The forte of independents is revitalizing mature assets and exploring undeveloped acreage left behind by the majors. They did it onshore North America in the 1980s and in the Gulf of Mexico in the 1990s. Next stop: the U.K. sector of the North Sea. Companies wanting to dive in are seeking deals and driving up asset prices. In the past three years, several U.S. and Canadian independents entered the province for the first time by acquiring producing fields, through farmouts and joint ventures, or by participating in the annual licensing rounds. These newcomers include Apache Corp., Newfield Exploration, EOG Resources, ATP Oil & Gas, Carrizo Oil & Gas, Challenger Minerals and Walter Oil & Gas. In addition, nearly 30 U.K start-up companies are seeking their first acquisition, keen to follow in the footsteps of successful domestic operations, such as Paladin, Tullow and Dana, says Simon Ashby-Rudd, managing director of Waterous & Co.'s London office. "This is still a relatively small market compared with the U.S., but last year there were 40 asset transactions in the North Sea," says Paul Willcocks, managing director of Harrison Lovegrove & Co., the London firm that advised BP on the sale of Forties Field to Apache. These deals ranged from $2 million to the $630 million that Apache paid for Forties. (For more on M&A in the region, see "M&A Across the Pond" in this issue.) For a generation, this mature area has been dominated by majors with huge projects that were out of reach of most independents. Fewer than a dozen companies still control the majority of the assets and infrastructure. But a sea change has started that will transform the North Sea through the rest of the decade. In 2002, new entrants operated 34% of the wells drilled, Brian Nixon, Scottish Enterprise's director of energy, said at the Offshore Technology Conference in Houston in May. OTC and several other conferences this year have focused on North Sea opportunities. The most recent offshore U.K. licensing round, just held in June, made available the most blocks since the second round back in 1965. At press time, the body that regulates the U.K. North Sea, the U.K. Department of Trade & Industry (DTI), announced 20 of the 68 companies that applied for licenses are potentially new entrants. In last year's round, 27 new entrants were awarded blocks. "This is a further sign that there remains plenty of interest and belief in the potential of the North Sea," the U.K.'s energy minister, Stephen Timms, said last month. License awards will be announced this August or September. Fast-moving companies hungry for reserve growth see opportunity opening not unlike what they saw in the Gulf of Mexico some 10 or 15 years ago. There are differences though. For example, blocks are much larger than in the Gulf. The average North Sea discovery size has declined, but at an average 20- to 40 million barrels of oil equivalent (BOE), it is still enough to please an independent. Although operating costs are higher than in the Gulf, the economics work because average flow rates are higher and no lease bonus is required-in addition, since 2003 there is no royalty on new production. "The analogies are striking," says John Seitz, co-chief executive officer in newly minted Endeavour International Corp., a Houston-based independent focused solely on the North Sea. It went public in March and trades on the American Stock Exchange. "The biggest difference is there is not a lot of turnover of acreage. The majors have held the big blocks for nearly 40 years. But we've had several months now to work the seismic data we acquired, and I'll tell you unequivocably, we're seeing plenty of opportunities." Incentives needed This renewed focus on the U.K. continental shelf (UKCS) could not come at a better time-production is falling. In 2003 the UKCS produced about 4.2 million BOE per day. But the government's target of a modest 4 million BOE a day in 2005 may be missed. Worse, sustaining an even smaller target of 3 million barrels a day by 2010 is unlikely, according to 29 E&P companies surveyed recently by the U.K. Offshore Operators Association (UKOOA). That is, unless exploration taps into the government's estimate of 4- to 25 billion BOE of undiscovered reserves. Most alarming of all, in 2005 the United Kingdom will become a net importer of natural gas for the first time in years, and by 2007, it may have to import crude oil as well. The UKOOA survey projects that development costs will trend 15% higher over this decade and unit operating costs will be 10% higher in 2004 alone than forecast a year ago. Exploration, appraisal and development drilling in 2003 were at historically low levels despite high