Targa's deal is the latest in a series of multibillion-dollar projects recently commissioned by oil giants and governments to help move oil and gas around the world.

Targa Resources (NYSE:TRGP) is a midstream energy group, playing a vital role in the energy sector. These businesses link upstream companies, which drill and extract the raw product, and downstream businesses, which refine and sell it to consumers.

Most oil and gas majors manage this part of the process themselves, but in markets such as the US, where thousands of smaller producers in oil fields need to connect to major refining and storage hubs, midstream firms are a vital part of the chain.

Growth in the pipeline market

The $65 billion Targa is just one such company in the industry. The firm was founded in 2003 and has grown steadily through organic growth and acquisitions. In 2004, it purchased midstream natural-gas operations from oil major ConocoPhillips and in 2005, it acquired an asset from energy supply business Dynegy. In 2007, the company listed as Targa Resources Partners LP, using the money from the initial public offering (IPO) to seal more deals.

Over the following two decades, Targa secured 20 further agreements, encompassing joint ventures, partnerships, asset sales and stake sales in key infrastructure assets.

Today, the group owns and operates assets across New Mexico, Oklahoma, Texas and Louisiana. It is active in the key oil-production regions of the Permian, the Bakken Three Forks Shale, Eagle Ford Shale and Fort Worth Basin.

The Permian has become one of the most important oil-producing regions in ExxonMobil's portfolio. When the group sealed the $60 billion deal to buy Pioneer Natural Resources in May 2024, it doubled its footprint in the region and laid out plans to drive production to two million oil-equivalent barrels per day (boepd) by 2030, up from the 612,000 barrels Exxon produced from the region in 2023.

Production hit a record boepd in the second quarter and is now close to 1.8 million as the group continues to grow at a breathtaking pace.

Exxon's total Permian production consists of between 70% and 75% liquid hydrocarbons (crude oil and natural gas liquids) and 25%-30% natural gas. This needs somewhere to go, and that's where the deal with Targa comes into play.

Exxon has agreed to so-called natural gas liquids (NGL) dedications with Targa, whereby it is legally committed to using the company's midstream assets for transport, processing, or fractionation (a physical and chemical separation process) of NGL production from its key fields in the Permian region.

Following these commitments, Targa has announced three new natural-gas processing plants in the Permian Delaware: Wrangler, Ranger, and Ranger II, with a combined capacity of approximately 825 million cubic feet per day.

The plants are expected to be operational in the first half of 2028, with scope for up to five additional processing plants. It also announced plans to build a new, approximately 70-mile, natural-gas pipeline called Bull Run II, supported by take-or-pay commitments (whereby producers buy a fixed amount of capacity and pay whether they use it or not).

To meet these commitments, Targa has upgraded its expected capital spending for the year from $4.5 billion to $5 billion. The business spent $2.1 billion on growth and maintenance capital in the first half of 2026, up 23% from the same period in 2025.

A new gold rush

Despite substantial efforts by policymakers over the past two decades to wean the world off its addiction to hydrocarbons, there has been no let-up in the relentless march of the oil and gas industry.

Pipelines and midstream assets are an often overlooked part of this market, but the conflict in the Middle East has highlighted their importance to the global economy.

With the Strait of Hormuz closed to shipping, pipelines across the Middle East have become critically important for the region's oil and gas producers.

In the past two months, the United Arab Emirates has announced plans to open a new pipeline alongside its existing Habshan-Fujairah pipeline, doubling its capacity.

Meanwhile, America, Iraq and Qatar have also announced plans to upgrade a pipeline from Iraq to Syria, and Chevron is in talks to build a series of them from Iraq to Syria and Turkey.

According to The Economist, citing information from Global Energy Monitor, an oil data and research firm, 12,300 kilometres of pipelines are currently under construction worldwide, with an additional 20,100 kilometres proposed.

Taken together, these additions represent nearly a 10% increase over the 350,000 kilometres of pipelines currently in operation worldwide.

The most cost-effective way to get oil and gas from production fields (usually located inland or in deep water) to refineries and key export markets is by tanker.

