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.

www.douglas-westwood.com

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.

NYC-based PIRA Energy Group believes that falling crude prices to slow midcontinent production growth. In the U.S., the stock excess versus last year increased and with a significant draw last year, the commercial excess should grow even more for the week of November 7. In Japan, crude runs fell, imports rose and stocks built. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Falling Crude Prices to Slow Midcontinent Production Growth
Crude prices plunged in October, with Brent falling nearly $10/Bbl and WTI ending the month below $80. Midcontinent differentials were little changed, except for those in the Permian Basin, where new pipeline capacity allowed prices to rebound from deep third quarter discounts. Midcontinent production is still rising, but lower prices will greatly reduce next year's growth.

Creeping Excess Storage
A look back at the most recent month of DOE weekly data shows a significantly smaller stock draw, compared to the same month last year, in spite of demand being up, year-on-year. A 630 MB/D difference in U.S. commercial stock change is a reflection of a global imbalance of supply over demand, this year compared to last year, of over 1 MMB/D. Far from being a mystery, this imbalance is apparent in stocks around the world. For winter, we expect the surplus to manifest itself in smaller draws, which will be reflected in a creeping stock excess. Come the spring, this surplus will appear as higher outright inventory levels. For this week, the stock excess versus last year increased to 15.4 million barrels, and with a significant draw last year, the commercial excess should grow even more for the week of November 7.

Japanese Crude Runs Fall, Imports Rise, Stocks Build
Crude runs eased to their lowest level since early July. Crude imports rose such that stocks built. Gasoline and gasoil demands were modestly changed and both product stocks drew, with the biggest draw being for gasoil. Kerosene demand was relatively strong and stocks posted their first seasonal draw. Refining margins are better with all the major product cracks firming.

Medium-Term Crude and Gas Price Outlooks Revised Down
Many of the bearish guideposts for our low case have emerged in the past six months. In the absence of new supply disruptions, we are likely to see prices at or below current levels for the next several years. We still believe that demand growth will return to a trend of 1.2 MMB/D, and combined with high-cost project cuts, this will lead to strengthening prices later in the decade. In the case of North American natural gas, the extremely strong growth in supply, even at sub-$4 prices and declining rig counts, suggests that prices are likely to stay lower for longer. Those changes, coupled with a weaker outlook for global gas demand growth, have led to reductions in the European and Asian gas outlooks as well.

U.S. LPG Stocks Remain Stubbornly High
Last week, U.S. propane inventories posted their second draw this heating season. The relatively small draw was influenced by a decline in both imports and in apparent demand. Inventories ended the week at 77.7 MMB, while the surplus expanded to 18.4 million barrels as the year ago withdrawal of 2.5 MMB stood much higher than the recent one. High U.S. stocks will ultimately need to clear by export. National LPG stocks are now well poised to both supply the harshest of winters and an increasing export market. Weaker prices relative to export destinations will be necessary for exports to increase.

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.

Exploring deep and ultra-deepwater areas could boost Trinidad and Tobago's (T&T) oil and gas industry, which has $6.2 billion of investment planned over the next two years, helping to offset the government's apparent move away from an energy-dependent economy, says an analyst with research and consulting firm GlobalData.

According to Effuah Alleyne, Senior Analyst for GlobalData, T&T's Budget Statement for the fiscal year 2015 revealed that the energy industry accounted for a 35% share of the country's anticipated revenue. This represents a significant decline since 2006, when the sector represented almost 53% of the budget.

While this move may imply trouble for T&T's oil and gas industry, Alleyne states that the emerging trend of deepwater exploration could help to revive the sector in a country where the majority of exploration and production (E&P) activity occurs in shallow waters of up to 250 meters (m) deep.

The analyst says: "T&T's competitive deepwater bidding round ended in March this year, with two of six blocks awarded to a consortium consisting of BHP Billiton and BG Group. These blocks are located in water deeper than 1,500m.

"As deep and ultra-deepwater is yet to be fully explored in T&T, these areas could represent vast potential, especially as there are over 15 open blocks. These lie in the Columbus Basin, an extension of the prolific Eastern Venezuelan Basin, where one of the world's largest reserves of 1 trillion barrels of heavy oil-in-place is located."

