If an independent producer is looking for a relatively hassle-free international experience, it would do well to investigate exploration opportunities in New Zealand, where the scenery is spectacular, the government friendly, and the laws and culture English-based. The country is attracting new interest lately due to several factors. One is the oil industry's preference for doing business in a secure place. "I like it here. I can speak the language, drink the water and understand what's going on," joked one North American oilman at the 2002 New Zealand Petroleum Conference, held in Auckland in February. New Zealand recently rose higher than ever before in IHS Energy Group's annual ranking of 103 countries. It was 17th in overall exploration attractiveness, up seven places from the 2000 notch and up 20 since 1999. This ranking combines E&P activity, political and commercial stability and the fiscal regime. New Zealand amended the latter in the 1990s to make the country more appealing. In E&P rank alone, the country rose five places to 40th in the world. But, insist local and foreign explorers, not nearly enough drilling has taken place to get an accurate reading. The first well in the British Empire was drilled near New Plymouth in the Taranaki Basin in1865, yet not much drilling has taken place since then. Some of the majors and a few independents have come and gone over the years, discouraged by the remoteness, which causes service costs to be higher, and the limited market-the population is just under 4 million, about the same as in Houston. "If people know where New Zealand is, that's step one. Step two is people think it's just a boring green island 'out there somewhere,'" says David J. Bennett, president and CEO of Indo-Pacific Energy Ltd. in Wellington. "But New Zealand has a larger continental shelf than the U.S. Lower 48. People don't realize it. "I would say that for the size of the discovery you can make here and the amount of money you might make, you'd be hard-pressed to make a similar find in the States. But we are sort of off the beaten path, aren't we?" Only 19 wells were drilled in the country in 2001. Interest in Kiwi exploration appears to be gathering steam now, however, given two significant discoveries made in the last three years, one by Shell Oil Co. offshore at Pohokura and another by Houston-based Swift Energy Co. onshore the Taranaki Basin at Rimu-Kauri. Pohokura, with an estimated potential of 1 trillion cubic feet equivalent, is the largest find made here in 20 years. "It's been really gratifying that these significant discoveries were made, because in the 1990s there was a very low level of activity," says J.M. (Mac) Beggs, director of GeoSphere Exploration Ltd., a Wellington-area geological consulting firm that has advised several U.S. independents. "But I've always said 'Look, the problem is a lack of investment, not a lack of hydrocarbons.' I said that as far back as 1993." Several North American and Australian independents that hold onshore blocks with relevant seismic and other data are looking for partners now to help kick off new drilling. Swift and German-based Preussag Energie GmbH have recently opened offices in Wellington. (The latter has a one-third interest in Pohokura.) "In some respects, it's easier to do business in New Zealand than it is in our own state of Texas," says Don Morgan, chairman of Swift Energy New Zealand. "For one thing, the Crown is the only owner of the minerals and you bid a work program, so there are no upfront cash bonuses. The regulations on the books spell out fairly clearly how to deal with the surface owners. We've been fortunate to build good relationships with the district and regional councils, Maori groups and land owners such that we've never had to use the notified consent [public hearing] process, which can add up to 18 months, to get a well drilled." Swift has drilled 12 wells since it entered the country in 1995, including two sidetracks. More exploration data is now being made available, often for frontier areas. This past July, for example, TGS-Nopec teamed with the Institute of Geological and Nuclear Sciences Ltd. in Wellington to perform a non-exclusive, 6,500-kilometer deepwater seismic survey that is being interpreted now in preparation for the block offer coming up later this year. Numerous government and private geological consultants in New Zealand are either just now completing or kicking off major regional studies on the various onshore and offshore basins, and on the country's large continental shelf. Shell's Asia-Pacific exploration team in Houston is conducting a deepwater Taranaki regional study this year, and it has commissioned a study on the Haast Basin on the west coast of the South Island as well. Conoco drilled a dry hole north of deepwater Taranaki in the Northland Basin in 1999 and has one more well to drill by April 2003 to fulfill its work