Fletcher Challenge Energy - Financial Results
YEAR ENDED 30 JUNE 2000
Total Shareholder Return of 37 per cent for the year
Net Earnings of $261 million (74 cents per share) – up 375 per cent
Cash Flow from Operations of $640 million ($1.93 per share) – up 25 per cent
Discovery of Pohokura – largest exploration success in Fletcher Challenge Energy’s history
Production of 49 mmboe
Record gas production in all geographies
ECNZ gas sales contract validity upheld
Decision by Fletcher Challenge Board to dismantle the targeted share structure
Agreement, subject to Petroz NL shareholder approval, to acquire a minimum 33.7 per cent interest in Petroz NL – enhancing Fletcher Challenge Energy’s regional E & P strategy
Initial Public Offering of Capstone Turbine Corporation investment (in which we hold 11 per cent)
Initiation of the “Creating our Company” culture change project
RESULTS BY GEOGRAPHIC REGION
(year ended) New Zealand North America
Brunei South America
Operating Revenue 640 390 73 461 1,564 1,192 1,035
EBIT (excluding Unusual Items) 255 47 14 (4) (18) 294 91 217
Unlevered Cash Flow from Operations 495 187 44 (1) (6) 719 575 613
Assets 1,329 1,206 397 7 1,245 4,184 3,160 3,421
Stock Exchange Listings: New Zealand (FEG), Australia (FLCES), New York (FEG)
CHIEF EXECUTIVE’S REVIEW
Twelve months ago the Board of Fletcher Challenge Limited approved and announced a bold and radically different strategy for Fletcher Challenge Energy.
In addition, the Fletcher Challenge Limited Board announced the separation of the Energy Division from Fletcher Challenge Limited.
We have a vision for the future of Fletcher Challenge Energy. We intend to build a strong, large company that has a clear focus on oil and gas exploration and production. The company will be committed to growth at the top line – reserves and production, and at the bottom line – cash flow and profitability. The company will seek to develop a full portfolio of exploration, development and production assets and will be primarily focused in Australasia and South-East Asia. This vision and strategy has been clearly and consistently communicated to stakeholders.
Implementation required us to undertake a number of clearly defined sequential steps:
– Communicating the new direction and
aligning the organisation for this change
– Re-focusing the business
– Building the required financial capacity
– Re-designing organisational structure and people processes
– Setting clear business performance goals
– Optimising growth from existing assets
– Growing the asset base
In the last year we have made good progress in transforming strategy into reality. We have sold non-core assets and released debt obligations within the past 18 months of just under $500 million. Our financial structure has been simplified, and most importantly, our debt to debt plus equity level lowered to less than 10 per cent. Total Shareholder Return, as measured by capital appreciation and dividends received, was an impressive 37 per cent for the financial year.
These are only the most obvious of the changes we have made. We have further built management bench strength, re-organised senior management and launched a far-reaching culture change programme, called “Creating Our Company”. Numerous internal processes have been re-designed, most significantly those around performance management, development of our exploration portfolio and capital allocation.
We are now beginning to reap the fruits of our labour. Financially we have had our best year since 1997 and our second best year ever. Overall production was up six per cent on the prior year. Oil and North American gas prices have been exceptionally strong. We have had our largest ever additions to the reserves since the acquisition of the BP share of Maui. We have also had some big one-off wins:
– The sale of our interest in
Natural Gas Corporation for $268 million (net of costs)
– The discovery of Pohokura, New Zealand’s largest gas and condensate find since Maui
– A favourable High Court ruling on the validity of our contract to supply gas to Electricity Corporation of New Zealand over 17 years
– The sale of our marketing rights for Capstone Turbine Corporation for consideration of $61 million
– A dramatic increase in the value of our equity in Capstone Turbine Corporation following that company’s successful Initial Public Offering on the NASDAQ on 29 June 2000
These events are neither random nor chance, but clear evidence of the planned transformation of the business.
The coming year will see even greater change. The Board of Fletcher Challenge Limited remains committed to dismantling the targeted share structure. Shareholder value will determine which of the possible exit mechanisms for Fletcher Challenge Energy is chosen. There are three possible outcomes for Fletcher Challenge Energy. The business could be listed as a separate company, merged with another industry player, or sold to a trade buyer. At this time it is not possible to determine which one of these will be chosen. Over the last six months, my management team and I have been working assiduously to ensure that we are able to present the Board of Fletcher Challenge Limited with the largest number of quality options.