commodity prices. Rig dayrates remain below the 2001 peak. As the North Sea enters a new chapter, it will require a higher level of operator, says Martin Lovegrove, chief executive of Harrison Lovegrove. "There are probably few companies who can make the grade...but there is still a lot of life left for those companies prepared to operate in such a mature environment," he says. "The industry faces a two- or three-year window of opportunity if it is to secure the future...the trend to spend more whilst producing less is unsustainable," the UKOOA reported in January. "This will require the combined efforts of industry, the supply chain and government through business models, improved application of technology...and appropriate fiscal incentives." No wonder DTI is pushing so hard to attract new companies. (See "Welcome to the North Sea," Oil and Gas Investor, May 2003.) It has modified its tax and royalty regime for North Sea exploration and production. It says if negotiations between operators and infrastructure owners break down, it has the right to step in and get involved. In February Timms introduced a new frontier license for blocks north and west of the Shetland Islands off northern Scotland. The rental fees were cut 90% for the first two years. The new promote license introduced last year attracted 42 applications this June. Again, rental fees are one-tenth the traditional license for the first two years. DTI also created the "fallow blocks initiative," where any fallow block that sees no activity within one year of being posted on its web site must be relinquished so that it can be offered to others. There are 151 such blocks. (For details on these licenses and how they work, see "The UKCS isn't fully explored," Timms said at OTC. "We want to see those opportunities realized. There is absolutely no room for complacency here." Several U.S. E&P companies are generally applauding these efforts and would like to see DTI do even more. "DTI has gone out of its way. They have worked very hard [to create the right conditions]," says T. Paul Bulmahn, chairman and president of Houston-based ATP. The independent, which has 12 UKCS blocks, just brought on its first production there this February at Helvellyn Field in the southern gas basin. Beyond DTI's various incentives, independents are intrigued by what interests them most-drilling success. That came recently from Buzzard Field in the central North Sea and primarily an oil basin. It was discovered by Calgary's PanCanadian Petroleum (now EnCana). Buzzard has an estimated 1.2 billion barrels of oil in place with about 550 million recoverable, making it the largest find in the North Sea in more than a decade. It will come onstream in late 2006 and plateau at about 75,000 barrels per day net to EnCana. At press time, Petro-Canada bought a 29.9% working interest in Buzzard from Intrepid Energy North Sea Ltd. for US$840 million, signaling how much value there could be. Another good example is tiny Oilexco, also based in Calgary. It won some acreage in last year's round and drilled an exploration well 100%. It found a 50-million-barrel field. DTI estimates some 61 new fields could be developed from now to 2008. Their average reserve size is an estimated 44 million BOE. Sources say prices for undeveloped assets have not suffered the same price inflation as producing assets have, although they, too, are starting to increase. Apache's prize The deal that really shone a spotlight on the UKCS occurred in April 2003 when Apache Corp. acquired 96% interest in Forties Field from BP, for an adjusted price of $630 million. Apache assumed abandonment liability for Forties and this was reflected in the purchase price. Forties was a company-maker for BP, a much smaller company when it discovered the field in 1970. BP sanctioned Forties for development when oil was just $2.70 per barrel. Since going online in 1975, Forties has produced 2.5 billion barrels of oil and at its peak, was producing 500,000 barrels per day. It remains the largest field ever found in the UKCS. At year-end 2003, Apache booked 148.5 million BOE in proved reserves at Forties, making the field the largest in its global portfolio. If just an additional 1% of the original oil in place is recovered, that's 40 million barrels of oil. "It's an incredible field," says John Crum, executive vice president and managing director, Apache North Sea Ltd., who last year came from heading the Australian operation to oversee the Aberdeen office. "Our infill targets here are some of the largest in the whole corporation. This is a fantastic project by anybody's standards. "In Farmington [New Mexico, where Crum worked earlier in his career, well