commitment. Some experts think the deepwater Taranaki could hold 5 billion barrels of oil. Wanted: Risk capital New Zealand has a lot of untapped promise. Although drilling and geophysical activity have increased since 1995, much more remains to be done-since 1900, only about 500 exploration wells have been drilled. In the country's most prolific basin, the onshore Taranaki in the North Island, only 114 wildcats have been drilled since 1955, although the rift area is twice the size of the Viking Graben in the North Sea. Second only to Taranaki in importance is the East Coast Basin along the east coast of the North Island. Covering 120,000 square kilometers on- and offshore, it has seen only 38 wells drilled. Onshore oil and gas discoveries made in both basins since 1998 are being appraised now and several independents are drilling-or looking for partners. One reason for the lack of activity is New Zealand's remoteness and relatively small economy, which even the native Kiwis admit is at once a blessing and a curse. It also presents an interesting geological conundrum. Oil and gas seeps and coal seams are found throughout its six major onshore basins, each full of multipay targets. Offshore basins may hold even more promise. But thrusting and faulting cause it to be highly complex. The capital, Wellington, sits smack on the active Wellington Fault. The northeast-southwest trending Taranaki Fault runs east of Swift's Rimu area to the South Island. Here the Pacific and Australian tectonic plates bump up against each other. Dormant volcanoes dot the landscape as well. "New Zealand has the geology and the fiscal terms. What it lacks is an appropriate amount of drilling risk capital," says Mike Patrick, executive officer of PEANZ, the Petroleum Exploration Association of New Zealand, based in Wellington. Oddly, there are few indigenous oil and gas companies in New Zealand. Most of the activity is conducted by Shell New Zealand and companies based in Australia, Calgary, Houston and Denver. The last big Kiwi E&P company fell in March 2001 when Shell New Zealand bought Fletcher Challenge Energy's Kiwi assets. Even New Zealand Oil & Gas, which holds several licenses, is based across the Tasman Sea in Sydney. On television and in the local business pages, one sees ads inviting investment in forestry and agriculture, the two biggest Kiwi industries-even ads for vineyards and olives and raising red deer commercially for venison. But there are none for oil and gas. "What that tells you is that exploration risk capital is extremely hard to come by. Even if you are an E&P company based here, you end up going abroad for capital," notes Glenn Thrasher, partner in GeoSphere. "Companies and investors here are risk averse. We have approached all the big gas users to ask them to help fund drilling and they've all said, 'No. You find it first and then we'll buy it.'" Supply crisis post-Maui? More than in many other places, time is of the essence in New Zealand. It cannot afford not to step up exploration for there is a looming shortage of natural gas. Shell's recent computer models indicate that New Zealand's largest supply, Maui Field, a huge gas accumulation offshore the Northern Island that has produced since 1979, is suffering severe water encroachment and is already 75% depleted. "The big issue facing the country-and it's up to us to fix it-is that Maui will start to run out in 2007," which is two or three years sooner than first estimated, "and we are desperately trying to replace it," says Patrick. New Zealand is likely to face much higher prices for gas as demand increases and production declines. Maui has an estimated 4 trillion cubic feet of gas but the only field that comes close to offsetting it, Shell's recently announced Pohokura, is about a quarter its size and won't come on line until 2005. "Security of supply in the electricity market is critically linked to gas, yet gas supply is constrained. That fact, if nothing else, should drive the government to encourage gas exploration-and that in turn probably means higher gas prices," says Malcolm Alexander, general manager of market services for M-Co. Ltd., an electric and gas market administrator. Maui supplies 80% of New Zealand's gas needs, with 40% going to utilities and 40% to Methanex's world-class methanol plant nearby. Meanwhile, New Zealand gas demand grew 5% in the year ended March 2001, with the amount of gas used for electric generation alone increasing 9.5% in that same period. (About half of the country's power comes from hydroelectric plants. When there is a dry winter as there was last year, the call on natural gas increases and Maui depletes even faster.) Maui's history has colored the entire country's gas market and price structure, but that may be changing. Essentially, large take-or-pay contracts with low gas prices between the operator of Maui and the end users served to keep a