion or more, much or all of the investment will be committed and spent around five years before any returns are seen. The critical point for such projects is not the price of oil now, but its anticipated price in the future and where deferral in the short term may result in missed gains later.

"From a decision-making perspective, this means the risk lies in the expected price of oil in 2020. As a result, projects currently underway are less likely to be stopped. This is in contrast to onshore unconventional shale investment where decisions are often much more short term," says George.

"Shale drilling can be cut back or ramped up in fairly short order to accommodate the market conditions, resulting in more rapid response to fluctuating oil price."

At the end of October 2014 GCA posted an article* looking at the potential impact of US$80 per barrel on activity in unconventional shale oil plays in the United States. The article indicated that, using the "sweet spot" volatile oil window of the Eagle Ford as an example, activity was still profitable at that price although more fringe areas (and other basins with pricing disadvantages) might be more challenged. However, even the sweet spots in the Eagle Ford oil window started to look challenged at US$70 per barrel.

Co-authors Cecilia Jing Cui and Neil Abdalla point out that strong offshore GoM projects can still be viable down to US$60 per barrel. Economic rationality would suggest that where the opportunity exists, onshore shale spending would be a more appropriate short-term target for capital deferral because operating flexibility allows any adjustments made there to be reversed in equally quick order.

Bob George states, "Although pain is likely for areas like the offshore Gulf of Mexico in 2015, it should be much better placed to weather the storm of depressed oil prices in the short term than the US onshore unconventionals industry."

Pipeline corrosion is a challenging issue for oilfield operators. Growing global energy demand coupled with the relentless depletion of onshore and shallow water resources has driven the push towards the exploration of deepwater and unconventional fields. In many of these areas, sour gas is evident, a condition complicated by high-pressure, high-temperature (HPHT) environments which places severe demands on the corrosion resistance of infrastructure and equipment. Various methods to combat corrosion are utilized within the industry principally corrosion inhibitors and materials selection.

The use of well-planned and structured inspection, maintenance and repair regimes together with robust chemicals management can mitigate much of the impact of corrosive hydrocarbons. However, regulatory and environmental concerns have seen the replacement of some chemical preventative methods to those that are less toxic or perceived as less threatening to the environment.

A critical factor in the choice of preventative methods is that of Capex vs Opex. Chemical inhibitors are Opex intensive requiring frequent maintenance regimes. By contrast, assets with a longer design life may benefit from the use of CRA's (Corrosion Resistant Alloys) which reduce ongoing costs but substantially increasing initial Capex. DW's analysis of the CRA market indicates a growing adoption across upstream and downstream applications with overall spend increasing from $2.5bn in 2010 to $4bn in 2014.

As operators become more involved in corrosion prevention decisions, they face a number of challenges in juggling cost control and problems arising from corrosion. For the future, it seems larger Operators will assume a risk-averse stance on these matters. Adopting a long-term view on corrosion prevention will likely lead to increased utilization of Corrosion Resistant Alloys to reduce overall project costs.

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Baker Hughes Stockholders to Receive 1.12 Halliburton Shares Plus $19.00 in Cash for Each Share They Own
Transaction Values Baker Hughes at $78.62 per Share as of November 12, 2014

Highly Complementary Product Lines, Global Presence and Cutting-Edge Technologies Will enable Combined Company to Create Added Value for Customers

Accretive to Halliburton Cash Flow by the End of Year One, with Nearly $2 Billion in Synergies and Significant Cash Flow to Support Future Returns of Capital to Stockholders

HOUSTON – November 17, 2014 - Halliburton Company (NYSE: HAL) and Baker Hughes Incorporated (NYSE: BHI) have announced a definitive agreement under which Halliburton will acquire all the outstanding shares of Baker Hughes in a stock and cash transaction. The transaction is valued at $78.62 per Baker Hughes share, representing an equity value of $34.6 billion and enterprise value of $38.0 billion, based on Halliburton's closing price on November 12, 2014, the day prior to public confirmation by Baker Hughes that it was in talks with Halliburton regarding a transaction. Upon the completion of the transaction, Baker Hughes stockholders will own approximately 36 percent of the combined company. The agreement has been unanimously approved by both companies' Boards of Directors.

The transaction combines two highly complementary suites of products and services into a comprehensive offering to oil and natural gas customers. On a pro-forma basis the combined company had 2013 revenues of $51.8 billion, more than 136,000 employees and operations in more than 80 countries around the world.

"We are pleased to announce this combination with Baker Hughes, which will create a bellwether global oilfield services company and offer compelling benefits for the stockholders, customers and other stakeholders of Baker Hughes and Halliburton," said Dave Lesar, Chairman and Chief Executive Officer of Halliburton. "The transaction will combine the companies' product and service capabilities to deliver an unsurpassed depth and breadth of solutions to our customers, creating a Houston-based global oilfield services champion, manufacturing and exporting technologies, and creating jobs and serving customers around the globe."

Lesar continued, "The stockholders of Baker Hughes will immediately receive a substantial premium and have the opportunity to participate in the significant upside potential of the combined company. Our stockholders know our management team and know we live up to our commitments. We know how to create value, how to execute, and how to integrate in order to make this combination successful. We expect the combination to yield annual cost synergies of nearly $2 billion. As such, we expect that the acquisition will be accretive to Halliburton's cash flow by the end of the first year after closing and to earnings per share by the end of the second year. We anticipate that the combined company will also generate significant free cash flow, allowing for the return of substantial capital to stockholders."