before joining Apache], we talked about permeability in tenths to hundredths of a millidarcy. Here the reservoir is 250 millidarcies to more than a darcy." Despite the reservoir's phenomenal permeability and significant remaining potential, Forties was no longer on BP's most-wanted list as it swung its focus to Russia, the Caspian pipeline, gas in Trinidad and other big projects. After 30 years, Forties had fallen to about 45,000 barrels a day, less than a tenth of the peak. Since Apache took over operations, production has been plagued by periodic shut-ins for mechanical reasons, but is averaging 49,000 barrels a day. But as Apache repairs and replaces equipment, output is rising. At press time, it had reached 59,000 barrels a day. The year-end target is 60,000 a day. New wells should average 2 million barrels of oil each. To achieve that, Apache has a long to-do list (not counting drilling new wells) in order to extend production and add to current proved reserves. On one platform alone, the company lists 200 things to do, says Alan Chesterman, a 22-year BP veteran (mostly on Forties itself) who is Apache's North Sea production manager. Apache is replacing 24 of the 30 turbines in the field with four large new ones on two platforms. It is replacing 16 old cranes with four modern ones. These upgrades will save millions in maintenance costs. "BP didn't do these things because you don't install a swimming pool in the yard when you know you are selling the house," says Crum. The 2004 drilling program calls for 12 wells from Echo platform and four each on Charlie and Delta platforms. At press time, GlobalSantaFe's Galaxy III cantilever jackup was rigging up on Echo-a platform once considered for abandonment. Additionally, four or five workovers are planned. The total drilling budget is about $275 million. The water is about 350 feet deep. "BP had identified 19 drillable locations under its economics, so we know we have at least that many. We think we have 30 or 35 targets. We are right in the middle of the source kitchen. The sands are 550 feet thick in the heart of the field," says Stephen Adiletta, geophysical team leader. (Editor's note: BP's price hurdle for drilling projects was raised to some $20 per barrel of oil.) The field's outer limits are known, but many bypassed pockets of oil were spotted on 3-D and 4-D seismic surveys conducted by BP and Apache. In fact, 4-D was basically first developed at this field, which is full of Paleocene channel sands that are so clean, porous and permeable that BP could image changes in the fluid properties as Forties was produced. "BP did a lot of science on this field," says Crum. "The difference is what we are doing with it. We have found little attic shots that are structurally trapped in the middle of the field, and we're also drilling on the edges of the field. The wells are expensive-$7.5 million on average-but we have drilled one at $4.8 million and another for $6 million. If we can get the costs down to $4 million, then targets of a half-million barrels start to make sense." These smaller targets are important to a company Apache's size, but were below BP's threshold. One of the most urgent tasks is upgrading and maintaining what the Brits call the service kit (surface production facilities). Equipment breakdowns have been common in the old field, causing weekly oil output to seesaw. It's a big task because Forties has five platforms. In 2003 Apache upgraded surface facilities at Alpha, Charlie and Delta. It just finished Bravo. These turnarounds take 10 to 30 days and thousands of man-hours. Some 80 workers swarm the platform at once, to upgrade or replace chokes, valves or compressors; inspect or paint rusted equipment; install more efficient pumps; and so on. It's a crucial task as well, because other operators send their oil through Forties' centrally located Charlie platform that connects to BP's Forties Pipeline to shore. Some 300,000 barrels a day go through, including all production from the Brae complex. Forties infrastructure, as connected to Forties Pipeline, is thus responsible for 40% of the U.K.'s daily oil production. "We joke that if Charlie goes down, we'll get a call from Tony Blair," says Crum. On any given day, at least 300 people are working on Forties, not counting additional personnel when drilling a well. With 70 active wells in the field (about 55 producing and 15 injectors), there is a lot of equipment to oversee and maintain. Apache retained most of BP's platform employees, some of whom have worked on Forties for more than 20 years. Several of them, interviewed independently, used the same word to describe working for Apache: refreshing. One way Apache