In the event that Fletcher Challenge Energy becomes a stand-alone company, we intend to press ahead with the established strategy. We have also identified the Worsley Co-Generation plant and our equity in the Maui pipeline as non core assets which we will seek to divest in a planned manner. We now also consider our shareholding in Capstone Turbine Corporation as non core and are reviewing options to maximise the value of this investment for our shareholders.
In our core business, particular focus will be paid to our mature assets to ensure that they continue to provide superior returns in the latter part of their productive lives. We will address under-performing assets. We have identified particular assets where value added has not attained the levels we seek for our shareholders. Plans are being developed to substantially improve the performance of these areas.
We would also intend to grow the company. Our balance sheet is strong and we will use that strength to increase value for our shareholders. Our recent interest in Petroz NL is tangible proof of that commitment.
There is no standing still. Achievements are simply milestones on the path to destinations that are more demanding. Every successful business faces this reality. Whatever the ultimate separation outcome that is chosen, Fletcher Challenge Energy has a motivated and willing team of employees who are dedicated to delivering value to our shareholders.
Fletcher Challenge Separation Programme
On 3 April 2000, the first major step in the dismantling of the Group’s targeted share structure took place with the announcement of the agreement to sell Fletcher Challenge Paper to Norske Skogindustrier ASA. The Transaction was subsequently approved by shareholders and the sale successfully completed on 28 July 2000.
Good progress is being made on the separation proposals for the three remaining Divisions – Energy, Building and Forests. A full range of options for each Division is being explored, including listings as separate “stand-alone” companies or sale to third parties.
The Board remains committed to delivering the best value outcomes in the separation process, and will keep shareholders informed of progress.
CONSOLIDATED FINANCIAL OVERVIEW
Throughout fiscal 2000, a strong commodity price environment and near record production levels enabled Fletcher Challenge Energy to deliver Net Earnings for the year of $261 million (74 cents per share), a 375 per cent increase on the 1999 financial year. This result includes significant non-recurring (Unusual) items that contributed a net $99 million to Net Earnings, leaving Net Earnings before Unusual Items of $162 million for the year.
Cash Flow from Operations (net of funding costs) was $640 million, or $1.93 per share for the year, an increase of 25 per cent on the 1999 year.
Good progress is being made on the separation proposal for Fletcher Challenge Energy. A full range of options is being explored, including listing as a “stand alone” company or sale to a third party. Unless the separation process results in a third party sale recommendation, the Directors intend that Fletcher Challenge Energy will declare a final dividend of 10 cents per share (record date 29 September 2000). If the dividend is declared and paid it will bring the total dividend for the year to 18 cents per share, an increase of 29 per cent over the prior year. This dividend is consistent with Fletcher Challenge Energy’s policy of paying out 10 per cent of Cash Flow from Operations after distributions to Capital Notes holders.
Revenue and Operating Costs
Gross operating revenues for the year were $1,564 million, an increase of 31 per cent over the 1999 year and a record for Fletcher Challenge Energy. Revenue from the upstream production businesses totalled $1,103 million. Revenue from the downstream and trading businesses added a further $461 million.
Offsetting these revenue increases was an increase in operating costs (excluding Unusual Items) from $1,101 million to $1,270 million. The increased cost and volume of petrol, gas and other products purchased for on-sale through the trading businesses accounted for the majority of the operating cost increase (81 per cent or $137 million). The balance of the increase (19 per cent or $32 million) resulted from increased upstream costs – primarily due to the inclusion of the first full year of Brunei operations and increased royalty payments (linked to commodity prices), offset by lower levels of exploration expensed.
Earnings before Interest and Taxes for the year of $393 million include a number of one-off items. Most significant amongst these is an unusual gain of $113 million recorded on the sale of Fletcher Challenge Energy’s interest in Natural Gas Corporation. A further $61 million gain was recorded on the sale of the rights to market Capstone Turbine Corporation’s products in certain geographic regions. These rights were subsequently sold back to Capstone Turbine Corporation. Offsetting these gains was a charge of $54 million against Fletcher Challenge Energy’s earnings, as a consequence of separating the Employee Educational Fund into four separate trusts, which then ceased to be accounting subsidiaries. This charge was largely offset on the Statement of Financial Position (Balance Sheet) by an increase in the Energy Division’s Reported Capital of $51 million. Additionally, Fletcher Challenge Energy wrote down its investment in Commodity Capital Group (CCG) by $20 million during the period. CCG is a financial and commodity products trading company based in the United States in which Fletcher Challenge Energy has a fully diluted 23 per cent interest. As a start-up business, management believes that it is appropriate to provide against the investment.
