BP Releases 3Q06 Earnings
BP's third quarter replacement cost profit was $6,975 million, compared with $4,410 million a year ago, an increase of 58%. For the nine months, replacement cost profit was $18,358 million compared with $14,882 million, up 23%.
The third quarter result included a net non-operating gain of $1,225 million compared with a net non-operating charge of $921 million in the third quarter of 2005. This includes significant gains on upstream asset disposals. For the nine months, the net non-operating gain was $1,214 million compared with a net non-operating charge of $1,201 million for the nine months of 2005.
Compared with a year ago, the third quarter trading environment reflected higher oil realizations and higher retail margins but lower refining margins and lower gas realizations.
Net cash provided by operating activities for the quarter and nine months was $5.1 billion and $23.2 billion compared with $6.4 billion and $22.5 billion a year ago.
The ratio of net debt to net debt plus equity was 16%.
The quarterly dividend, to be paid in December, is 9.825 cents per share ($0.5895 per ADS) compared with 8.925 cents per share a year ago. For the nine months, the dividend showed an increase of 10%. In sterling terms, the quarterly dividend is 5.241 pence per share, compared with 5.061 pence per share a year ago; for the nine months the increase was 8%. During the nine months, the company repurchased 1,024 million of its own shares at a cost of $12 billion.
BP Group Chief executive, Lord Browne, said:
"The trading environment reflected higher oil realizations and retail margins but lower refining margins and gas realizations compared to a year ago. The third quarter result benefited from significant disposal gains and IFRS accounting effects. Results are being impacted by higher tax charges. The share buyback program is continuing, with $3.5 billion of share repurchases during the quarter".
Summary Quarterly Results
Exploration and Production's third quarter result benefited from higher liquid realizations offset by lower gas realizations. In addition, it included higher production taxes and higher costs, reflecting the impacts of sector specific inflation, revenue investment and production growth. Furthermore, the result includes significant net gains on the sale of assets. BP's share of the TNK-BP result benefited from a gain of $892 million on the sale of its interest in the Urdmurtneft assets.
Compared with a year ago, the Refining and Marketing result, excluding Texas City, reflects strong operating performance. The lower result reflects lower refining margins, reduced supply optimization benefits and the impact of higher levels of refining turnaround activity. Retail margins improved strongly compared with a year ago. The result includes a significant gain related to IFRS fair value accounting effects.
In Gas, Power and Renewables, the lower third quarter result includes a charge for non-operating items compared with a gain in the same period last year. A significant reduction in the contribution from gas and power marketing and trading was partly offset by better operational performance in the natural gas liquids business and a lower charge related to IFRS fair value accounting.
Finance costs and Other finance expense was $117 million for the quarter compared with $181 million in the third quarter of 2005. Increases in market interest rates were more than offset by higher capitalized interest and a higher return on pension assets due to the increased market value of the pension asset base.
The consolidation adjustment, which removes the margin on sales between segments in respect of inventory at the period end, was a credit of $440 million in the third quarter. This primarily reflects changes in the amount of BP equity production held in Refining and Marketing segment inventories.
The effective tax rate on replacement cost profit of continuing operations was 40% versus 34% a year earlier, reflecting the retroactive impact of the increase in the North Sea tax rate, enacted in July 2006. The effect of this change on the Group's effective tax rate is partly mitigated by a sharp decline in prices around the end of the quarter.
Capital expenditure was $4.8 billion for the quarter, including $1 billion in respect of our investment in Rosneft. Disposal proceeds were $2.8 billion.
Net debt at the end of the quarter was $16.8 billion. The ratio of net debt to net debt plus equity was 16%.
During the third quarter, the company repurchased 299 million of its own shares, at a cost of $3.5 billion. Of these, 48 million shares were purchased for cancellation and the remainder are held in treasury. Additionally, shares to the value of $1.25 billion were issued to Alfa Group and Access Renova (AAR) being the last installment of the deferred consideration for our investment in TNK-BP.
The commentaries above and following are based on replacement cost profit.