lid on gas prices and discouraged aggressive exploration. Currently operators receive an average US$1 at the wellhead in New Zealand. But now, the limits of the take-or-pay production are being reached and suddenly, there's growing gas demand as well. "We need a vibrant exploration sector," says Bruce Aitken, managing director of Methanex New Zealand. "We'd like to stay in New Zealand. But the next two years are crucial-if we are to stay, we need new discoveries." The first key steps will be taken by the Crown Minerals section of the Ministry of Economic Development, based in Wellington. The manager of the country's mineral assets, Crown Minerals by law must review by 2005 the fiscal and license terms, and the government is also studying possible deregulation of the gas industry-which would include raising gas prices. Crown Minerals has three bidding rounds in the works. On April 30 it will accept work program bids for 20 onshore and 6 offshore blocks in the Taranaki Basin, its largest such offering in a decade. In July, there will be an offshore block offer in the Canterbury Basin east of the South Island. Only four wells have been drilled there over the 20,000 square miles covering shelf and slope. Late Cretaceous coals and oil seeps are seen similar to what is found in the Taranaki to the north. And in September 2002, Crown Minerals will announce the deepwater Taranaki blocks to be offered the following summer. This will cover an area of the basin that was seismically surveyed for the first time only last July. New Zealand's fiscal terms are attractive, with the state taking only a 5% ad valorem royalty or a 20% net profits interest. There are no other severance taxes. At the February petroleum conference, however, a speaker from Shell publicly urged the government to improve the work terms. Companies that apply under the AFO (acceptable frontier offer) mechanism, where application can be made any time outside a bidding round, must promise to drill one well by the end of either the second or third year of a five-year work program. Many think that isn't enough time to assess the geology before making the drill-or-drop decision, especially for frontier areas. Under bidding rounds the terms are more flexible, with drill-by dates determined by the successful bidder, within the first five-year term. "I don't think the fiscal terms are going to drive the debate. It's the work program," concedes Darryl Thorburn, group manager of Crown Minerals. "We try to work through the issues and make sure a company has time enough to do two seismic rounds or otherwise use all the modern technology it wants to apply," he says. "Even five years may be too short for a deepwater program. We will look at the Gulf of Mexico and West Africa and the way the system works there. "We are attracting more North American independents but we need to attract the majors. We want more wells drilled offshore." Shell's Pohokura Field One bright spot for New Zealand is Pohokura, discovered by Fletcher Challenge Energy in February 2000. This low-relief anticline contains an estimated 1 trillion cubic feet of gas and condensate, offshore just north of the Taranaki Peninsula of the North Island. The discovery well flow-tested 17 million cubic feet per day; the appraisal tested twice that, both from Eocene Mangahewa. The gas column in the #1 was 426 feet; in the #2 it was 377. Partners now include Preussag Energie with 33.3% and Shell, 48%, after having bought FCE. Field development will be performed by Shell Todd Oil Services, a 50-50 joint venture formed in 1955 with Todd Petroleum, the largest family owned company based in New Zealand. The latter owns 18.7% of the field. Located in shallow water just 3 miles from shore, Pohokura is conveniently close to the Methanex methanol plant. This year Shell plans to drill one appraisal well offshore and another directionally from land. Front-end design has begun as the major contemplates installing two or three production platforms, possibly unmanned. The gas is rich with liquids-annual production may exceed 300,000 tons of butane and propane, so Shell is considering building a cryogenic turboexpander plant onshore. Gas sales should commence in 2005. "New Zealand is a small but valued part of our worldwide portfolio," says Shell's Peter Jeans, former regional business advisor for New Zealand at The Hague. "We wouldn't have undertaken to buy Fletcher Challenge Energy had we not perceived New Zealand to be a core asset within the portfolio." As part of its FCE acquisition, however, Kiwi authorities required Shell to divest certain New Zealand holdings. It has sold the so-called TAWN assets (four producing onshore oil and gas fields onshore Taranaki) to Swift Energy for $54.5 million. But Shell still dominates as operator of the Maui Field offshore. It also has the 1.5 Tcf Kapuni gas field and some smaller fields onshore, and retains several