A provision was made against earnings for taxation of $53 million, significantly higher than the $3 million provided for in the prior year. This increase is primarily a consequence of higher earnings.
Funding costs increased from $63 million to $79 million. This increase reflects a decrease in the level of term debt being more than offset by the inclusion of a full year’s interest portion of Gas Loan payments. A full schedule of the expected Gas Loan interest and principal payments is available on the Fletcher Challenge Energy website (www.fce.co.nz/finance).
Total Capital Expenditure for the year was $360 million, down 17 per cent on 1999. Amongst Fletcher Challenge Energy’s core exploration, development and production businesses, New Zealand invested $73 million, the Americas $188 million and Brunei $35 million. The completion of the Maharaja Lela project in Brunei and the farm-down of exploration costs in Blocks A and CD resulted in significantly lower capital expenditure in that region. Increased year-on-year capital expenditure in Canada was primarily attributable to a declining NZ-CAD dollar cross rate.
The ratio of Net Interest Bearing Debt to Book Capitalisation improved substantially from 33.3 per cent to 9.6 per cent as proceeds from asset sales and free cash flow from operations continued to be applied to debt reduction. This ratio was also improved significantly by the inclusion, in the Revaluation Reserve, of the 30 June 2000 market value of the investment in Capstone Turbine Corporation, in accordance with US GAAP. The ratio of Operating Cash Flow to Gross Interest strengthened from 6.1 times to 7.1 times.
To match its key currency exposure, Fletcher Challenge Energy maintains the book value of its assets and term debt in US dollar terms and translates these to New Zealand dollar values at balance date. A consequence is that fluctuations in the NZ-US dollar cross-rate translate into variations in the New Zealand dollar value of assets. During fiscal 2000 the NZ-US dollar cross-rate fell 13 per cent from 0.5286 to 0.4686. This cross-rate decrease resulted in a corresponding increase in Fletcher Challenge Energy’s reported New Zealand dollar assets and debt value.
By Product New Zealand
Oil and Condensate (mmbbls) 9.1 5.2 0.4 14.7 16.6 18.8
Gas (bcf) 129.2 53.7 14.9 197.8 169.0 151.1
LPG (tonnes) 124.0 124.0 119.0 108.9
Total (mmboe) 31.9 14.1 2.9 48.9 46.0 45.1
Note: 6 bcf of gas equals 1 mmboe and 100 thousand tonnes of LPG equals 1 mmboe
SEC PROVEN RESERVES New
Oil and Condensate 45 39 6 90 104 106
Gas * 124 102 29 255 251 259
LPG 8 8 9 10
Total (mmboe) 177 141 35 353 364 375
* Net of pre-paid gas
PRE-PAID GAS RESERVES
Maui Pre-paid Gas Balance
(Fletcher Challenge Energy Share)
Pre-paid gas (bcf) 177 183 181 170 175
Note: Pre-paid gas is gas that has not yet been produced but has been paid for by the New Zealand Government under the terms of the Maui Crown Contract. Pre-paid gas reserves are not included in the SEC Proven reserves.
As a result of substantial exploration success in the Pohokura field in New Zealand, Fletcher Challenge Energy achieved 70 per cent reserve replacement on a SEC proven basis. Total SEC proven reserves at 30 June 2000 were 353 million barrels of oil equivalent (mmboe).
Fletcher Challenge Energy’s vision is to create a strong, large, regional oil and gas company that provides consistent capital appreciation and high liquidity for its shareholders.
This vision requires the business to grow. Size in the business provides the strength of portfolio to manage the risks of the industry. It also provides the liquidity required to compete in today’s capital markets.
With many of Fletcher Challenge Energy’s existing oil and gas fields now mature, reserves and production replacement are priorities for the business. This top line growth will provide the platform for continued bottom line performance into the future. While a full exploration programme remains a fundamental element in Fletcher Challenge Energy’s strategy, growth through acquisition or merger is considered essential. Fletcher Challenge Energy has a very strong balance sheet. Management intends to use this strength to selectively grow the business in a value accretive manner. The first step in this growth was taken in July 2000 when Fletcher Challenge Energy announced an agreement to take a minimum 33.7 per cent stake in the listed Australian explorer Petroz NL.
