NEW ZEALAND REFORMS TO SPARK BIG RESURGENCE IN EXPLORATION

New Zealand has set the stage for a resurgence in oil and gas exploration.

Recent developments point especially to a significant natural gas market opportunity opening soon in the twin island nation.

On the 25th anniversary of its key source of hydrocarbon production, offshore supergiant Maui gas/condensate field, New Zealand faces some critical choices in its energy future.

Maui, which supplies about 32% of New Zealand's primary energy demand, is expected to enter into decline after the turn of the century. Discovered in 1969, Maui reserves then were estimated at 5 tcf of gas and 130 million bbl of condensate. Lack of market for the gas at the time kept Maui development on the shelf.

The field accommodates three fourths of New Zealand's natural gas demand. Its production not only provides most of the 37 bcf/year of natural gas consumed in the residential sector, it also feeds a world class petrochemicals/synthetic fuels industry nearby on North Island as well as two electrical power plants.

POLICY TURNABOUT

The New Zealand government has undergone a dramatic turnabout in its approach to energy policy.

When oil import dependence became a concern in the early 1970s, the New Zealand government intervened to make Maui the cornerstone of efforts to minimize dependence on foreign oil by converting Maui gas to gasoline and creating a new petroleum product export industry.

That has worked well enough to help the country almost double total energy self sufficiency to 81% during 1975 90 and jump liquid fuels self sufficiency from 4% in 1975 to 51% in 1990. At the same time, Maui gas feedstock underpins significant foreign exchange earnings from exports of methanol and ammonia/urea derived from it.

The government maintained a heavy presence in New Zealand's energy scene during the 1970s and 1980s, keeping an equity stake in Maui and related industries through state owned Petrocorp. The government's removal of some tax incentives for drilling came about the time oil prices nosedived in the mid 1980s.

With Maui decline looming and a dearth of exploration activity, the New Zealand government recently implemented steps designed to spark interest in oil and gas drilling by foreign companies.

In addition to fiscal reforms, the government has taken aggressive steps toward privatization, creating an overall better climate for investment in the country's energy sector.

The upshot is a renewal of interest in an underexplored theater and the likelihood of stepped up activity in the years to come.

Much of the information in this article came from papers presented at a petroleum conference in Rotorua, N.Z., earlier this year and sponsored by the New Zealand Ministry of Commerce Crown Minerals Operations Group's Energy and Resources Division (ERD) and the Petroleum Exploration Association of New Zealand (Peanz).

Other background information was provided by the Australian Institute of Petroleum's Petroleum Gazette and Fletcher Challenge Petroleum Ltd.'s annual review.

ENERGY SUPPLY CONCERNS

Shell Petroleum Mining Co. of New Zealand Ltd. predicts New Zealand's domestic hydrocarbon production, which now accounts for 85% of its gas and transportation fuels requirements, will account for only a 50% share by 2000.

That forecast hinges on expectations for Maui.

New Zealand's synthetic fuels, methanol, ammonia/urea, electrical power industry essentially were developed to take advantage of low cost, abundant Maui gas. Accordingly, not replacing Maui production could see some of those projects phase out or undertake costly switches to more polluting fuels.

"The depletion of Maui around 2010 is expected to reduce our liquid self-sufficiency and reduce the availability of gas for electricity generation and petrochemicals," said ERD head Michael Lear.

"The ministry's forecasts conclude this will result in price rises for gas and electricity and increased use of coal, geothermal, hydro, wind, and other renewables for generation."

Overall energy demand is forecast to jump to 528 bcf of gas equivalent (bcfge) in 2020 from 359 bcfge in 1990.

Lear noted that New Zealand gas demand has rocketed from about 10.45 bcf in 1975 to about 170 bcf in 1993. Of Maui production, 36% goes to Electricity Corp. of New Zealand (ECNZ), 32% to the Motonui gas to gasoline plant, 19% to Natural Gas Corp. (NGC), 10% to the Petralgas methanol plant, and 3% to the Petrochem ammonia/urea plant.

Shell sees the outlook for continued strong oil and gas demand as promising. Shell's Chris Scanlon noted that the petrochemical industry uses a little less than 50% of all New Zealand gas supplies, with those contracts for Maui gas expected to end about 2003-05. He contends there is no reason to believe such plants could not continue to take gas beyond those dates if enough uncommitted reserves are available.

Shell estimates residential demand for natural gas the so called reticulated market will grow to about 62 bcf/year from about 38 bcf/year during the next 20 years.

And if electrical power demand continues to grow at a conservatively estimated rate of 3%/year, it will require the equivalent of adding a major power plant every 18 months after 1999.