exploration licenses. At press time, it agreed to sell the Kaimiro oil and gas field and a 50% interest in Ngatoro oil and gas field to Greymouth Petroleum Ltd., a local E&P startup staffed by former Fletcher Challenge employees. Further divestitures are coming this year. Swift Energy No independent has made a bigger splash in New Zealand than Houston's Swift Energy Co. "We've put our stake in the ground and we're putting our money where our mouth is," said president and CEO Terry Swift at the 2002 New Zealand Petroleum Conference. "We have drilled from 3,600 feet to 13,500 feet, through nine zones in all. One comes to the conclusion there is world-class oil in place here." By yearend, about 25% of the company's production will come from New Zealand, but the potential could be much larger. Swift executives say that one of the company's blocks, with about 50,000 acres, holds potential recoverable reserves of more than 250 million barrels of oil equivalent, which would represent more than a doubling of Swift's size if drilling succeeds. Including a recent acquisition, Swift has approximately 167 billion cubic feet equivalent of proved reserves in New Zealand. Its drilling has identified nine distinct hydrocarbon-bearing formations in its 95%-owned Rimu-Kauri area on the southern edge of the Taranaki Peninsula. Swift first learned of the possibilities in New Zealand while viewing booths at the American Association of Petroleum Geologists International Pavilion in 1994. Swift then entered New Zealand in 1995 as part of its effort to add an international component to its long-term strategy, which also included forays in Russia and Venezuela in the early1990s. Today the company holds interests in three exploration permits and five mining (production and development) licenses, all on the North Island. Fast forward to 1999, when Swift announced its Rimu A1 oil and gas discovery in the Taranaki Basin near the town of Hawera. It tested at rates of up to 1,525 barrels of oil and 4.8 million cubic feet per day from the Oligocene Upper Tariki Sand. The Rimu B1 tested 505 barrels and 2.8 million a day, and the Rimu B2 tested 1,384 barrels and 9.4 million cubic feet a day, both from Upper Rimu Limestone. To date Swift has drilled 12 wells. It has found hydrocarbons in every one and commercial pay in almost all of them, in multiple limestones and sandstones. At press time the Rimu production station was being commissioned so that first production would start by the end of this quarter. Swift recently got the development go-ahead when Crown Minerals awarded a 30-year petroleum mining permit, PMP 38151, for Rimu. Plans call for nine additional wells, including one gas injector. Targets will be the Upper and Lower Tariki sands and the fractured Upper Rimu limestone. Estimated peak production will be 5,700 barrels of oil and liquids and 22 million cubic feet of gas per day. Swift has built two drilling pads at Rimu and intends to add three more, with several wells to be drilled off each one, for additional spending that may top $80 million "Swift's story is very positive," says Thrasher of GeoSphere. "They had a four or five-year lead time to establish their acreage position and do the science. Rimu did kind of come out of nowhere, whereas Pohokura had been on the books. The market largely rejected Rimu [during the industry downturn in 1999], yet Swift had the resolve to drill it anyway, and 90%," Thrasher says. (Today Swift has 95%.) Swift also found four potential pay zones at the Kauri A1 about 5 miles south of Rimu. The Upper Tariki Sand flowed about 500 barrels of oil equivalent a day. Seismic and other data indicate that Rimu and Kauri may be in direct communication to form one large multizone field. Two other potentially significant sands were penetrated in the Kauri A1, says Kush Patel, Swift's Houston-based vice president, geophysics. One, the Kauri Sand, which had better mud log shows than any of the Rimu wells, encountered 577 net feet of hydrocarbon-bearing sands with good porosity, beginning at a depth of 9,473 feet. This Kauri sand has not yet been fully evaluated. The second sand, the shallower Manutahi found at 3,746 feet, was approximately 40 feet thick with porosities of up to 27% and permeabilities of up to 800 millidarcies. Additionally, Swift has drilled the shallow Kauri A2, A3 and B1 wells to further delineate its discovery. There are two drilling pads at Kauri and plans to add more. And, it has more onshore prospects at Tawa and Matai, located between Shell's large Kapuni Field and Swift's discoveries. At year-end 2000, Swift had booked about 20 million barrels of oil equivalent of proved reserves at Rimu alone. Ambitious development drilling budgeted for this year could lead to higher production, which will be enabled by the Rimu production station coming online this spring. By yearend 2002, Swift will have a much better idea of what