Transporting each barrel of oil on the world's largest seagoing tankers can cost as little as a few dollars a barrel. But when it is impossible to use tankers to transport them, producers have no choice but to turn to other methods such as rail, road or pipelines.

A large-diameter pipeline that can carry around one millions barrels of oil per day costs, on average, about $5 million per kilometre, or $5 billion for a 1,000 kilometre pipeline.

That's assuming the pipeline is laid over relatively flat terrain. If mountains, rivers and lakes get in the way, costs can rise significantly.

The significant upfront capital cost is why midstream companies and pipeline owners turn to take-or-pay agreements.

Under these agreements, customers purchase a minimum amount of transport capacity on the pipeline and pay a fee for this capacity, often indexed to the price of oil over an extended period (frequently a decade or more).

The company has to pay to use this capacity whether or not it has oil to transport. This dramatically reduces the risk inherent in the project for the pipeline-operating company and its lenders.

Pipelines require a lot of capital to start, but the long-term economics are hard to argue with.

Data compiled by The Economist shows that the cost of transporting oil via a pipeline is, on average, around $5 per barrel. The cost rises to $18 per barrel when oil is transported via road or rail.

At the height of the US-Iran conflict earlier this year, some reports emerged of companies in central Africa paying as much as $200 a barrel, with $50 of that covering transport costs alone.

No wonder, then, that there is heavy investment in expanding pipeline networks to cut costs and improve reliability. In East Africa, for example, a 1,500 kilometre pipeline is under construction to transport oil from Uganda to the Tanzanian coast.

Argentina is building a 440 kilometre pipeline to connect its key oil fields in the centre of the country to the Atlantic.

There is a growing opportunity for investors. Because returns from pipelines are relatively stable and predictable, thanks to pre-agreed take-or-pay contracts, private infrastructure funds have flooded into the market.

According to McKenzie, a consultancy, assets under management across private infrastructure funds have rocketed to $1.6 trillion in recent years.

This year, global investment group KKR finished raising money for its largest-ever infrastructure fund with a total value of $19 billion. It's almost certain a large chunk of this will go to pipeline projects. Blackstone and Brookfield are also getting in on the action. KKR, Blackstone and Brookfield have signed a $16 billion deal with Kuwait's oil company for a stake in the country's pipeline network.

Don't be tempted by partnerships

The midstream sector is particularly strong in the United States thanks to a quirk of US tax law.

Midstream firms can be structured as master limited partnerships (MLPs), which are pass-through entities much like real-estate investment trusts (REITs).

MLPs pay no taxes, so they can distribute much more of their cash flow to investors. Investors then pay tax on these distributions. Over the past decade, many former MLPs have transitioned to C-corporations (a standard limited company) following a change introduced by the 2017 Tax Cuts and Jobs Act.

The changes have opened these companies to a wider range of investors, but yields have fallen because dividends are now paid out after corporate tax; in the partnership model the tax liability falls on the investor.

As a rough guide, the Alerian MLP ETF currently yields 7.4% on a trailing 12-month basis, while the Alerian Midstream Energy Dividend UCITS ETF, which has strict limits on MLP exposure, yields just 3.6%.

The Alerian Midstream Energy Dividend UCITS ETF has enforced limits on exposure to MLPs owing to K-1 tax constraints – the reason why these MLPs are unsuitable for all but the most sophisticated investors. A Schedule K-1 Federal Tax Form is issued by US partnerships to report a partner's share of its income, losses, capital gains and dividends.

In short, they are a nightmare for non-US investors. Even smaller domestic US investors generally avoid partnerships to avoid the added administration these tax requirements create. Very sophisticated investors who want exposure to these businesses may use total return swaps or other synthetic instruments instead, rather than becoming entangled in the web of compliance. Don't be tempted by a high yield on a US midstream MLP.

Fortunately, plenty of other options exist for investors to play this theme. Kinder Morgan (NYSE: KMI), the largest natural gas-pipeline operator in the United States (and a former division of Enron) consolidated its various MLPs into a single traditional C-corporation in 2014 in order to lower its cost of capital and appeal to a broader range of local and international investors. Many of the company's peers have since followed suit.