The Ministry of Commerce noted that the back to back take or pay supply agreements for Maui gas all will expire during 2003 09. The Motonui contract expires in 2003 and the ammonia/urea and methanol plants' contract in 2005. The ECNZ and NGC contracts extend to 2009.

Lear fears gas price increases are likely to make the synthetic fuels and methanol plants uneconomic about 2009.

Because of Maui's impending decline, the ministry's current forecast calls for total natural gas demand to peak in 2000 at 194 bcf and fall to about 65 bcf in 2020. Maui depletion in turn will undermine the country's current high level of energy self sufficiency, expected to peak in 1995 at 83% overall and 56% for liquid fuels. That will drop to 67% and 27%, respectively, in 2020, the ministry predicts.

Accordingly, without other oil and gas fields to take up the slack, New Zealand's growing demand for energy will increasingly be met by imports.

As Lear noted, "The depletion of Maui field highlights the importance of developing an attractive petroleum royalty regime to encourage further exploration of New Zealand's petroleum resources."

MAUI UPDATE

The cornerstone of New Zealand's energy sector is now in private hands.

Fletcher Challenge, Auckland, took a commanding role in that sector in 1988, when it acquired Petrocorp from the government and public shareholders for about $1 billion. Since then it has invested another $1.4 billion in oil and gas exploration and development in New Zealand.

Fletcher Challenge currently produces 62% of the country's gas and 71% of its crude oil and condensate. Combining synthetic gasoline output with crude and condensate, that accounts for 34% of New Zealand's overall demand for liquid fuels.

Maui alone provides feedstock that yields 45% of New Zealand's transportation fuels. Remaining reserves at yearend 1993, according to ERD estimates, were 2.297 tcf. That's 72% of the nation's total current proved reserves of gas.

Maui condensate and crude oil reserves account for 48% of the nation's proved total liquid hydrocarbon reserves.

Fletcher Challenge owns 68.75% of Maui and notes that the giant field and its environs will continue to play an important role in New Zealand's energy sector even after the main reservoir has begun to decline.

Remaining Maui interests are held by Shell Petroleum Mining Ltd. 18.75% and Todd Petroleum Mining Ltd. 12.5%. Maui platforms, onshore facilities, and tank farms are operated by Shell Todd Oil Services as agent for the joint venture.

Hugh Fletcher, Fletcher Challenge chief executive officer, cited an exploratory deepening of a gas development well from Maui B platform in 1993 that found a new oil leg the Paleocene Farewell Kapuni F sand that contains about 34 million bbl of crude oil, about half of which is recoverable. The well flowed oil on test at a stabilized rate of 3,300 b/d.

Last year, Maui operator Shell Todd Oil Services Ltd. disclosed plans for one and possibly two horizontal wells to tap the Kapuni F reservoir with the potential to produce about 10,000 b/d. Maui mainly produces from Eocene Kaimiro.

A 10th well at Maui B was programmed to test and evaluate additional oil found in some of the gas sands that earlier had not been considered prospective for oil.

Installation of Maui B was completed in 1993 at a cost of about $1 billion (N.Z.). Maui B production started Apr. 15, 1993. The second platform, an unmanned satellite to Maui A, taps the second major structure of the field to maintain contract volumes of gas supply as reserves from the first major structure are depleted.

Maui production currently averages about 400 435 MMcfd of gas, not 265 MMcfd as reported incorrectly (OGJ, July 11, p. 13).

Fletcher said Maui partners may drill more wells from Maui B to develop the new oil leg. Although no development scheme is in hand, the Maui group probably will opt to use a floating production/storage facility similar to those used for Australia's Northwest Shelf and Timor Sea marginal developments. In addition, Fletcher noted there remains a number of exploration leads on the Maui license and surrounding license blocks that, "given reasonable gas price regimes, we believe have the potential to be explored in the near future."

OTHER FIELDS

A string of other oil and gas fields dots the southwest peninsula of North Island in the Taranaki basin, the only one of New Zealand's 10 sedimentary basins that has produced commercial hydrocarbons.

P.R. King, with the Institute of Geological and Nuclear Sciences Ltd. (IGNS), estimated total Taranaki proved and probable reserves at 254.7 million bbl of crude oil, 210.3 million bbl of condensate, and 6.371 tcf of gas.

Predating Maui is Kapuni gas/condensate field, whose development during the 1960s spurred creation of the current gas infrastructure, with a gas treatment plant at Kapuni and pipelines to Wellington and Auckland. Kapuni's initial reserves estimate was 1.03 tcf of gas and 55 million bbl of condensate.