has brought its can-do culture to Forties is its concept of area ownership. Small sections of a platform are "owned" by two employees who are responsible for improving and maintaining all equipment and operations-and safety-related to that particular site. Some of the before-and-after is dramatic in terms of physical appearance, efficiency and cost reduction. Apache encourages employees to make suggestions and act as if they are spending their own money. Decisions large and small are often made in a day. "We have empowered the people on the platforms and the guys really take to it," says Chesterman. "It's very different from a major where decisions are made at a higher level." Crum adds, "I just love the stories. One employee needed a simple dolly. It was £2,700 at the oilfield supply store in Aberdeen but he found a similar one at a Home Depot-type store for £350." In another example, Crum says, "we are doing flowline designs now for a tenth of the old price." Forties uses gas lift to enhance oil production, powered by diesel compressors. Instead, Apache plans to connect the five platforms with a 4.5-inch gas line and power cable to allow them to share gas and electricity and reduce generator downtime. This gas ring main, as it is called, will cost $30 million to install but save an estimated $12 million a year in diesel costs. What's more, it will help reduce flaring and CO2 emissions by nearly half. "This takes flared gas and uses it as fuel, so we'll no longer need to buy diesel. This project has something for everyone from the government to Greenpeace, and still generates an internal rate of return of 30%," Crum says. Currently Apache sells the oil to BP through the latter's Forties Pipeline, but the transportation agreement permits marketing to virtually any buyer. A portion is sold at fixed prices, the rest at spot. Going forward, Apache will look at lease rounds, asset swaps and farm-ins as well as acquisitions and longer term, at the Dutch and Norwegian sectors as well. Delayed results Houston-based ATP Oil & Gas is also working toward a victory at sea, bringing its successful Gulf strategy to the U.K. and Dutch sectors. In 2000 it opened an office in London and in 2001, acquired its first blocks. Its aim is to acquire proved undeveloped reserves (PUDs) that are not core to the discoverer, then use the latest drilling and subsea tie-back technologies to develop the PUDs cost-efficiently. "The similarities between the Gulf and the North Sea are strong. There is a great opportunity set. DTI showed us a number of fallow blocks that had been drilled but never developed. That's exactly our formula," says president and chairman Bulmahn. He likes the business environment. "There is infrastructure created by the majors so we don't have to create it. There is a fairly stable regulatory climate. DTI provided the ability to expense 100% of an investment in the year it is incurred. Some of the tax changes resulted in projects becoming marginal to the major operators, yet they have potential for us." ATP marked its first North Sea production in February 2004 at Helvellyn, a gas field it acquired from BP in 2001 as part of a package of three fields. ATP drilled one well with a 2,300-foot horizontal leg and tested it in January 2003 at 60 million cubic feet per day. The field is now flowing from the Permian-age Rotliegend and Carboniferous reservoirs at about 9,200 feet. It is producing about 22 million cubic feet a day net to the company, which owns 50%. Aberdeen independent First Oil Expro Ltd. owns the rest. This subsea well was tied into BP's Amethyst platform 9.5 miles away. Some unexpected delays from partners over which ATP had no control, strained its cash flow and operating results last year. But the work for which it was responsible-drilling and completing the well and a required sidetrack, and running the subsea umbilical and pipeline to the platform-was on time and near budget. "We took a real hit in 2003," Bulmahn admits with frustration. "Seven straight years of production increases for ATP ended in 2003 because of the problems at Helvellyn. We felt we had risked the infrastructure issues sufficiently but clearly we had not. We'll be more cautious now." In last year's licensing round, ATP picked up more assets. It acquired 50% of Block 49/30b in 100 feet of water, and 100% of blocks 2/10b and 3/11b, in which are located the Emerald Field, east of the Shetland Islands. The company also acquired an additional block in Emerald, 2/15a, in an out-of-round procedure. Emerald is in about 550 feet of water. Emerald is ATP's largest property based on company estimates, but its reserves have not yet been booked to ATP's account