The financial information for 2005 has been restated to reflect the following, all with effect from 1 January 2006: (a) the transfer of three equity-accounted entities from Other businesses and corporate to Refining and Marketing following the sale of Innovene; (b) the transfer of certain mid-stream assets and activities from Refining and Marketing and Exploration and Production to Gas, Power and Renewables; (c) the transfer of Hydrogen for Transport activities from Gas, Power and Renewables to Refining and Marketing; and (d) the change in the basis of accounting for over-the-counter forward sale and purchase contracts for oil, natural gas, NGLs and power.
Exploration and Production
The replacement cost profit before interest and tax for the third quarter was $9,935 million, an increase of 52% over the third quarter of 2005. This result benefited from higher liquid realizations offset by lower gas realizations. In addition, it included higher production taxes and higher costs, reflecting the impacts of sector specific inflation, revenue investment and production growth. Furthermore, BP's share of the TNK-BP result benefited from a gain of $892 million on the sale of its interest in the Urdmurtneft assets. Net non-operating gains for the third quarter were $2,466 million, mainly arising from net gains on sale of assets of $1,985 million, primarily from the sale of a pre-development asset in the Gulf of Mexico, and fair value gains of $521 million on embedded derivatives relating to North Sea gas contracts. The corresponding quarter in 2005 contained a net non-operating charge of $147 million.
After adjusting for the effect of disposals, production increased by 3% compared with the third quarter of 2005. Actual production was broadly flat compared with the third quarter of 2005.
The replacement cost profit before interest and tax of $24,584 million for the first nine months represented an increase of 30% over the same period of the previous year. This result benefited from higher oil and gas realizations partially offset by lower volumes, higher production taxes and higher costs reflecting the impacts of sector specific inflation, increased integrity spend and repairs, revenue investments and production growth. The nine months result included net gains on sales of assets of $2,324 million and net fair value gains of $275 million on embedded derivatives. The first nine months of 2005 contained a net non-operating charge of $19 million.
After adjusting for the effect of disposals, production for the first nine months was up around 1% compared with the first nine months of 2005 as underlying production growth from major projects in the new profit centers and TNK-BP offset decline in existing profit centers. Actual production was down 57 mboe/d from 2005.
In September, we determined that the oil transit lines in the Eastern Operating Area of Prudhoe Bay could be returned to service for the purposes of in-line inspection. We have now returned to service all three flow stations previously shut down, and current production from Prudhoe Bay is around 400,000 barrels of oil and natural gas liquids per day (BP has a 26% interest in the Prudhoe Bay field). We are still committed to replacing the main oil transit lines (16 miles) in both the Eastern and Western Operating Areas of Prudhoe Bay and expect to complete this next year. The effect of reduced production at Prudhoe Bay on average third quarter production was 27 mboe/d.
Offshore commissioning work on the Thunder Horse platform is proceeding. Following a series of tests carried out over the past few months, which revealed metallurgical failures in components of the subsea system, we plan to retrieve and replace all the subsea components we believe could be at risk. This work will be done over the course of the next year and we do not expect production from Thunder Horse to begin before the middle of 2008. It is too early to estimate the additional costs involved in replacing the affected systems.
In our other major projects we continue to make good progress. In Azerbaijan, ACG and BTC continue to ramp up. The Shah Deniz gas field and East Azeri are on track to start up in the fourth quarter. In Angola, the FPSO for the Dalia field is now being moored.
During the quarter, we made a significant oil exploration discovery on the Kaskida prospect in approximately 5,900 feet of water in the Gulf of Mexico and in Angola, we announced the Titania discovery, our 11th discovery in Block 31. In addition we have been awarded the Birbhum coal bed methane license in India and have reached agreement to acquire acreage in the UK Central North Sea which contains two discovered fields and further exploration potential.