A tailwind from AI

Kinder Morgan reported record net income of $867 million in the second quarter, up 21% from the same period last year.

Around $660 million of new projects coming on stream helped boost the company's top and bottom lines, including Tennessee Gas Pipeline's (TGP) Cumberland Project, designed to serve a new gas-fired power plant in Tennessee.

The company said it had a construction backlog of $9.7 billion at the end of the quarter, with an additional $400 million of projects not included in the official backlog, but sanctioned to proceed.

Natural-gas projects made up 92% of the backlog, and 60% of those projects are designed to support local power generation and distribution. The company believes it will outperform expectations by 5% for the year, with adjusted earnings before interest, tax, depreciation and amortisation (EBITDA) of $9 billion and a 12% rise in adjusted earnings per share.

Kinder Morgan, like other US midstream companies, is benefiting from increasing demand for power across the US driven by the AI boom. According to Goldman Sachs Research, domestic power demand from data centres is projected to more than double from 31 gigawatts (GW) to 66 GW by 2027, consuming over 8.5% of total US peak summer electricity.

To keep up, companies are commissioning new natural-gas power plants, which can be brought online in a few years and located next to data centres; pipelines are needed to connect these facilities to production zones.

Kinder Morgan may be the largest natural-gas pipeline operator in the sector, but peer Enbridge (Toronto: ENB) is worth nearly twice as much.

It plans to spend between C$10 billion (£5.3 billion) and C$11 billion this year, with half of that already spent in the first six months. It is constructing the $4 billion Sunrise expansion of its British Columbia pipeline (adding 140 kilometres of new pipeline in addition to upgrading the capacity of the existing pipeline) and spending $1 billion relocating a pipeline in Wisconsin.

Williams Companies (NYSE: WMB), the second-largest pipeline group after Enbridge in market value, has raised its spending guidance for the acquisition of Momentum Midstream. It is now projecting spending between $7.3 billion and $7.9 billion in 2026.

Enterprise Product Partners is spending around half as much, with capital spending earmarked at between $2.9 billion and $3.4 billion, net of asset sale proceeds.

Key projects include two new gas-processing plants in the Permian Basin, illustrating the growing importance of natural-gas processing and transportation.

Enterprise Product Partners is the fastest-growing of the large midstream companies, but it is also still structured as a partnership. It reported a 19% increase in adjusted cash flow from operations in the first half to $2.5 billion, as well as a 28% increase in net income, thanks primarily international demand for US natural-gas liquids and crude oil.

Energy Transfer also set several all-time record volumes, notably in natural-gas liquids transportation volumes, which increased 13%, and exports, which increased 25%. Distributable cash flow rose 32% to $2.6 billion. Enbridge, Williams and Kingdom Morgan are all trading at roughly the same valuation, with a price/ earnings ratio (p/e) in the low 20s and a yield between 3% and 5.5%.

The Alerian Midstream Energy Dividend UCITS ETF (LSE: MMLP) offers exposure to all three companies, plus 16 others, with Kinder Morgan, Williams, Enbridge and Targa comprising around 40% of the fund. Investors also get synthetic exposure to the Alerian MLP index.

The picks-and-shovels plays

Infrastructure provides a steady, predictable return. But if you want something offering a bit more excitement, consider the companies providing the picks and shovels to help build future pipelines. Companies worthy of research include Caterpillar (NYSE: CAT), Tenaris (NYSE: TS), MasTec (NYSE: MTZ) and Primoris Services Corporation (NYSE: PRIM). Caterpillar is a broad-based play on the health of the US economy. The company reported record revenue of $20.5 billion in the second quarter, up 24% year on year – the first time Caterpillar has reported more than $20 billion of revenue in a single quarter.

Meanwhile, the company's order backlog hit a record of $72.1 billion, that's not just related to its diggers. While Caterpillar is widely associated with earth-moving and construction equipment, it also operates the SPM oil and gas brand and manufactures equipment for gas power plants. This energy and transportation division increased sales by 17% year on year. While the stock has dipped recently, it is still trading at 25 times projected 2027 earnings.