it has found. "This is still true exploration," notes executive vice president Bruce Vincent. "Only two wells had been drilled on the Rimu block before we got it. The synthetic-based muds we used here have made a big difference. At Kauri the shallow Manutahi sands were unconsolidated so we did some gravel packs. That's nothing new to this business, but it is relatively new to New Zealand. Activity on the block is so new that a lot of things just haven't been tried yet." Make no mistake, Swift is committed to New Zealand and has solidified its Kiwi presence through acquisitions. Last year it bought all of Calgary-based Antrim Oil & Gas Ltd.'s New Zealand interests, including its minority stake in Rimu-Kauri and in PEP38716, the Huinga permit just to the north. It paid less than $1 million and 220,000 shares of SFY common stock. In late January it acquired from Shell a 96.76% working interest in the TAWN assets 17 miles north of Rimu. This comprises the Tariki, Ahuroa, Waihapa and Ngaere fields, the Waihapa production station and associated pipelines. Net production in first-quarter 2002 from the 17 wells involved was expected to be about 900 barrels of oil, 27 million cubic feet of gas and 500 barrels of gas liquids per day. Net proved reserves as of November 2001 were 65 billion cubic feet equivalent, about 70% gas. The underutilized Waihapa plant will complement Swift's plan for development drilling at TAWN and elsewhere in the Taranaki Basin. "TAWN has the capacity to produce up to 60 million cubic feet equivalent a day but because of market conditions, it is the swing producer for gas in New Zealand," explains Vincent. Swift sells its gas from TAWN to Contact Energy and has contracted with Genesis Power for the Rimu gas output. Both are large Kiwi power producers. Shell has a year to elect whether to acquire up to 50% of the deep rights at TAWN And at press time, it was about to decide whether to take a 25% interest in Swift's PEP 38719 block that includes Rimu-Kauri. Indo-Pacific Energy Ltd. A small public company incorporated in Yukon, Canada, but traded in the U.S. (OTC: INDOF), Indo-Pacific Energy explores in Australia, Papua New Guinea and New Zealand. "We're the largest onshore acreage holder here, and whether that is a virtue or a vice depends," says president and chief executive David J. Bennett. The company plans five Kiwi wells this year. In the North Island's East Coast Basin, Indo-Pacific has interests in four exploration permits totaling more than 2 million acres. In the Taranaki, it holds interests in another four exploration permits and one mining (production) permit, all adjacent to producing fields. It has completed three seismic surveys and drilled two wells in the virtually unexplored Canterbury Basin on the South Island. But it is the Goldie well that is causing excitement and giving the company a new lease on life. Discovered in March 2001, it flowed about 700 barrels of oil per day from a new pool, Miocene Mt. Messenger (turbidite sands). It is within an existing production license, PMP 38148 near Ngatoro Field. Average porosity was 23%. Today the well is flowing about 400 barrels a day and Indo-Pacific is considering water injection, as well as a second oil well. The well caused quite a stir because Indo-Pacific drilled it 100% when it only held 5% of the prospect-but it made its money back in three months. Shell subsequently backed in to the project by paying the sole risk penalty. "It's an amazing story," says Bennett. "We had 5% of the license and the other partners, Shell and New Zealand Oil & Gas, disagreed with the idea of going forward. NZOG is the original operator and they had mapped it, but we all had access to the same data. Exploration is such an inexact science." In the 1980s Bennett was exploration manager for New Zealand Oil & Gas, leading the team that discovered the Kupe South and Ngataro fields in the Taranaki Basin. "We maintained this would be an oil pool, and it was. We stated our reasons for believing in it, and we're glad to see those were correct. Goldie may not be too big, but it is intellectually satisfying. It's going to make 1- or 2 million barrels." Later this year the company will drill an offset to Goldie and also particpate in Bligh Oil's Huinga 1A and Tabla-1 onshore Taranaki. Swift is also a partner in Huinga. That will be followed by a wildcat in PEP 38330 onshore the East Cape. Meanwhile, its Kahili-1 on PEP 38736 was tested 2 miles from Tariki Field. It found waxy crude, but the well was too close to water-saturated reservoir and too low in the oil trap to be commercial. "At Kahili we were going for a play in Tikorangi limestone and Tariki sands. The Tariki 1-A well, 2.5 miles south, is doing 40 million cubic feet a day-that kind of well brings tears to your eyes." The company will try a deviated well to the east and updip, the Kahili 1-A, to test the formation at a shallower