Exploration lagged after Kapuni and Maui were discovered until Petrocorp found McKee oil and gas field about 22 km east of New Plymouth.

Fletcher Challenge holds 100% of McKee, which produces about 7,000 b/d of oil and 15 MMcfd of gas. Its initial reserves were estimated at 38 million bbl of crude oil and 106 bcf of gas. Production peaked at 11,000 b/d in 1989. Beginning in 1993, Fletcher implemented a waterflood in the field.

Based on new seismic data, Fletcher Challenge has scheduled six infill wells for 1994. Other work on tap will focus on shallower and deeper prospects in the McKee license area. McKee produces from the Eocene McKee.

Petrocorp also discovered 29 bcf Kaimiro gas/condensate/oil field in 1982 and 53 bcf Tariki and 24 bcf Ahuroa gas/condensate fields in 1987.

Kaimiro encompasses two finds, 1 Kaimiro, which produces 1 MMcfd of gas from Kapuni, and 2 Kaimiro, which taps shallower Miocene Mt. Messenger and has produced 200,000 bbl of oil. The 5 Kaimiro flowed oil from two zones at rates of 300 b/d and 400 b/d, respectively, and has been tied back to Kaimiro production station. The 4 Kaimiro at last report was being completed prior to testing. Four more wells are programmed for Kaimiro during 1993 94.

Fletcher Challenge predicts a likely production peak of 2,000 b/d in 2 years before the field goes into a gradual decline.

Petrocorp tapped 1 million bbl of shallow oil and 1 bcf of gas at Ngatoro, near Kaimiro, in 1991. Kaimiro and Ngatoro each produce about 600 b/d of condensate from Miocene pay.

Tariki and Ahuroa have not been developed. Their geology is characterized by very, complex folding and faulting.

Gas from the two fields is under contract to ECNZ beginning in 1996. Pipelaying and infrastructure work is set to get under way this year.

More potential is thought to exist in Tariki sandstone, sandwiched between the Tikorangi and Kapuni formations, as well as in shallow Miocene. Plans call for more seismic surveys in the two fields this year prior to drilling of wells targeting Mt. Messenger at 1,500 m and Tikorangi at 2,500 m.

WAIHAPA-NGAERE

A 1988 discovery at Waihapa tapped mainly oil in Miocene Tikorangi fractured limestone for Petrocorp just before its sale to Fletcher Challenge.

Waihapa, southeast of Stratford, contains an estimated 20 million bbl of oil and 19 bcf of gas. Australian companies Carpentaria Exploration (MIM Holdings) and Bligh Oil & Minerals also hold interests in the discovery.

It was the first time the fractured limestone had been successfully tested in the Taranaki basin. The 1 Waihapa discovery well flowed 2,000 b/d.

The field was extended with an exploratory well at Ngaere, which proved another 7 million bbl of oil and 7 bcf of gas. The 1 Ngaere, which has flowed oil at a rate of as much as 8,100 b/d, currently produces 7,500 b/d.

At present, Waihapa Ngaere produces 15,000 b/d from six wells. Plans call for expanding production facilities to boost flow to 20,000 b/d this year.

Fletcher Challenge's Petrocorp Exploration Ltd. unit earlier this year brought on stream the 2 Ngaere appraisal/development well. Drilled to 3,224 m, it flowed 2,600 b/d of oil and was tied back to Waihapa production station via a 2 km flow line. Tentative plans call for another appraisal to be drilled at Ngaere.

The license area north of 2 Ngaere is lightly explored, with limited seismic and no wells. A 3D survey completed last year set the stage for a wildcat there. Fletcher Challenge sees shallow Miocene prospects at Waihapa-Ngaere, with a wildcat planned to probe that horizon this year.

KUPE SOUTH

Also awaiting development is Kupe South offshore field, the most significant New Zealand find since Maui.

Operated by Australia's Western Mining Corp. Ltd. (WMC), Kupe South is a 1986 discovery that holds combined proved and probable reserves estimated at 128 million bbl of crude and 757 bcf of gas. Partly appraised, its recoverable reserves are pegged at 31 million bbl and 264 300 bcf.

WMC's Kupe South license PML 38146, in which it owns a 40% interest, also holds Toru gas/condensate field, with proved and probable reserves listed at 106 bcf and 6.7 million bbl. Other license interests are held by Norcen International Ltd. 20%, New Zealand Oil & Gas Corp. 16.5%, New Zealand Ministry of Commerce 11%, Shoseki Oil Development Co. of Taranaki Ltd. 10%, and Delta Petroleum 2.5%.