Martin Craighead, Chairman and Chief Executive Officer of Baker Hughes said, "This brings our stockholders a significant premium and the opportunity to own a meaningful share in a larger, more competitive global company. By combining two great companies that have delivered cutting-edge solutions to customers in the worldwide oil and gas industry for more than a century, we will create a new world of opportunities to advance the development of technologies for our customers. We envision a combined company capable of achieving opportunities that neither company would have realized as well – or as quickly – on its own, all while creating exciting new opportunities for employees."

Lesar concluded, "We believe that the expertise of both companies' employees and leaders will be a competitive advantage for the combined company. Together with the people of Baker Hughes, we will establish a team to develop a detailed and thoughtful integration plan to make the post-closing transition as seamless, efficient and productive as possible. We look forward to welcoming the talented employees of Baker Hughes and are pleased they will be joining the Halliburton team."

Transaction Terms and Approvals
Under the terms of the agreement, stockholders of Baker Hughes will receive, for each Baker Hughes share, a fixed exchange ratio of 1.12 Halliburton shares plus $19.00 in cash. The value of the merger consideration as of November 12, 2014 represents 8.1 times current consensus 2014 EBITDA estimates and 7.2 times current consensus 2015 EBITDA estimates. The transaction value represents a premium of 40.8 percent to the stock price of Baker Hughes on October 10, 2014, the day prior to Halliburton's initial offer to Baker Hughes. And over longer time periods, based on the consideration, this represents a one year, three year and five year premium of 36.3 percent, 34.5 percent, and 25.9 percent, respectively.

Halliburton intends to finance the cash portion of the acquisition through a combination of cash on hand and fully committed debt financing.

The transaction is subject to approvals from each company's stockholders, regulatory approvals and customary closing conditions. Halliburton's and Baker Hughes' internationally recognized advisors have evaluated the likely actions needed to obtain regulatory approval, and Halliburton and Baker Hughes are committed to completing this combination. Halliburton has agreed to divest businesses that generate up to $7.5 billion in revenues, if required by regulators, although Halliburton believes that the divestitures required will be significantly less. Halliburton has agreed to pay a fee of $3.5 billion if the transaction terminates due to a failure to obtain required antitrust approvals. Halliburton is confident that a combination is achievable from a regulatory standpoint.

The transaction is expected to close in the second half of 2015.

Compelling Strategic and Financial Benefits
• • Leverages complementary strengths to create a company with an unsurpassed breadth and depth of products and services. The companies are highly complementary from the standpoint of product lines, global presence and cutting-edge technology in the worldwide oil and natural gas industry. The resulting company will provide a comprehensive suite of products and services to customers in virtually every oil and natural gas producing market in the world. This strategic combination will create an oilfield services supplier with the ability to serve customers through strong positions in key business lines, a fully integrated product and services platform, increased capabilities in the unconventional, deepwater and mature asset sectors, substantial and improved growth opportunities and continued high returns on capital.

• • Generates significant opportunities for synergies. In addition to the compelling and immediate premium Baker Hughes stockholders will receive, the transaction will also yield significant synergies. The combination will provide substantial efficiencies of scale and geographic scope, particularly in the Eastern Hemisphere, which will enhance fixed cost absorption. Once fully integrated, Halliburton expects the combination will yield annual cost synergies of nearly $2 billion. These synergies are expected to come primarily from operational improvements, especially North American margin improvement, personnel reorganization, real estate, corporate costs, R&D optimization and other administrative and organizational efficiencies.

• • Enables increased cash returns to stockholders. Halliburton expects the transaction to be accretive to cash flow by the end of the first year after closing and to earnings per share by the end of the second year. Halliburton expects that the combined company will maintain a strong investment grade credit profile and substantial financial flexibility. In addition, the combined company will generate significant free cash flow, allowing the return of cash to the combined investor base through dividends, share repurchases and similar actions.

Headquarters, Management and Board of Directors
The combined company will maintain the Halliburton name and continue to be traded on the New York Stock Exchange under the ticker symbol "HAL." The company will be headquartered in Houston, Texas,

Dave Lesar will continue as Chairman and Chief Executive Officer of the combined company. Following the completion of the transaction, the combined company's Board of Directors is expected to expand to 15 members, three of whom will come from the Board of Baker Hughes.

Concurrently with the execution of the merger agreement, Halliburton withdrew its slate of directors nominated for the Board of Directors of Baker Hughes.

Advisors
Credit Suisse is serving as lead financial advisor and BofA Merrill Lynch is also serving as financial advisor to Halliburton. Baker Botts L.L.P. and Wachtell, Lipton, Rosen & Katz are serving as Halliburton's legal counsel. BofA Merrill Lynch, as lead arranger, and Credit Suisse are providing fully committed debt financing in support of the cash portion of the consideration.
Goldman, Sachs & Co. is serving as financial advisor to Baker Hughes. Davis Polk & Wardwell LLP and Wilmer Cutler Pickering Hale and Dorr LLP are serving as Baker Hughes' legal counsel on this transaction.