In addition to deepwater exploration, Alleyne notes that reassessing mature assets is another developing trend in T&T, with numerous recent discoveries being made in some of its established reserves.

The analyst explains: "Repsol's continued exploration activities in the mature Teak field revealed new oil accumulations this year through discovery well TB 14.

"Furthermore, this area, which has been producing since 1972, also has unexplored acreage onshore and offshore, similar to other mature assets in the country."

Alleyne concludes that T&T's planned oil and gas sector investment of $6.2 billion over the next two years reflects the confidence that untapped potential, both in existing fields and in under-explored deepwater and ultra-deepwater areas, could significantly boost the country's capital expenditure.

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."

NYC-based PIRA Energy Group Reports that U.S. total commercial oil stocks drew the week ending November 7, slightly widening the commercial stock surplus. On the week, Japanese crude runs rose and crude imports declined, causing crude stocks to draw. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Stock Excess Expands Slightly W/W
U.S. total commercial stocks drew the week ending November 7. The draw fell short compared to last year, slightly widening the commercial stock surplus. Within the overall draw, another week of very low crude imports drove an unexpected crude stock draw, pushing crude stocks into a deficit versus 2013 levels. The four major refined products drew year-on-year, narrowing their deficit.

Crude Imports in Japan Decline W/W
Japanese crude runs rose and crude imports declined the week ending November 8, causing crude stocks to draw. Finished product stocks built, with most of the build in kerosene. Gasoline demand was relatively strong, the yield fell back and stocks drew. Gasoil demand was again fractionally changed, as were stocks. Kerosene demand fell and the yield was higher so consequently stocks built on the week.

OPEC Meets November 27
Saudi Arabia will be in an uncomfortable position at the upcoming November 27 meeting in Vienna. As the primary beneficiary, along with the two other core OPEC countries, Kuwait and UAE, of OPEC (and non-OPEC) outages since 2010, other OPEC members will expect Saudi Arabia to sacrifice volume in the current oversupply situation.

Creeping Stock Surplus Continues
The preliminary October stock data for the three major OECD markets are in and they show a commercial stock draw of just 2 million barrels versus a stock decline of 31 million barrels in the same month last year. The nearly 1 MMB/D swing in the change in inventories is evidence of the ongoing 1.0-1.5 MMB/D supply surplus relative to demand in 2014.

Weak Naphtha Hampers LPG Demand
LPG remains stuck in strong competition with naphtha in Europe. Propane declined in lockstep with the refined product, losing 4% last week. Butane performed better bust still lost 2%, settling Friday at $505/MT. Butane weakness in Europe has the product's cracking margin soaring. At 48¢/lb, butane is a full ten cents higher than other feedstocks. Naphtha margins improved some, and now look about equivalent with propane in the region. Propane remains relatively expensive, and thus any increase in petrochemical demand will necessitate a widening of LPG's discount to naphtha in both Europe and Asia.

U.S. Ethanol Prices Soar W/W
Ethanol prices jumped again the week ending November 7 as inventories and production during the prior week were lower than expected. This resulted in a short squeeze since many traders had counted on values to decline.

U.S. Ethanol Output and Stocks Increase W/W
Ethanol production rose to 946 MB/D the week ending November 7, up from 929 MB/D during the preceding week as more corn has come available from the new harvest. Inventories built for the second consecutive week, reaching 17.7 million barrels.

Political Risk Scorecard
Progress in the Kurdish negotiations but continued instability in Libya this week.

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.

While the specific terms of Mexico's new contractual frameworks for its oil and gas industry are yet to be announced, the regime appears an attractive one and should be conducive to active bidding, according to an analyst with research and consulting firm, GlobalData.

Mexico's first licensing round is rapidly approaching, with bids for shallow water areas formally scheduled for the first half of this month. Round 1 is being staggered, with areas offered in the following order: shallow water, extra-heavy oil, Chicontepec and unconventional, onshore, and deepwater.

Will Scargill, GlobalData's Upstream Fiscal Analyst, states that much will depend on the specific contracts and terms allocated to the blocks and fields on offer, as Mexico looks to counter the significant production declines that its energy sector has experienced in recent years.
However, Scargill explains: "Analysis of the details released so far for the royalty and tax license framework shows positive signs.