depth. The steeply dipping Tariki sands are difficult to map accurately without well control-the one thing New Zealand needs more of. That, and a robust gas market, which seems to be assured as Maui declines. "The New Zealand gas market has improved," says Bennett. "Eighteen months ago, you could not sell gas for love nor money. Now you can sell all you can find. New Zealand uses 230 Bcf per annum and has 2.8 million people on the North Island-our gas consumption is the highest per capita in the world." Denver independents Westech Energy Corp., Thomasson International Ventures Inc. and Anschutz Corp., all Denver-based independents, hold exploration permits in New Zealand. Westech is focusing on the Taranaki and East Coast basins of the North Island. The company has three offshore and one onshore blocks in the East Coast Basin, where it has two modest gas discoveries, and two exploration permits in the Taranaki onshore. It has acquired new 2-D and/or 3-D on all of these since 1998. At press time, it was gathering final consents for development of its Tuhara and Kauhauroa gas fields onshore the East Coast Basin, with drilling to be done in the first half of this year. Potential Miocene reserves exceed 350 billion cubic feet of dry gas. Following those two wells it hopes to drill on the Surrey project, PEP 38734 near the Ngatoro Field in Taranaki, west of Swift's TAWN assets. The target is the Miocene Mt. Messenger formation at about 6,000 feet. Westech also has concluded an agreement with Orion Exploration, a New Zealand independent, subject to Crown Minerals approval, where it assumed Orion's 50% interest in three East Coast permits, reserving an overriding interest to Orion. And it is relinquishing its interest in a smaller license, PEP 38335 on the East Coast. All of this portfolio managing is meant to reduce Westech's risk profile. "Ultimately, we wish to be joined by a 50% partner for all our New Zealand holdings," says Edward J. Davies, president. "We are optimistic because there is an expectation of a growing gas market on the East Coast. Offshore we see some really large structures we'd like to see drilled." Ed Berg, a consultant with Thomasson in Denver, remains highly enthused about New Zealand, citing its stability, favorable economic terms and geology. In 1998 the firm, which is a network of independent prospect generators, took a partner in GeoSphere, the Wellington-based geoscience and project consultant. Each year at its annual convention, the AAPG hosts an international pavilion where countries exhibit their data and deals. "I was wandering around the first one in 1994 and a few of the countries had good databases available. Ultimately it was being able to partner with GeoSphere that pulled New Zealand to the top of our list-they are extremely knowledgeable explorationists. Plus, the terms are good. The geology is just so prospective." The partners obtained PEP 38213 (the Waiau prospect), covering 741,000 acres in the Great South Basin on the South Island. Keeping an override, they sold 100% to EEX Corp. of Houston, which subsequently relinquished this block without drilling in January 2002. On the same day, Thomasson and GeoSphere re-applied for the permit, which has two drillable oil prospects in Eocene Beaumont. At press time they were awaiting the award. "We are currently seeking a partner to drill with us. Total depth will be about 7,500 feet. We estimate reserves in the range of 50- to 300 million barrels. It would be economic at the P- 90 estimate, which is 2.7 million barrels," says Berg. "There is a potential market in a bauxite smelter 40 miles away that consumes 15% of New Zealand's electric power. It could be an ideal spot for a cogeneration plant. "We have proposed to either drill right away or gather more seismic. We would need more seismic to develop the other leads in the area. Amoco held the block originally and acquired quite a bit of 2-D seismic data, which is available, and further seismic by EEX confirmed our mapping of the area. We see a large fold with four-way closure. The reservoir is Eocene channel sands similar to reservoirs seen in the Taranaki Basin to the north." Large traps and hydrocarbon expulsion are indicated. Last fall Shell took an option to partner with Thomasson and shoot new 2-D seismic data in the Haast Basin. Terms of the permit, PEP 38511, required them to drill a well by 2003. However, at press time, Shell withdrew from the project. The distance from the northern tip to the southern tip of New Zealand's offshore territory is roughly equal to the distance between Edmonton and New Orleans, and broadly, it is unexplored, says Mac Beggs. "When you looked at the deepwater areas off West Africa or the deepwater Gulf of Mexico 10 years ago, those were purely hypothetical, yet look at them today! So that's how I see New Zealand-but it's going to take a lot of activity that hasn't happened yet."