Kupe South lies about 30 km off the Taranaki coast in 35 m of water. The reservoir is at 3,100 m in the Farewell formation of the Kapuni group.

Five wells have been drilled in Kupe South. Three of the wells have been drilled in the same fault block, although there is an argument that one of the wells, 2 Kupe South, is not connected to Kupe South 1 or 3, WMC Chairman Ray Hutchinson said.

Additional fault blocks are near the main block, but before they can be drilled at a cost of $20 million (N.Z.), Kupe South development must be under way or a suitably attractive sales contract in hand, Hutchinson said.

Hutchinson estimates Kupe South development costs at $150 250 million (N.Z.), depending on how production is delivered to market. Maui and Kapuni are currently meeting New Zealand's gas needs, so there is insufficient market demand. At the same time, Kupe South's gas reserves are inadequate to make up the shortfall when Maui goes into decline.

Hutchinson said prices offered by potential buyers of Kupe gas have been too low to justify development. The license expires at the end of January 1996, with a development proposal deadline of Aug. 1, 1995. WMC plans to seek renewal of its license should it not make that deadline.

Hutchinson said he believes Kupe South gas will be sold at a price that will justify development and that such a commitment will be made this year.

Because future discoveries are more likely to be of the scale of Kupe South rather than that of Maui, Hutchinson thinks that what happens to Kupe South "may well set the pattern, or at least the expectation for future investors in natural gas exploration in New Zealand."

TARANAKI PROSPECTS

Most of New Zealand is virtual rank wildcat country. Even the one source of commercial hydrocarbons, the Taranaki basin, is a relatively underexplored petroleum province with respect to the number of wells drilled.

IGNS' King sees potential for new geologic frontiers and play concepts in the Taranaki basin. Most fields there occur within a Miocene fold thrust belt. Ngatoro and Kaimiro occur in an adjacent foredeep basin that has been modified by normal faulting. Maui occurs in a hybrid tectonic setting, encompassing fold thrust belt and foredeep basin styles.

King describes the Taranaki basin as a petroleum province with a concentrated distribution of oil and gas pools. The bulk of reserves is contained in a very few large fields, with the remainder in many small fields.

Most of the smallest fields are onshore, which King thinks may reflect a bias against testing marginal hydrocarbon indications offshore rather than geological effects.

King estimates a conservative expected median field size of 15 million bbl of oil equivalent for future discoveries in the Taranaki basin.

By yearend 1992, 212 oil and gas wells had been drilled in the Taranaki basin. Of those, 158 were drilled after 1959, broken out as 85 wildcats and 73 appraisal and development wells. King figures the basin's exploratory success ratio at 4.5 wildcats/discovery, lower than the 3.8 wildcats/discovery average for the Asia Pacific region.

FRONTIER PROSPECTS

Outside Taranaki, New Zealand's hydrocarbon potential is concentrated in frontier basins.

The East Coast basin is a structurally and stratigraphically complex belt that covers 70,000 sq km and stretches 750 km along both islands' eastern coasts, from Marlborough in the south to Raukumara Peninsula in the north. Most exploration in the basin has concentrated on Cretaceous and Pliocene targets.

Consulting geologist Dave Francis sees the best indications for future discoveries in the East Coast basin-where seeps were recorded as early as 1865 in relatively shallow Tertiary, especially Miocene, targets.

Geologists T.L. Thompson, W.L. Leask, and B.T. May conclude that all the essential ingredients for petroleum accumulation exist in the South Wanganui basin, which covers 20,000 sq km on and off south central North Island, just east of the Taranaki basin. In the deepest part of the basin, where no wells have been drilled, there are indications of sandstone reservoirs, mudstone seals, large structures, and potential for mature organic source rocks. The deep basin merits a well test to basement on at least one of the structures, the authors contend in a paper given at the Rotorua conference. Only five wells in all have been drilled on the flanks of the basin.

INGS research scientists Rick Herzer and Mike Isaac conclude there is considerable potential west of the Northland Peninsula, where regional seismic surveys show a thick sequence of Cretaceous and Cenozoic sedimentary rocks. The Northland basin features facies and basin history very similar to those of the Taranaki basin, they said.

NEW EXPLORATION

The new regulatory regime and gas market opportunities are spurring renewed interest in New Zealand exploration and development, notably in frontier areas.

Amoco New Zealand Exploration Co. and partners plan to spud by yearend a wildcat in the offshore East Coast basin. It will be only the second well to be drilled in the huge basin.