"In addition to royalties, income tax and a predetermined signature bonus, contractors under this regime will pay a biddable additional royalty, which will be adjusted according to profitability. This mechanism is expected to be similar to that which will be applied for profit oil split under both production and profit-sharing contracts."

Based on the information provided by the Mexican government to date, GlobalData's assessment assumes an industry standard R-factor mechanism. No additional royalty is applied until cumulative net revenue equals cumulative investment, and the percentage of the bid that is applied increases linearly to 100% when cumulative net revenue reaches 2.5 times cumulative investment.

Scargill continues: "The fact that both the basic royalties and additional royalty are adjusted according to the commodity price and profitability, respectively, means that developments should remain commercially viable, even at low prices. This is particularly significant given the many heavy-oil areas on offer in Round 1 and recent falls in the world oil price.

"In comparison to the fiscal regime applicable to shallow water fields in the US Gulf of Mexico, the basic Mexican royalty and tax regime before the additional royalty offers much higher investor returns. This leaves space for significant competition in the bidding round," the analyst concludes.

We all need to remember, but often choose to forget, that oil is a highly cyclical sector. There have been seven significant price cycles since 1970 and also a few minor ones between times, so yet another should come as no surprise. The reasons for the fall in Brent crude prices from $115.19 in June to below $85 last week are well documented, as is the realization that OPEC is now defending market share, rather than a minimum price. That said, the nature of the oil business is very different now compared to after the 2008 crash.

It should be noted that 70% of the additional production that has come onstream since 2005 is unconventional. Much of this, of course, is from US shales - this is not cheap oil (mostly needing prices of $60-80 to be commercially viable) and decline rates are rapid - without ongoing drilling the current production capacity will be quickly eroded.

As in the past, the present downturn could be a great buying opportunity. In global E&P the NOCs rule and they will continue to invest; China has been the high spender and India's ONGC now plans a huge $180 billion foreign production acquisition spree. Likewise in oilfield services - acquisition opportunities are likely to present themselves for strategic and PE buyers, as was the case in the last downturn. Even without oil demand growth, vast numbers of new wells will need drilling worldwide each year to counter natural decline rates, probably some 80,000 in 2014 and more as demand grows again, boosting the demand for oilfield services.

Recent history suggests that oil price downturns tend to be short and measured in months, not years. There is plenty to suggest that, this time, it could be even shorter: rapid supply erosion is likely along with a healthy boost to GDP for net importers. Both high and low oil prices present opportunities for well-managed, well-financed companies that have a long-term view, as the oil & gas industry is not a short-term game. But the window of opportunity may well be very short before the next cycle begins.

www.douglas-westwood.com

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.

As the year draws to a close, attention turns to expectations for 2015. December usually sees a variety of eagerly anticipated E&P spend forecasts, however early indications suggest we will have a mixed bag of operators' increased/decreased spending plans. The drivers for this can be project-specific – biased by exposure to short or long-term projects – and also geographic.

Whilst the spending surveys are a useful guide, what can be learned right now from the drilling and production data? A review of our latest quarterly DW D&P output throws out some interesting geographic trends and here we pick two to illustrate the point:

The USA, the world's largest drilling and OFS market seems to have enjoyed a bumper year-to-date. Our expectations for land drilling in 2014 are just over 40,000 wells, versus 37,677 in 2013. The market has been buoyed by an upturn in activity in Texas shale formations, with the Texas Railroad Commission reporting completions increased by 21% for the first three quarters, with 23,149 over the year.

In contrast Russia, another major OFS market, appears to be suffering. Drilling is conducted by both independent contractors and directly by some E&P companies. Despite the long-term positive underlying drivers, the impact of both geopolitical turmoil and weak oil prices is becoming evident. The largest drilling contractor, EDC has reported drilling volumes down 7% for the first three quarters. Surgutneftegas a 17% drop, whilst for the first half of 2014 Rosneft was down 1.6% and Gazprom reports a slight upturn. Furthermore, international oil companies such as ExxonMobil and Shell have had to suspend activities in Russia as a result of sanctions imposed on the country.

Overall, our expectation is that Russian drilling will be down some 10% in 2014, at 6,700 wells, and will remain so or slightly lower in 2015 before recovering over the period to 2020.