Tenaris is one of the more interesting companies in the area. It supplies tubular steel used to make pipelines worldwide. Sales fell 4% in the second quarter, mainly because shipments to customers in the Middle East were postponed owing to the conflict.

Lower deliveries to Kuwait and Iraq were, however, offset by higher sales to Venezuela and Argentina, along with the start of delivery of offshore line pipes to the Sakarya Black Sea development in Europe.

The company reported a $3.6 billion net cash position at the end of June, compared with a $19bn market capitalisation. The stock is on a forward p/e of 13.9.

MasTec and Primoris are two of the largest engineering construction contractors in North America. The latter is more focused on utilities, while the former has a big pipeline and energy business. Still, both recently reported record second-quarter sales and record order backlogs.

MasTec reported a record 18-month backlog of $21.4 billion; of this total, $1.8 billion was allocated to its pipeline segment, while Primoris achieved a record total backlog of $13.9 billion (comprising $7.7 billion in the utilities segment and $6.2 billion in energy).

MasTec recently acquired The Superior Group to expand its services into datacentre infrastructure and trades at the higher valuation of the two (21 times 2027 earnings versus 14 for Primoris). That's because Primoris reported a loss for the second quarter, despite record sales. The losses stemmed from cost overruns on six renewable-energy projects. All of these will be complete by the end of the year, which should draw a line under the situation.

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The trouble is, it is not likely to work out that way. The ratings agencies were quite clear that they were grading Scotland on the basis that it was still part of the United Kingdom, and the debt backed by the Bank of England and the Treasury in London. If Scotland were an independent country it would surely be a very different story.

To start with, Scotland runs a huge budget deficit. For 2024-2025 it rose from £21 billion to £26 billion. That is 11% of GDP, compared with 5.1% for the UK as a whole. If you took out oil, which might not all go to Scotland in a separation agreement with the rest of the UK, it would rise to a terrifying 14%. The rise was largely on account of lower revenues from North Sea oil and gas, but the SNP is fiercely opposed to the oil industry, and wants to close it down as quickly as possible, so the deficit would be a lot worse if the country became independent. Its deficit would rank as one of the highest in the developed world. It is behind Timor-Leste, at 48% of GDP, and Ukraine at 18%, if above Egypt and Zimbabwe. It is hard to believe that borrowing on that scale would be sustainable for very long.

Next, Scotland has a political class that is addicted to spending. Ever since the devolved government was created at the start of the century the one thing it has proved very good at is giving away free stuff. Higher education does not have to be paid for, and neither do prescriptions, or bus travel if you are under 22 or over 60. It makes politicians sound generous. Some of that is paid for with higher income-tax rates in Scotland than in the rest of the country, but most of it comes from subsidies from London. Public spending is already more than £2,000 per person higher in Scotland than in the rest of the UK, but the budget deficit is still huge. It is hard to see any government in Edinburgh changing that.

It's hard to think of anything worse than Scotland's proposed 'kilts'

Finally, Scotland may break away from the UK at some stage, and, if it does so, it may have to issue its own currency. The SNP has always maintained that it can carry on using the pound after independence, if it ever happens, and the Bank of England will remain the ultimate guarantor of its debts. But the government in Westminster has never agreed to it and neither has the Bank. It is hard to see why they ever would. Anyone holding a “kilt” has to reckon with the possibility that Scotland may have to issue its own currency at some stage and that it will sharply devalue against the pound. Measured in sterling, or indeed dollars or euros, they will face huge losses on their holdings.

In reality, it is hard to think of a worse investment. A market in “kilts” will make that painfully clear almost as soon as it is launched. It might start out trading at the same price as UK-issued gilts, but it will very quickly start to deviate from that. If a second referendum on independence is mooted, prices will plunge if there are polls showing a “yes” vote, which paradoxically, will make that outcome far less likely.