During the quarter, we completed the sale of our remaining Gulf of Mexico Shelf assets which have been subject to pre-emption rights. In July, we completed the sale of our 28% interest in the Shenzi discovery in the Gulf of Mexico to Repsol. To date we have received $3.8 billion of proceeds from our divestment activity in 2006. In August, TNK-BP completed the sale of its interest in the Urdmurtneft assets to Sinopec and we announced the sale of five onshore properties in South Louisiana.
Refining and Marketing
The replacement cost profit before interest and tax for the third quarter was $1,503 million. This is compared to $1,875 million for the same period last year. The nine months' result was $4,971 million compared to $4,559 million for the same period last year, up 9%.
The quarter's result included a charge of $431 million for non-operating items. This includes a further provision of $400 million as a result of the ongoing review of fatality and personal injury compensation claims associated with the incident in March 2005 at the Texas City refinery. In addition, non-operating items include impairment charges of $90 million, a charge of $33 million in respect of new, and revisions to existing, environmental and other provisions and net disposal gains of $92 million. The non-operating charge for the corresponding quarter in 2005 was $154 million.
The third quarter's result included a significant gain related to IFRS fair value accounting effects. The third quarter of 2005 included a smaller gain.
The results for both the third quarter and the first nine months of 2006, excluding Texas City, reflect strong operating performance. The reduction in the result in respect of Texas City, including the impact on associated businesses, was some $320 million compared to the third quarter of 2005 and around $1,400 million compared with the first nine months of 2005. These figures exclude the provisions for fatality and personal injury compensation claims which are treated as non-operating items. The third quarter result also reflects the absence of hurricane activity which negatively impacted the third quarter of 2005.
This quarter's result reflects lower refining margins and reduced supply optimization benefits driven by lower crude and product prices, particularly around the end of the quarter. The quarter's result also included the impact of higher levels of refining turnaround activity. Retail margins improved strongly compared with the third quarter of 2005 due to the steady decline in wholesale product prices. The result for the first nine months reflects higher marketing margins and supply optimization benefits compared with the first nine months of 2005.
Refinery throughputs for the quarter and nine months were 2,287 mb/d and 2,200 mb/d respectively, lower than in the corresponding periods of 2005. This is primarily as a result of the phased start-up of production at our Texas City refinery during 2006. The recommissioning of the Texas City refinery continues, with throughput for the quarter averaging 247 mb/d. Refining availability for the quarter, excluding Texas City, was 96.3%, higher than in the corresponding period last year. Marketing sales were 3,924 mb/d for the third quarter and 3,875 mb/d for the first nine months of the year, compared with 4,044 mb/d and 3,979 mb/d for the corresponding periods in the previous year.
During the quarter, BP announced that it has entered the final planning stage of a $3 billion investment in Canadian heavy crude oil processing capability at its Whiting refinery located in northwest Indiana. The intention is to reconfigure the Whiting refinery so most of its feedstock can be heavy Canadian crude oil. Reconfiguring the refinery also has the potential to increase its production of motor fuels by around 15 percent, which is approximately 1.7 million additional gallons of gasoline and diesel per day. Construction is tentatively scheduled to begin in 2007 and be completed by 2011, pending regulatory approval.
Gas, Power and Renewables
The replacement cost profit before interest and tax for the third quarter and nine months was $152 million and $906 million respectively, compared with $347 million and $948 million a year ago. Included in the result for the quarter was a charge for non-operating items of $85 million arising from fair value losses of $20 million on embedded derivatives related to long-term gas contracts, a charge of $70 million for the impairment of a North American NGL asset and a $5 million gain on disposal. The corresponding quarter of 2005 included a net non-operating gain of $95 million, largely comprising fair value gains of $91 million on embedded derivatives.
The third quarter result was 56% lower than the same quarter of 2005. The decrease was primarily due to a non-operating charge in the current quarter compared with a net non-operating gain in the same period last year. A significant reduction in the contribution from gas and power marketing and trading was partly offset by better operational performance in the natural gas liquids business and a lower charge related to IFRS fair value accounting. Similarly, the nine month result was marginally lower than the same period in 2005, largely reflecting a net charge for non-operating items compared with a gain in the same period last year and higher IFRS fair value accounting charges, partly offset by higher contributions from the operating businesses.