At an operational level, Fletcher Challenge Energy is determined to improve performance so that returns on invested capital exceed the cost of capital in all of its businesses. The key to achieving this is a focus on cost reduction and improved asset utilisation.
Recognising the maturity of the upstream assets in New Zealand and Canada, strategic repositioning is underway to ensure a long-term sustainable future for these businesses. In New Zealand, exploration portfolio diversification is underway. This will see Fletcher Challenge Energy reduce exposure to individual licence areas, but increase the number of licence areas within which it has an interest.
In Canada, an active disposition and acquisition programme targets the elimination of higher cost properties and their replacement with high margin properties with a specific emphasis upon gas. To increase the risk-return profile of the Canadian business, Fletcher Challenge Energy will seek exposure to more frontier positions in less mature plays and basins. An early example of this shift is the recent acquisition of a land position in Northeast British Columbia. The primary focus of this move is gas and/or light oil. Near-term quick payback opportunities in Fletcher Challenge Energy’s plains oil operations are also a focus in the current high oil-price environment.
In Brunei, cost management in the non-operated Maharaja Lela field is a core objective for the business in the coming year. Additionally, opportunities exist to increase the asset utilisation of Maharaja Lela through the routing of either uncommitted gas from Block B or gas from third party sources, through the established facilities. Combined, these initiatives have the objective of improving unit production margins in Brunei by 20 to 30 per cent.
Consistent with its strategy, management continued to re-focus Fletcher Challenge Energy on its core exploration and production business throughout the year. One of the most visible steps toward this goal occurred with the sale of the 33.3 per cent interest in Natural Gas Corporation in July 1999. The shareholding was sold to Australian Gas Light Company for $268 million (net of costs) or $2.05 per share.
Less visible but equally notable was the establishment of improved core exploration and production processes within the business. Consistent exploration assessment, capital allocation and risk management processes were established across the business during the year. Fletcher Challenge Energy believes that success in the industry requires strict capital stewardship and portfolio management disciplines. These processes support that philosophy.
To align the operating business units with this strategy, significant changes were initiated. A restructure of the New Zealand Business Unit was completed in October 1999 resulting in staff reductions and migration of key sub-surface functions from New Plymouth to Auckland. This has achieved greater alignment between technical and commercial efforts. A business process review in Canada targeting 20 per cent operating cost improvements has been initiated with recommendations to be implemented during the first half of financial year 2001.
Consistent with the operating business changes, Fletcher Challenge Energy also reorganised its management structure in February 2000. Dr Lloyd Taylor was promoted to the role of Chief Operating Officer and Paul Chrystall to Chief Financial Officer. Reporting to Dr Taylor are three regional General Managers: Rick Webber, recruited to the role of General Manager New Zealand; Mark Taylor, promoted to General Manager, Canada; and Chris Newton, General Manager, Brunei.
Subject to authorities
delegated by the Fletcher Challenge Limited Board, the
primary decision making body within Fletcher Challenge
Energy is the Executive Committee (EXCO). This committee
comprises the Chief Executive, Chief Operating Officer,
Chief Financial Officer, Growth Director (with
responsibility for Merger and Acquisition activity), Human
Resources Director and Communications Director. The EXCO
Approximately half of Fletcher Challenge Energy’s production revenues are derived from the sale of products at prices linked to the international price of crude oil. The balance of the production revenues is substantially isolated from the effects of oil price movements.
The West Texas Intermediate (WTI) oil price benchmark strengthened significantly during the year, reaching a peak of US$34.13 per barrel on 7 March 2000. The price strength was attributable to the unity of the producer group, OPEC, in restraining production. This restraint was set against higher demand as a consequence of strong world economic growth, resulting in higher prices. Commercial oil inventories are now at low levels and a strong world economy is keeping oil demand high. WTI closed the year at US$32.50 per barrel.
Price differentials for Canadian heavy oil relative to WTI remained comparatively narrow during fiscal 2000. Combined with the rise in the WTI price, these narrow differentials have improved the economics of heavy oil considerably. Fletcher Challenge Energy’s Canadian oil and liquids realisations averaged C$21.97 per barrel during fiscal 2000, up 32 per cent on C$16.68 per barrel in fiscal 1999.
Gas produced from the Maharaja Lela field in Brunei is sold exclusively to Brunei Liquefied Natural Gas (BLNG) at prices that are linked to LNG prices. These prices, in turn, are related to the prices of a basket of crude oils, primarily Dubai. Consequently, realised gas prices in Brunei have benefited from the strength in world crude markets, with an average realised gas price during the financial year of US$1.83 per millions of British Thermal Units (mmbtu), an increase of 50 per cent over the average realised gas price in the prior year.