If there is a prospect of a vote being held, prices will start to sink as investors weigh the possibility that it might be a Treasury in Edinburgh rather than London that has to pay them back. Scottish politicians pushing for “kilts” might imagine it will strengthen the case for independence and bolster their financial credibility. More likely is that it will backfire spectacularly, making it clear that an independent Scotland would struggle to pay its bills.

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On the other hand, the next five years look pretty positive. It’s obvious that the world is going to go nuclear now, and that small modular reactors (SMRs) are going to provide the power artificial intelligence so badly needs.

However, it will be a good five years before they come on stream, so what is going to provide the power in the interim? The answer is natural gas. There is a problem though: supply. America’s gas wells seem to be drying up.

The North American shale gas revolution dramatically changed the outlook for fossil fuels. Peak Oil was a huge theme in the years before the global financial crisis, and then it disappeared, practically overnight.

Between 2005 and 2020, US natural gas production grew 90%, with shale accounting for the vast majority of it. In 2005, shale gas made up about 5% of US natural gas production; by 2020, the figure had risen to over 75%.

By 2017, the US had become a net exporter, especially of more transportable liquefied natural gas (LNG). The price, meanwhile, plummeted – good for consumers. Prices slipped from $16 per metric million British thermal units (MMBtu) to $3.50 today.

Obviously, we in the UK and Europe pay way more for our natural gas than they do in North America. It’s absurd: we have enough to supply ourselves in the UK. But we don’t because fracking is deemed environmentally damaging.

So we import gas from abroad, which is produced by, you guessed it, fracking. I suppose if it is fracked somewhere else, it’s less harmful. Then there are the transport costs and the environmental costs that come with that.

Where does the US get their natural gas?

Spanning Ohio, New York, West Virginia and Pennsylvania, Marcellus is the largest natural gas-producing field in the United States, contributing over 25% of production. In 2010, output was two billion cubic feet per day (bcf/d). By 2023, it exceeded 35 bcf/d, but production has been falling for almost a year now. We are currently at 26.7 bcf/d.

The next largest is Haynesville, in Louisiana, Texas, and parts of Arkansas. Extraction costs here are higher, and production stands at 16 bcf/d, but it is slowing here too, according to analysts Goehring & Rozencwajg. One of the few areas of growth is the Permian Basin, in Texas and New Mexico, currently producing approximately 23 bcf/d, but even there, growth is modest.

Now, it may be that the reason for stagnating growth is low prices, and higher prices will result in increased production. They usually do. That is the way with commodities. But natural gas prices have already doubled to around $3.50 per MMBtu this year, and they keep on creeping up. The other interpretation is that the North American shale gas revolution has passed its peak.

With America’s new president, you can expect plenty more investment in production than under the Democrats, and that should bring the price down, but the gas price rocketed after the election (from $2.70MMBtu to $3.50MMBtu) before pulling back to $3.10MMBtu, where it sits now. It may also be that Russian gas taps come back online to the EU next year, which means America will lose its new market.

Beware of calling peaks in natural gas. The world – when regulators allow it – has a habit of finding this abundant and clean energy source, and that always sends the price down. But all of this conjecture is factored into the price. And that is rising. For now.

How to invest in natural gas

The simplest way is to own the iShares Oil & Gas Exploration & Production ETF (LSE: SPOG), which is finally on the move. If you want something a bit more spicy, there is the Diversified Energy Company (LSE: DEC), which is the largest owner of old natural gas wells in the United States.

Diversified Energy acquires existing long-life, low-decline producing wells and then tries to improve or restore production. It hit a rough patch with some “well leaks and accounting tricks”, as my friend Charlie Morris of ByteTree puts it, which got the company into trouble and resulted in a 70% decline in the share price.

But now those problems are behind it, it should face fewer permitting obstacles under the new US administration. It is cheap for what it is: the market value is around $830 million. High-cost producers can be good plays on rising commodity prices. As the price of the underlying commodity rises, they suddenly become profitable.

Company X produces a commodity at £100/ unit. Company Y produces it at £200/unit. The commodity’s price jumps from £210 to £220. Company X’s profits do not even rise 10%. Company Y’s double. On the other hand, if the commodity falls to £190, company Y is in deep trouble.