Instances of double-digit movements in drilling from one year to the next are comparatively unusual, particularly so for large, established markets. But as the above illustrates, attempts to generalize the outlook for the whole E&P sector are difficult, and the "devil is always in the detail."

www.douglas-westwood.com

The Middle East will be one of the key markets for oilfield services companies for decades to come as countries across the region seek to maximize recovery from maturing assets and bring new fields into production, according to leading energy specialist corporate advisory firm Simmons & Company International Ltd. 

Speaking at ADIPEC in Abu Dhabi, Nick Dalgarno, co-head of eastern hemisphere corporate finance at Simmons, said there is an increasing willingness amongst governments and the national oil companies to build relationships with foreign companies to bring know how and technology into the region.

The oil and gas and wider energy factors driving this include the accelerating need for enhanced oil recovery, sour gas, heavy oil, tight gas, LNG, GTL, "clean fuels" refineries, carbon capture and storage, nuclear and solar technologies.

Just over half of the world's proven conventional oil reserves and 42 percent of the world's proven conventional gas reserves are located in the Middle East and North Africa (MENA). The region has 13 of the world's 20 giant oilfields as well as the largest gas field in the world. There is an estimated US$3 trillion of projects underway or planned in the six Gulf Cooperation Council countries (Saudi Arabia, United Arab Emirates, Kuwait, Oman, Bahrain and Qatar) plus Iraq and Iran. The majority of these relate to upstream oil and gas, downstream (including refineries, LNG and GTL), petrochemicals and related infrastructure projects.

Projects with values in excess of US $10 billion include the Jubail, Yanbu and Petrorabigh refineries and petrochemicals schemes in Saudi Arabia; the Rumaila, West Qurna and Majnoon field development in Iraq; Zadco Upper Zakum artificial islands field development, ADCO onshore field development programmes, ADMA-OPCO offshore field developments and Shah/Bab sour gas field developments in Abu Dhabi; Khazzan deep/tight gas project in Oman; and the Barzan gas development in Qatar.

The need for nuclear power and renewables, especially solar, waste to energy, desalination, and IT and communications security and asset protection technologies is also increasing.

Simmons' international practice spans offices in Dubai, London and its eastern hemisphere headquarters in Aberdeen. Earlier this year, it advised on one of the biggest oilfield services deals in the Middle East, playing a key role in the acquisition of National Petroleum Services (NPS) by a consortium of investors led by sovereign-backed investment firm Fajr Capital. The deal, which completed in June, was valued in excess of $500 million and is believed to be the biggest oil services M&A transaction in the region to date.

The involvement of the Simmons' Dubai and Aberdeen teams on this high profile deal marked their growing presence in the region, where they have now been involved in several notable transactions including the sale of Lamprell subsidiary Inspec to Intertek, the disposal of Al Mansoori's Thailand business and the sale of Clough's marine construction business to Sapura.

Nick Dalgarno said: "The Middle East is becoming an increasingly important region for international oilfield services businesses and the expertise of our Aberdeen and Houston teams combined with our local presence in Dubai make a compelling proposition for companies in the sector looking to buy, sell or secure investment.

"Involving our UK and US teams in Middle East transactions brings a wider international perspective and insight to our local presence in Dubai which, when combined with our network and market knowledge, is of real added value to industry in the region.

"No oilfield services company can afford to ignore the market in the Middle East due to its sheer scale and variety. The region is increasingly receptive to bringing in skills and technology from outside to support its E&P activity and EOR requirements and indigenous businesses are also seeking opportunities to grow internationally. The new relationships resulting from this are creating opportunities for mergers and acquisitions.

"Iran is also an enormous untapped market which, when it is eventually rehabilitated into the international community, will have to address decades of underinvestment in its oil and gas industry," said Mr Dalgarno.

Oceaneering International, Inc. (NYSE: OII) reports record earnings for the third quarter ended September 30, 2014. On revenue of $973.1 million, Oceaneering generated net income of $124.3 million, or $1.16 per share.

For the third quarter of 2013, Oceaneering reported revenue of $853.3 million and net income of $104.4 million, or $0.96 per share. For the second quarter of 2014, Oceaneering reported revenue of $927.4 million and net income of $110.3 million, or $1.02 per share.