Pre-hedging, realised oil and condensate prices from the Brunei operations for the financial year were, on average, US$25.30 per barrel compared to US$16.28 in the prior year.
Natural gas is a regionally priced commodity.
As the leading oil and gas producer in New Zealand, Fletcher Challenge Energy’s gas production in that market is constrained by demand. Record levels of gas demand were enjoyed during fiscal year 2000, underpinned by high levels of methanol production and gas fired electricity generation.
In the petrochemical sector, Methanex remains the dominant gas purchaser accounting for approximately 45 per cent of New Zealand’s demand. Despite relatively low methanol prices, Methanex’s New Zealand plants have operated at or near capacity for the last 12 months.
Continued strength in demand from the power generation sector is expected as competition amongst newly deregulated generation companies increases. Gas-fired generation plant continues to be preferred in meeting increased electricity demand, supporting the fundamental attractiveness of gas exploration in New Zealand.
Almost all of New Zealand gas production is sold at prices linked to local producer price indices. Consequently, prices increased on average only one to two per cent over the 1999 realisations.
In contrast, Fletcher Challenge Energy’s gas production in Canada is capacity, rather than demand, constrained. In North America, gas is traded on open markets in which prices have strengthened significantly over the last 12 months to near record levels. This is the result of declining deliverability from established basins and plays, despite record levels of gas development drilling. Gas storage and inventory build is at historical 10-year lows on a seasonally adjusted basis.
Adding to this, gas demand has continued to strengthen in North America on the back of general economic growth and a clear environmental preference for natural gas in meeting the energy needs of this growth. Barring identification of a significant new low cost gas supply, Fletcher Challenge Energy believes that the long-term fundamentals are good for strong North American gas prices in the intermediate and longer term.
Realised natural gas prices averaged C$2.36 per gigajoule (GJ) during fiscal 2000, an increase of 15 per cent on the previous year.
Approximately 65 per cent of Fletcher Challenge Energy’s Canadian gas production is tied to the local Alberta gas price index (AECO). Construction of the new Alliance pipeline will be completed by the end of 2000 and will increase export pipeline capacity by two billion cubic feet per day. This is expected to keep differentials narrow between Canadian and US gas prices for another three to five years.
Fletcher Challenge Energy operates an Energy Price Risk Management Policy enabling the use of risk management tools and techniques. The strategic context of this policy is to ensure that cash is available to make value-enhancing investments in upstream oil and gas businesses.
To this end, the core objective of the policy is to ensure that any source of earnings and cash flow volatility arising from exposure to energy price movements:
– is within the
company’s capacity to sustain;
– does not threaten Fletcher Challenge Energy’s core strategic growth objectives, particularly in relation to capital expenditure programmes; and
– establishes a minimum acceptable return on assets, while retaining exposure to commodity price increases.
Fletcher Challenge Energy is not
permitted to undertake speculative transactions that have
the effect of increasing its exposure to energy price risk
beyond that which relates to the underlying asset
The full benefits of commodity price increases experienced during the year were not realised in terms of production revenues due to the significant hedging programme in place. Fletcher Challenge Energy realised an average oil price of US$17.96 per barrel (WTI equivalent) versus the average market price of US$25.93 per barrel. In North America, Fletcher Challenge Energy realised an average gas price of C$2.36 per GJ versus the average market price of C$3.64 per GJ. For financial year 2001 and beyond, the hedging programme involves a substantially increased use of instruments that retain upside participation whilst providing downside protection.
All hedges are carried within the Balance Sheet at market value on the balance date. Market value is the amount that the instrument is in or out of the money, with the calculation being based on the spot price at balance date. This “mark-to-market” entry grosses up the Balance Sheet. The deferred profit or loss, net of premia, on the underlying instrument is also recorded on the Balance Sheet. This amount is equal and opposite to the market value, after consideration of the premia.
Fletcher Challenge Energy discloses its full price risk management position quarterly. Details of the programme, which extends to financial year 2003, are available on the Fletcher Challenge Energy website (www.fce.co.nz/finance).
Core to Fletcher Challenge Energy’s vision of a regionally focused oil and gas company, is a strong exploration portfolio. Given the risks in the industry, where individual exploration wells typically have a probability of commercial success of less than 25 per cent, portfolio validity requires exposures to be spread.