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The news means the average home's gas and electricity bill will drop £122 a year (£10 a month) to £1,568 in July. It follows a 12% fall in the cap in April. The fall was on a par with what experts had predicted, and came as wholesale prices trickled down to within touching distance of pre-crisis levels.

However, there have been warnings that energy prices could soar this autumn and winter, with experts urging political parties on the general election campaign trail to reform the price cap. Ofgem recently launched a consultation on whether to scrap it in light of the UK’s net-zero push.

Energy prices are expected to remain relatively stable over the next two price cap periods. But while fixed deals have returned to the market, very few are competitive with the rate of the cap.

Ofgem energy price cap falls by fifth year-on-year

Energy bills for a typical household will tumble to £1,568 per year from 1 July for around 28 million households. The 7% fall means energy bills will be £10 a month cheaper than they currently are.

Compared to July 2023, when the price cap took over from the Energy Price Guarantee as the de facto energy bills rate for most bill payers, prices will have plummeted 21% (£408) when the new energy bills rate comes in.

This means the average bill will have gone from £165 per month to £131 year-on-year by this summer. But costs still remain significantly above where they were when the energy crisis began in the autumn of 2021. Back then, the price cap was £1,370 a year - 14% lower than the July cap and almost a quarter below current energy prices. The fixed deals on offer at the time were likely to be cheaper still, with many coming in below £1,000 a year.

The unit rates under the new cap (for those paying via direct debit) will be:

While standing charges have remained unchanged, they will still come in at £334 a year for a dual fuel household. So, in essence, you will be paying more than £30 a month before you've used any energy. The figure rises to £369 for standard credit bill payers.

What does the new Ofgem energy price cap mean for my energy bills?

The price cap announcement will affect around 28 million households in just over a month's time. According to Ofgem, there are roughly 18 million people in the UK who are on a standard variable tariff (SVT - the type of energy deal governed by the price cap), and pay via direct debit. This is the cheapest way of paying for your energy on this type of tariff.

Ofgem said a further five million households are on 'standard credit' SVTs (i.e. they pay their bill after using the energy they've been charged for), with four million homes on an SVT via a prepayment meter. Another four million households have signed up for a fixed tariff, and are therefore unaffected by the new price cap.

A key thing to note is that the only Ofgem figure that really matters when it comes to the price cap is the 7% fall. This is because the cash figures given by Ofgem solely apply to the energy regulator’s idea of a typical household.

The price cap sets a limit on what you can be charged per kilowatt hour (kWh) for your gas and electricity. It also limits how high standing charges can be. The exact figures vary depending on what region you live in. So, not only will your final bill depend on how much energy you use, but it will also hinge on your postcode.

Another thing to be aware of is that today’s news will not impact your energy bills until 1 July. So, you won’t need to take a meter reading until the end of June. The new rate will then apply for three months, as Ofgem sets rates on a quarterly basis.

Cornwall Insight: ‘bad news on the way this winter’

The latest Ofgem energy price cap came in almost exactly the same as forecasts had suggested. Earlier this week, Cornwall Insight had said the annual figure would be £1,574 - just £6 higher than the eventual figure we received on Friday (24 May) - as a result of lower wholesale prices since the turn of the year.

But the energy consultancy warned the good news could be short-lived. It said it now expects domestic gas and electricity prices will rise 12% from October to an annual figure of £1,762, and will remain close to this level for the January 2025 price cap.

Welcoming the reintroduction of the Warm Home Discount benefit for next winter, principal consultant at Cornwall Insight, Dr Craig Lowrey, said: “The anticipated rise in bills as we move into the winter months, emphasises the continued volatility of the market and the importance of providing protection for vulnerable households.

“It is clear the cap in its current form is not going to bring down bills to pre-crisis levels. However, while the general election is likely to put a halt to any immediate reforms to household energy bills, parties may use this opportunity to highlight how they intend to approach this challenge in the future.”

His comments were echoed by energy supplier trade body Energy UK, which said it wants the next government to work with the industry and Ofgem to find a "long-term solution" to high energy bills and soaring consumer debt levels.