Sequentially, quarterly EPS was 14% higher on operating income improvements from all business segments, led by Remotely Operated Vehicles (ROV). Year over year, quarterly EPS increased by 21% on the strength of operating income improvements from Subsea Products and ROV. EPS for the first nine months of 2014 was up 18% over the comparable period in 2013.

M. Kevin McEvoy, President and Chief Executive Officer, stated, "We achieved record EPS for the quarter, demonstrating the high level of demand we experienced for our subsea services and products. Our results were highlighted by all-time high operating income from our ROV and Subsea Products businesses.

"We remain on track to achieve record EPS for 2014. For the fourth quarter, we are projecting EPS of $0.94 to $0.99. Given this outlook and our year-to-date performance, we are narrowing our 2014 EPS guidance range to $3.95 to $4.00 from $3.95 to $4.05.

"Compared to the second quarter of 2014, ROV operating income increased on higher global demand to support drilling and vessel-based projects and an improvement in operating margin. Our ROV days on hire for the quarter increased to a record high of over 25,200 and our operating margin improved to 31% from 28% due largely to a change in geographic operations mix, resulting in a higher average revenue per day-on-hire. During the quarter we put 14 new vehicles into service and retired five. At the end of September, we had 332 vehicles in our fleet, compared to 302 one year ago.

"Subsea Products operating income was higher due to increased demand for tooling and subsea work systems. Products backlog at quarter-end was $768 million, compared to our June 30 backlog of $850 million and $857 million one year ago.

"Subsea Projects operating income increased due to a seasonal uptick in U.S. Gulf of Mexico demand for diving services. Asset Integrity operating income improved due to activity increases in the United Kingdom and Australia, and a $2.5 million gain on the sale of a non-core operation that was part of our AGR FO acquisition in 2011. Advanced Technologies income increased due to higher profitability on vessel maintenance and engineering services for the U.S. Navy.

"During the third quarter, we repurchased 3.0 million shares of our common stock at a cost of $201 million. Year to date, we have repurchased 3.5 million shares at a cost of $237 million. The decision to repurchase our shares reflects our belief that Oceaneering's stock has been undervalued. It also underscores our willingness to return cash to our shareholders and confidence in Oceaneering's financial strength and future business prospects. We have 5.4 million shares remaining under our current Board of Directors share repurchase authorization. Year to date, we have spent $318 million on share repurchases and cash dividends.

"As previously announced, we reached agreement for $800 million of committed bank facilities, consisting of a $500 million five-year revolver and a $300 million three-year delayed-draw term loan, to provide us with increased financial flexibility.

"We are initiating 2015 EPS guidance with a range of $4.10 to $4.50, based on an average of 105.7 million diluted shares. While we are facing widely publicized concerns regarding the future of deepwater activity, our 2015 guidance is based on assumptions that service and product demand to perform life-of-field activities and develop new fields will be higher than in 2014 and global floating rig demand will be about the same.

"Our liquidity and projected cash flow provide us with resources to invest in Oceaneering's growth and return cash to our shareholders, and we intend to continue doing so. We generated EBITDA of $241 million during the quarter and $645 million year to date. For 2014 and 2015, we anticipate generating EBITDA of at least $845 million and $880 million, respectively.

"Compared to 2014, we anticipate all of our business segments will have higher operating income in 2015, notably: ROV on greater service demand to support drilling and vessel-based projects; Subsea Products on the strength of higher demand for tooling and installation and workover control system services; and Subsea Projects on growth in deepwater intervention service activity in the GOM and diving in the GOM and offshore Angola.

"For 2015 and beyond, we believe that the oil and gas industry will continue its investment in deepwater projects. Deepwater remains one of the best frontiers for adding large hydrocarbon reserves with high production flow rates at relatively low finding and development costs. With our existing assets and opportunities to add new assets, we are well positioned to supply a wide range of the services and products required to safely support the deepwater efforts of our customers."

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

The Seaway line reversal in May of 2014 marked a turning point in the North American crude oil market with the draining of record stocks at the Cushing, Oklahoma storage hub. Attention has now shifted to the U.S. Gulf Coast and its capacity to move, store, refine, and export the glut of U.S. crude oil.

