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 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.
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.
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."
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