In August, we purchased Greenlight Energy, Inc., a US-based developer of wind power generation projects. The purchase will further accelerate the rapid growth of BP's wind power business in North America. In Korea, K-power Company Limited (BP 35%) completed construction of a 1,074MW, LNG-fired combined cycle power plant near Kwangyang City, which has began full commercial operation.
Other Businesses and Corporate
Other businesses and corporate comprises Finance, the group's aluminum asset, interest income and costs relating to corporate activities. The third quarter's result includes a net gain of $78 million in respect of non-operating items. This includes a net credit of $96 million in relation to new, and revisions to existing, environmental and other provisions. Also included in the result, but not treated as a non-operating item, is a charge resulting from new, and revisions to existing, vacant space provisions.
BP Group Chief Executive, Lord Browne, concluded:
"World economic growth has been sustained. US economic growth appears to have slowed compared to the second quarter, but growth in Europe and Asia has been robust. The near-term global outlook is for slower but resilient growth.
"Crude oil prices averaged $69.60 per barrel (Dated Brent) in the third quarter of 2006, similar to the second quarter average and nearly $8 per barrel above the same period last year. After peaking above $78 per barrel in early August prices have declined and in early October were below $60 per barrel. Ample inventories, a perceived lessening of geopolitical tensions, and a lack of hurricane-related disruptions have contributed to the decline. OPEC members have announced an intent to reduce production.
"US natural gas prices averaged $6.58/mmbtu (Henry Hub first of month index) in the third quarter, $0.22/mmbtu below the second quarter average and nearly $2/mmbtu below the same period last year. Gas continued to trade at a discount to residual fuel oil. Domestic production growth retained its momentum, and consumption outside the power sector remained sluggish. Gas in storage at the end of September was 12% above the five-year average. Prices should be supported by seasonally rising winter demand.
"UK gas prices (NBP day-ahead) in the third quarter averaged 33.72 pence per therm, slightly below the second quarter but 15% above the same period last year. Since the peak in late July, prices have fallen significantly, facilitated by fewer North Sea maintenance closures, LNG imports, and most recently, the testing of the Langeled pipeline. Rough storage is full and import capacity has increased, easing most concerns over winter supply availability.
"The global average indicator refining margin fell to $8.40/bbl in the third quarter of 2006, down more than $4/bbl versus the second quarter and by a similar amount versus the third quarter last year. Margins were strong in July and August but fell away sharply during September on the end of the US gasoline season, limited hurricane activity and growing product inventory levels. So far in October, margins have averaged around $5/bbl, and should be underpinned in the near term by the autumn refinery turnaround program and demand for distillates once colder weather arrives.
"Retail margins increased significantly in August and September due to a steady fall in the cost of product, leaving average retail margins for the third quarter above the previous two quarters. More stable raw material costs during October to date and an increase in competitive pressures suggest that marketing margins in the fourth quarter are likely to be weaker.
"The UK Government's announced increase in the North Sea supplemental tax rate has been enacted. This increase has two effects; first to create a one-time deferred tax charge and second to increase current tax to reflect the 2006 impact of the higher rate, which is retroactive to the start of the year. The full year aggregate effective tax rate is expected to be around 37%.
"Our strategy is unchanged. We continue to execute it with discipline and focus. Production for the year is expected to be around 3.950 mmboe/d, lower than in 2005 due principally to divestments and the impact of higher prices on entitlements under Production Sharing Contracts. Capital expenditure excluding acquisitions is expected to be around $16 billion for the year. Divestment proceeds are expected to be around $6 billion."
Operates 33 Offshore Rigs
- BP Seeks Stake In Cairn Energy Senegal Assets (Nov 20)
- Officials: BP, Eni Interested In Developing Iraq's Majnoon Oilfield (Nov 20)
- Aker BP Buys Hess' Norway Unit For $2B (Oct 24)