Comparison website Uswitch said the latest forecasts meant there were “storm clouds on the horizon” for households. It urged people to consider fixed-rate deals.

Will Owen, the site’s energy expert, said: “If you’d prefer to avoid the uncertainty of rising costs in winter, now is a good time to think about taking a fixed energy deal, which would let you lock in rates while prices are cheaper. Fixed energy tariffs are the cheapest they’ve been since summer 2021 and there are some great value deals currently worth considering.”

Any increase to energy bills later this year would also come as bad news to the next government. Energy bills were one of the key reasons why inflation, as measured by the Consumer Prices Index (CPI), fell to 2.3% in April. The latest forecasts suggest there could be a spike in the headline rate later this year - something which could keep interest rates higher for longer.

The Republic of Kazakhstan's Ministry of Oil & Gas approval, for the period 2012 to 2014, is the final regulatory consent needed before pilot production can start on the NW Konys Field.

CEO David Wilkes commented, "We and our partner LGI are now in a position to commence pilot production from two of our wells on NW Konys and at the same time will test the outcome of wells NK 9 and NK 10 in early in 2012."

Roxi now expects Well NK 4 & NK 6 will be put into pilot production in the first quarter 2012.

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cj

The British firm owns 30% of block "BM-S-9" in the Santos Basin off the coast of Brazil.

Its partner in the project, Petroleo Brasileiro, has submitted a "Declaration of Commerciality" (DoC) with the relevant authorities.

BG Group says this DoC "marks the start of the production phase for the Guar field".

The two partners are looking to name the block Sapinho. They also claim it has "excellent reservoirs with good quality 30 API oil".

Over 2011 BG Group is 5.45% up. Over the last five years the stock has doubled in value.

BS

IRG wants to build a large gas storage facility underground at the site to alleviate Italy's gas supply disruptions during the winter.

The Company expects to receive the signed, ministerial decree confirming the approval early in 2012 after the holiday season.

It characterises the project as "a much-needed infrastructural investment in an extremely under-supplied market."

Of course, IRG would say that, but with the Rivara site located at the hub of Italy's gas transmission system, the scheme does have a certain logic.

At 9.34am the stock was up 17.11% at 44.5p. Over the year to date IRG is down 3.83%.

BS

The deferred charges are to be paid by the state of New York after a verbal decision from the New York Public Service Commission (to be confirmed in writing) relating to "pensions, environmental costs, capital expenditure and other activities." The total will be $211m whereas the company wanted $236m.

The storm compensation is a result of Hurricane Irene and amounts to a total of $25m.

"National Grid is very pleased with the outcome of the deferral filing", said Ken Daly, President of the New York division. He added: "It will allow us to pass significant bill reductions onto our Upstate New York electric customers, while at the same time recovering expenses previously incurred in operating our electric system."

The positive cash flow from this money, however, will need to be set against the loss of the Long Island electricity system contract which has been managed by National Grid for 13 years. The company says the contribution to earnings of the contract was "less than one percent of Group operating profit".

Nartional Grid has gained 11% this year but is down 18% over the last five years.

BS

The 'Carrot Creek' assets include 80 producing wells, associated infrastructure and a gas processing plant with natural gas liquid extraction capability.

Centrica called the deal "a unique opportunity to invest in a liquids-rich, multi-zone area that had significant development potential".

The purchase will provide the firm's North American subsidiary, Direct Energy, with a net additional 25.6bn cubic feet equivalent of proven and probable reserves, an increase of approximately 4%, split 42% gas and 58% liquids.

The resulting net increase in production will be 6.2m cubic feet equivalent per day, Centrica said.

"This represents both a valuable addition to our existing reserves and offers the potential to develop significant resources," said Chris Weston, chief executive of Direct Energy.

This acquisition marks the latest stage in the growth of Direct Energy's upstream business.

Last year it bought natural gas assets in the Wildcat Hills region of Alberta, increasing its natural gas reserves by approximately 60%.