Meantime, Conoco Inc. has been awarded a big exploration permit in the offshore Northland basin. Its initial geologic studies indicate the Northland basin has a similar but older stratigraphic development in relation to the Taranaki basin.

Fletcher Challenge is stepping up investment in E&P to lead what it calls a renaissance in Taranaki exploration.

It expects to hike its exploration budget for fiscal 1994 95 to $65 million (N.Z.) from $45 million in 1993 94. Plans call for participating in eight Taranaki basin wells this year. The focus in the Taranaki onshore campaign is on shallower oil and gas first produced commercially in its 2 Kaimiro discovery.

Fletcher plans four onshore wells to test shallow Miocene targets. The first, 1 Paritutu, has been completed. It was the first New Zealand exploratory well to be drilled in a modern urban environment, in the western suburbs of New Plymouth.

Two more wells are slated in Northeast Taranaki targeting shallow oil beyond McKee field, and a fourth is planned for the Northeast Waihapa area. The company also plans to drill two deeper oil exploratory wells in the fractured Tikorangi limestone at Waihapa Ngaere. Also on tap are two more deep wells targeting gas in Maui field and on the margins of Maui.

Fletcher further plans to move seismic exploration into relatively virgin areas in Southwest Taranaki.

And Fletcher is seeking partners for exploration in the offshore Taranaki area, setting up a study group to evaluate additional oil and gas prospects there and high grading them for wildcat locations.

The government is doing its part to make more acreage available. Earlier this year, it disclosed plans to release new onshore and offshore petroleum exploration licenses in the Taranaki basin in the third quarter. That is to be followed by similar releases in the East Coast basin. Permits are to be offered either through standard work program bids, cash bonus bids that are reserved for outstanding prospects, or frontier offering in areas where there is little interest or competition for a permit.

REGULATORY REFORMS

New Zealand's government has reversed direction on energy policy, from taking the lead on and investing heavily in energy projects to privatization and deregulation.

The basic fiscal regime based on a tax and royalty structure remains the same, but the government recently implemented new measures to sweeten fiscal incentives.

The government cut the ad valorem royalty to 5% from 12.5% and eliminated its 11% carried contributory interest in production. It also accelerated the depreciation period for development costs to 7 years from 10 years. The ad valorem royalty is to be charged against new sales revenue from a permit.

At the same time, however, the government introduced a 20% accounting profit royalty (APR), payable on a company's net accumulated accounting profit from development in any year. It will be assessed by a formula that considers costs of extracting, processing, and selling petroleum products and the price received.

The government will require payment of the higher of the ad valorem royalty of APR in any 1 year, applicable to all permits granted after the new rules take effect. The new regime is to be phased in gradually.

According to Petroleum Gazette, independent calculations based on the new guidelines suggest the marginal government take on production will be 36 46%, leaving producers with 54-64% of profits. That compares with a producer profit share of 55% under the old regime.

And the government has aggressively divested its interests in state petroleum concerns in recent years.

It privatized 30% of Petrocorp in the mid 1980s and sold the remaining 70% to Fletcher Challenge in 1988. In 1990, the government sold its interest in the Motonui synfuels plant to Fletcher, which in turn spun off its methanol and synfuels business and NGC. Canada's Methanex Corp's Methanex New Zealand now owns and operates both of New Zealand's methanol plants and the synfuels plant. NGC is a separate, publicly listed company.

SHELL'S VIEW

Shell's Scanlon, also chairman of Peanz, praised the government reforms but voiced concerns for other industry hurdles.

"After considerable lobbying by Peanz, we now have a tax regime nearly back to what it used to be," he said. "New Zealand has a regime that is comparable to that of our neighboring countries who are competing for the international exploration dollar."

Scanlon commended the government for its intent to withdraw directly from petroleum exploration and development but expressed concern over the time the government is taking to phase in the new royalties regime. The government in July closed a comment period for a draft minerals program implementing the new licensing and royalty legislation.

"This is the single most important issue facing investment decisions at present, and a quick resolution is required to stimulate exploration activity. We are also concerned by the fact that no new license permits will be offered until the decision process is complete."

The government also took steps in 1992 to partly deregulate and roll back price controls for the natural gas industry. Scanlon cited a recent study that found future gas prices in the deregulated post Maui era could net producers prices of about $1.90/Mcf, compared with the current 76.7cts/Mcf for Maui gas and less than half that level for Kapuni gas.

"It would be fair to say that this country has moved away from a 'Fortress New Zealand' regulatory system to an environment where competition and market forces are encouraged," he said.

"This has resulted in considerable changes to the legislative and business environment, and in the course of its enactment, the petroleum industry has taken a very positive approach."