and it is not currently producing. First production began there in 1992 but ceased in 1996 when lower oil prices made it uneconomic to produce through the FPSO (floating production, storage and offloading vessel) that was on site at the time. Only 8% of the estimated 232 million barrels of oil in place had been produced. Some 6,000 barrels per day of Jurassic-age oil were still flowing when the prior operator shut it in. The asset then reverted to the government and lay dormant until it was offered in the 2003 round. Bulmahn thinks Emerald can do much more. "If we can recover 30% of what's remaining, the field is huge for us and a potential company-maker," he says. Although there was some 3-D seismic data available, it had been shot down the faults, so Western Geco is now performing a 3-D shoot across the faults from which ATP can get a better idea where to place the next wells. "The existing reservoir is a big feature, but we're finding the well placement wasn't as optimal as it could have been," says Bulmahn, "and we are seeing potential targets in the Paleocene and Cretaceous reservoirs as well." Bulmahn doesn't see ATP reentering old wells at Emerald. Instead, it plans to install a fixed platform and drill new wells, possibly bringing in some industry partners. This will occur in 2005 or 2006. Roughly one-third of ATP's booked proved reserves are in the North Sea, not counting Emerald. Also ahead lies development at Venture Field (Conoco 50%); Tors, where there are multiple pays (Gaz de France, 25%); and Block 49/30b (Tullow Oil, 50%). These reserves are not booked yet either. ATP will operate these. A March 2004 debt facility obtained from Credit Suisse First Boston will cover all of ATP's 2004 capital expenditures. Development plans are proceeding for several of the fields. Bulmahn hopes to book reserves from Emerald and 49/30b this year. And he has opened an office in The Netherlands after acquiring 50% of the L-06d block in 115 feet of water. First production is anticipated in 2005. "These reservoirs in the North Sea will extend our corporate reserves-to-production ratio extensively. We grew up on one-well reservoirs in the Gulf, but we are now big enough to obtain and produce larger ones. We are in the North Sea to stay." Exploration sizzle Carrizo Oil & Gas Inc. is extending its 3-D-seismic-based exploration model to the North Sea. In the 2003 licensing round, the Houston independent acquired seven blocks, consisting of one traditional license and three of the new promote licenses, in water depths from 30 to 350 feet. All of the blocks are near infrastructure; one is on trend with Forties Field. At press time Carrizo was marketing its seven drillable prospect ideas to a number of potential drilling partners. Although still focused mainly on its Texas and Louisiana Gulf Coast onshore exploration program, entering the North Sea is not the stretch it appears. Two of its directors have experience there-one was on the board of Enterprise Oil-and the company has retained two consulting geologists that between them have about 40 years of North Sea experience, primarily with Arco International. "Is this North Sea presence different, have we lost our focus?" asks S.P. (Chip) Johnson, president and CEO. "No. It is still based on using 3-D seismic to explore for new fields in existing trends. "We are a Gulf Coast exploration company with two new areas of optionality: one in the (North Texas) Barnett Shale, and the other, our exploration upside in the North Sea. We are not risking our balance sheet entering these plays, and now we've got all the exploration sizzle anybody needs." For its entry into the North Sea, Carrizo high-graded areas, acquired 3-D data and generated prospect leads first, then picked up blocks in the 2003 round. Now it is negotiating for partners to drill the prospects. It is the very type of company DTI is looking for-small, flexible, exploration-oriented, willing to farm out to other companies with operating experience and larger drilling budgets. The net profits share in the North Sea is better than that of the Gulf of Mexico, says Jeremy Greene, vice president of exploration. "The North Sea is one of the better places right now for profitability, especially with the promote license. A good prospect in the Gulf on a 5,700-acre block could cost upwards of $3 million to lease, but in the North Sea we received 210,000 acres for a lease cost of less than $100,000 per year," says Johnson. "A lot of companies are entering through asset acquisitions, but that's not us-we are explorers." Carrizo aims to spend its dollars on seismic and leases and farm-out drilling to a partner, retaining a 25% to 50% carried