Northern said it considered that Vinkega was "not a prospect of sufficient size and structural appeal to have attracted a wildcat well on the Drenthe III licence

alone."

The Vinkega gas field was discovered when Vermilion Oil & Gas Netherlands drilled the Vinkega-1 well on its Gorredijk Licence. The field has been mapped as underlying both part of the Gorredijk licence and part of the Drenthe III licence.

All the Drenthe III Licence interest holders have agreed to the sale of their respective Drenthe III interests in the Vinkega field to Vermilion, with Northern Petroleum Netherland's pro-rated share of the consideration being €3.1875m.

70% of the purchase price has already been paid on signing of agreement, with the remaining 30% payable following completion, which is subject to the usual governmental and other consents.

Derek Musgrove, Managing Director of Northern, said: "The sale will enable a smooth transition into production under Vermilion's team and make a useful financial contribution to our hopefully successful exploration activities on the Drenthe III licence in the near future."

The share price rose 6.58% to 81p by 12:59PM.

NR

Ascent, which has a 75% stake in the project, used hydraulic fracturing for the test and achieved a stabilised rate of 240,000m cubed of gas or the equivalent of 1,420 barrels of oil per day.

Ascent's Managing Director, Jeremy Eng commented, "This result from Pg-10 is excellent and exceeds our expectations. It follows the commercial, although less prolific, result from the Pg-11A stimulation, and gives us confidence that the redevelopment of the Petiovci field can and will now proceed.

At 8.51am Ascent's shares were trading at 2.16p, up 30.85%, although in the year to date the firm's stock has fallen 76%.

BS

The PNG LNG project is an integrated development that includes gas production and processing facilities, onshore and offshore pipelines and liquefaction facilities with the capacity of 6.6m tonnes per year.

The contract was awarded by Chicago Bridge and Iron and Clough. The plant will be operated by Esso Highlands, a subsidiary of Exxon Mobile.

Kentz chief executive Hugh O'Donnell, said he was delighted by the win.

"We look forward to being part of a successful project completion in the region," he said.

Group copper production totalled 165,000 tonnes, a 4.0% increase compared with the previous quarter. This increase was mainly due to higher production at Esperanza as the ramp-up process continued and also from Los Pelambres as a result of higher ore grades.

Copper production was 453,500 tonnes in the first nine months of 2011 compared with 393,600 tonnes in the first nine months of 2010, reflecting the production from Esperanza.

As previously announced, current estimates for 2011 group copper production are for between 620,000 and 640,000 tonnes.

Molybdenum production at Los Pelambres in the third quarter was 2,400 tonnes. The 7.7% decrease in production from the previous quarter is mainly due to lower ore grades.

Gold production in the three month period rose to 54,300 ounces from 48,600 ounces in the previous quarter, mainly due to the continued ramp-up of Esperanza.

Group cash costs (net of by-product credits) in the July-September quarter eased to 100.5 cents per pound compared to 103.8 cents per pound in the previous quarter. This decrease was mainly due to reduced costs at Esperanza reflecting the progress of the ramp-up and lower costs at El Tesoro, partly offset by increases at Los Pelambres (due to lower by-product credits) and Michilla.

The group has approved the initiation of a $109m feasibility study for the potential expansion of copper production in its Sierra Gorda district. The study will look into the construction of new facilities to process sulphide ores from each of the Telgrafo and Caracoles deposits.

In total, this could potentially increase sulphide processing capacity in the Sierra Gorda district from 97,000 tonnes of ore per day when the Esperanza mine reaches design capacity to a total of around 300,000 tonnes of ore per day by mid to late 2016. Additionally, both Telgrafo and Caracoles have oxide ores which could be processed at the El Tesoro SX-EW plant maintaining cathode production at near plant capacity until about 2020. The feasibility study is expected to be completed in early 2013.

The company added that transport division had a solid operational performance in the third quarter with total volumes transported of 2.1m tonnes, the same as in the previous quarter.

As for the water business, volumes of 11.8 million cubic metres in the third quarter were marginally higher than the 11.7 million cubic metres of the previous quarter.

The share price rose 25p to 1,139p on the production update.

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