The goal of Genscape's new U.S. Gulf Coast Oil Supply Chain Service is to provide a holistic view of market fundamentals in the region to help traders, analysts, hedge funds, and infrastructure owners stay ahead of the evolving supply-demand dynamic. Using a range of patented, proprietary monitoring technology and a team of market experts, the comprehensive service provides granular inventory levels, 30-minute pipeline flows, and real-time camera tracking of refinery performance to provide unmatched transparency to this crucial region.

"We used to look at the Cushing storage hub for insight into the U.S. oil supply dynamic. That's not enough anymore," said Chris Sternberg, managing director of oil at Genscape. "Now, we need to look at the Gulf Coast and understand in detail what's happening to the oil and where it's going. We're excited to be filling this information gap with granular, measured data on oil fundamentals that will help market participants manage risk and opportunities."

"The incremental barrel produced is now heading to the Gulf during periods of oversupply or high refinery demand," said Dominick Chirichella of the Energy Management Institute. "Without the economic incentive to store oil at Cushing, physical and financial players will be making moves based on activity in the Gulf."

Furthermore, "with more than eight million bpd of refining capacity, the Gulf Coast is quickly becoming the most critical location for crude spot market activity and potential benchmarks to reflect market value for North America," according to Genscape's latest white paper, The Evolving Domestic & Global Crude Oil Pricing Landscape: An Inside Look at the Gulf Coast Infrastructure & Supply Chain. The paper argues that the current fragmentation of spot markets in the Gulf is causing market participants to struggle and creates the need for "new, granular fundamental benchmarks to support market efficiency and spur price benchmark evolution."

NYC-based PIRA Energy Group believes that the oversupply of crude will grow into 2015. In the U.S., seasonal low in runs leads to large U.S. product stock decline. In Japan, crude runs ease back, but crude stocks still draw. Specifically, PIRA's analysis of the oil market fundamentals has revealed the following:

Asia-Pacific Oil Market Forecast
Oil prices are likely to remain soft, even assuming a substantial cut at the November 27th OPEC meeting, though there would be a psychological bounce if cuts are enacted as PIRA assumes. The oversupply of crude will grow into 2015, with stock-building forecast for each of the first three quarters. Without an OPEC cut by year-end, the market would deteriorate further as the imbalances would be that much greater.

Seasonal Low in Runs Leads to Large U.S. Product Stock Decline
Overall inventories fell this past week, 2.7 million barrels more than the decline last year for the same week. Products led the inventory decline, the largest weekly decline this year as refinery runs hit their seasonal low and reported demand surged on the week. A large chunk of this demand increase was in distillate largely because of peaking harvest demand and in propane because of downstream movements in preparation for the winter. Compared to last year, the stock excess narrowed.

Japanese Crude Runs Ease Back, but Crude Stocks Still Draw
Crude runs eased back, while crude imports rose from the low level seen the previous week, building crude oil stocks. Gasoline demand was slightly weaker and stocks built modestly. Gasoil demand rebounded from a low level and stocks drew slightly. Refining margins remain soft but all the major product cracks improved on the week.

Refinery to Restart in U.S. Virgin Islands
The government of the U.S. Virgin Islands announced that it had reached an agreement with Atlantic Basin Refining (a U.S. firm) to restart the Hovensa refinery on St. Croix. That refinery operated on imported crude and primarily supplied the U.S. marketplace until its closure in 2011 – a time when all Atlantic Basin refining was under pressure. Those economics have since changed with the U.S. shale crude revolution because the refinery is in the United States and as such can use U.S. crude without any regulatory restrictions. Furthermore, the Virgin Islands have a blanket exemption from the Jones Act.

NGL Prices Rebound on Demand Jump
U.S. LPG prices rebounded this week on the first propane stock draw of the season. The sizable draw helped propel December NYMEX propane futures 3.4% higher on the week. Cold weather increased the need for heating fuels in the reference week with heating degree days growing by 54% week-on-week. Apparent demand jumped by 335 MB/D (28%) from the week earlier to 1.5 MB/D. Butane prices rose 4.6% to $1.12/gal, garnering strength from steadily decreasing weekly NGPL stocks in the EIA weekly data. Ethane prices bounced 1.8¢ higher with higher natural gas prices.