interest. It hopes to get one of the blocks drilled by year-end or in the first quarter of 2005. Once it elects to drill, the block reverts to a traditional license with a well commitment in the following two years. In the southern North Sea gas basin, targets range from 60 billion cubic fee (Bcf) to 200 Bcf of gas. In the central North Sea, where the water is deeper, the targets are 50- to 250 million barrels of oil. The size of some of the left-behind prizes in the North Sea, say 30 Bcf, is very appealing to a company Newfield Exploration Co.'s size, says Steve Campbell, head of investor relations for the Houston company. That's why the southern gas basin is one of its two new core areas, along with its recent entry into Malaysia. Newfield opened a London office two years ago, staffed by five local experts with North Sea experience, as well as one American. It has bid on numerous producing packages, but won only a few small ones so far, spending about $6 million. And it participated in the 2003 and 2004 licensing rounds. In last year's round, Newfield picked up interests in the Cumbria area in Block 49/4a and 49/4b, where it plans a well later this year. Cumbria is the last undrilled fault block near the 650-Bcf Markham Field, which Gaz de France operates. Last year it also bought Chiswick, a field with three wells drilled but not developed, and this asset came with a 20% working interest in nearby Windermere Field. One appraisal well at Chiswick is planned in early 2005. The company plans other wells later this year or in 2005 at the Grove prospect on Cleaver Block North. At West Sole Field it has an alliance with BP and is interpreting BP's data. "The majors could use us as an outsourced exploration arm, where we look at their data, help drill wells and share the upside," Campbell says. "They need new volumes to keep their infrastructure running and their unit costs in check, and we need access to their acreage." He adds, "DTI is very anxious to get the mentality of independents into the North Sea." North Sea start-up When Anadarko Petroleum CEO John Seitz left that company last year, and his friend Bill Transier departed Ocean Energy as CFO when it was sold, the pair knew they wanted to start an international E&P company. After a couple months of what Seitz calls "strenuous analysis" of global hydrocarbon basins, they chose the North Sea as their focus. Thus was born their start-up, which through a reverse merger with a small public shell, went public in March and now trades on Amex as Endeavour International. Management, composed of former Anadarko and Ocean employees, owns 23% of the new company. It opened a London office, participated in the June licensing round, and expects to do exploration later on. It is also seeking acquisitions of assets or corporations, primarily in the central North Sea. At press time negotiation was under way on possible farm-in opportunities. Longer term, Endeavour will look at Norway and the Dutch sector as well. "Most of the U.K. acreage has been in the hands of the original owners for nearly 40 years and is going to expire soon," says co-chief executive Seitz. "We wanted to be in on the very early stage of the transformation. I am extraordinarily encouraged there are so many play concepts that are still undrilled." Endeavour got a jump-start by raising $50 million, and inking an agreement with Petroleum Geo-Services for access to 3D Mega-Merge, a data set that includes 79,200 square kilometers of seismic on the UKCS and Norwegian shelf. In return, PGS has an equity stake in the company-similar to the deal Spinnaker Exploration struck when it started in the Gulf some years ago. Endeavour has alliances with five other companies on different geographic areas to gain additional technical comment, and to apply for licenses with some of them. Next year in the 2005 licensing round, Endeavour expects to be active when even more fallow blocks will be relinquished. "North Sea costs are higher on average than in the Gulf, but you are generally targeting sizes in the 10- to 50-Bcf range that should result in higher flow rates," says Transier, who serves as co-CEO with Seitz. "I think the rate of return is going to be better than in the Gulf." The pair sees a lot of things lining up well. They believe operators of the infrastructure will be motivated to bring new supplies across their platforms because that extends field life and delays the time of abandonment. DTI has promised to intervene if negotiations on access to infrastructure get bogged down. The U.K. gas price is starting to rise. "I think you'll see a lot of independents get involved and they are going to find a lot of oil and gas," says Seitz.