Ethanol Output Soars
Ethanol production spiked to a ten-week high 937 MB/D the week ending October 24, up from 896 MB/D during the preceding week. Inventories declined for the fourth consecutive week, dropping to a 5-month low 17.0 million barrels, led by a 670 thousand barrel draw in PADD I.

U.S. Cash Margins Rebound
Cash margins for ethanol manufacture in the U.S. rebounded during the end of October following eight straight weekly declines. Many mills in the South-Central region of Brazil will shut down four to six week early, lowering ethanol output for the season.

Probability of an Iranian Nuclear Deal Up to 50%, nut Iranian Politics Add Complications
Less than one month remains before the November 24th expiry of the interim nuclear deal and PIRA understands that talks are turning more creative. Discussions have reportedly shifted to the idea of disconnecting cascades of linked centrifuges that would reduce enriched uranium fuel output but avoids outright dismantling of individual centrifuges. PIRA believes the probability of reaching a final deal has moved up to 50% as U.S. President Obama and Iran President Rouhani, and Iran Foreign Minister Zarif are keen to do a deal. However, ultimately it is the Supreme Leader who approves the terms of any deal and his acceptance remains unclear.

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.

Platts – U.S. oil prices would have to fall another 20% or so before one of the leading American shale oil producers, Continental Resources, would cut back significantly on its operations, the company's CEO said Sunday on Platts Energy Week.

"We're hurt, but we're not to the point we're shutting down," Harold Hamm said. "And we're not getting close to that, yet, within a pretty good measurable amount, you know, $15 or $20. And certainly that's the case in the Bakken."

West Texas Intermediate (WTI) crude oil for December delivery fell 90 cents last week, to close at $81.01 per barrel (/b) Friday.

Hamm, whose company is the second-largest producer in the Bakken, said he was optimistic that the oil price decline would reverse soon.

"I've thought that we ought to be in the $90 range for sure," he said. "And I think the price will quickly come back to that."

Rising demand in China, primarily for transportation, would remain a key driver of world oil prices, he added.

Hamm said he preferred not to talk about the point at which oil prices would cause sharp declines in U.S. drilling activity.

"I don't like to go there, talking about where would you stop," he said. "That gets to be putting more fear into the market, if you will, and panic. And that's certainly not anything we should be talking about."

Nevertheless, such speculation has been prevalent among analysts following the oil price decline. For example, Standard & Poor's Rating Services last week said a reduction in U.S. shale drilling is likely if WTI prices fall below $80/b. S&P, like Platts, is part of McGraw Hill Financial.

Still, Hamm acknowledged that Continental Resources and other companies have begun to scale back some activities in response to the price decline.

"Certainly, we've had a serious reduction in price, losing some $20/b over these last few weeks," he said. "So, that's a pretty good pull-back. And certainly, people will probably start adjusting right there on projects that they can push back or don't have to do for a while. And our company has done the same thing, and others have."

But Hamm said the impacts vary depending on the locations of the wells, the financial needs of individual companies and other factors. The Bakken shale, he added, "probably lends itself to lower prices" more than other shale reserves.

Other Program Highlights

Also Sunday, Brigham McCown, a former head of the U.S. Pipeline and Hazardous Materials Safety Administration, shared some of the infrastructure challenges facing the U.S. oil and natural gas sector.

During another segment, Murray Energy CEO Robert Murray discussed his efforts to help Republicans re-take the U.S. Senate this November amid sentiment that the Obama administration and Democrats in Congress are contributing to the decline of coal.

In "Market Spotlight," Andrew Moore, managing editor of Platts Coal Trader, gave an overview of the myriad factors shaping the U.S. coal market.

Platts Energy Week airs at 8 a.m. U.S. Eastern time Sunday mornings on WU.S.A9 in greater Washington, D.C., and in Houston on KUHT, a PBS affiliate, as well as on other PBS stations in cities throughout the U.S., including Anchorage, Billings, Houston, Juneau, Las Vegas, Minneapolis, San Francisco, Raleigh and Wichita. For online viewing, the program is accessible at www.plattstv.com.