Over the coming year, Fletcher Challenge Energy intends to diversify its exploration portfolio by acquiring or farming-in to additional licence areas. To balance exposure levels with materiality, equity interests in any given licence area will typically be between 25 and 50 per cent.
The major exploration project in New Zealand for the year was the drilling of the Pohokura prospect, located in PEP 38459, offshore Taranaki. Fletcher Challenge Energy has a 33 per cent interest in this licence area and is the operator. The exploration well, Pohokura-1, was spudded in February 2000 into the prognosed crest of the structure, approximately five kilometres offshore from the Taranaki coast. The well resulted in a major gas condensate discovery.
In the second of two drill stem tests, Pohokura-1 flowed natural gas at a rate of 17.0 million standard cubic feet per day (mmscf) through a 54/64th inch choke at a flowing tubing head pressure (FTHP) of 1380 psi. Gas-to-condensate ratios of approximately 70 barrels per mmscf were observed during the test, more than three times higher than expected. These results supported the pre-drill reserves hypothesis and were sufficiently encouraging for the Pohokura joint venture to move immediately to drill an appraisal well, Pohokura-2, into the structure. This rapid appraisal was a record for the New Zealand exploration industry.
Pohokura-2 was subsequently drilled approximately four kilometres to the north west of Pohokura-1. Natural gas flowed from the well at a rate of 30.7 mmscf per day through a one inch choke at a FTHP of 1938 psi. Gas-to-condensate ratios of more than 80 barrels per mmscf were observed during the test.
As a consequence of these tests Fletcher Challenge Energy doubled its initial reserve estimates to bring mean recoverable field reserves to 750 billion cubic feet (bcf) of natural gas and 40 million barrels of condensate. Proven reserves are estimated at 392 bcf of natural gas and 17 million barrels of condensate. Fletcher Challenge Energy’s share of these Proven reserves is included in company reserves as at 30 June 2000.
Pohokura is the largest field to be discovered in New Zealand since Maui was discovered over 30 years ago and the largest field discovered to date by Fletcher Challenge Energy. With the Maui and McKee fields now mature, Pohokura is likely to provide an important source of growth for Fletcher Challenge Energy, and an important fuel source for New Zealand business into the future.
Further appraisal and development planning is now underway to ensure that the Pohokura field is commercialised as soon as possible. Planning is underway for a 3D seismic survey and for a Pohokura-3 appraisal test to be drilled from an onshore site to an offshore bottom-hole location.
Elsewhere in New Zealand, drilling of the Tuihu prospect in PEP 38718, onshore Taranaki, is scheduled to begin in October. Fletcher Challenge Energy currently has a 90 per cent interest in this licence area and is the operator. Consistent with the portfolio approach to exploration, efforts are underway to farm-down this interest to a target of 50 per cent.
In July 2000, Fletcher Challenge Energy agreed to farm-in to PEP 38728, onshore Taranaki, and intends to undertake seismic survey work in this licence area in the coming year.
NEW ZEALAND CAPITAL
(Oil and Gas only) (NZ$ million)
Exploration 15 32 24
Development 58 43 53
TOTAL 73 75 80
Exploration Expensed (1) 3 41 12
CANADIAN CAPITAL EXPENDITURE
(Oil and Gas only) (NZ$ million)
Exploration 42 39 61
Development 96 73 85
Acquisition 44 21 32
TOTAL 182 133 178
Exploration Expensed (1) 13 14 24
BRUNEI CAPITAL EXPENDITURE
(Oil and Gas only) (NZ$ million)
Exploration 8 9 9
Development 27 135 118
TOTAL 35 144 127
Exploration Expensed (1) 8 9 9
(1) Fletcher Challenge Energy accounts for exploration expenditure on a ‘successful efforts’ basis with unsuccessful exploration expenditure being written off rather than capitalised.
Exploration expenditures remained in line with the previous year, comprising 27 per cent of the total capital budget. Fletcher Challenge Energy drilled a total of 55 net exploration wells, of which 57 per cent were successfully completed for production. Of the successful wells, 79 per cent were completed as gas wells. Two significant light oil discoveries and one gas discovery highlighted exploration activity. At Kneller, Fletcher Challenge Energy’s ongoing gas development project was augmented by a new pool discovery at Looma with nine metres of gas pay that flowed 2.1 mmcf per day on test with no depletion. The well is currently being tied in. Our Wolf Creek well at Willesden Green was cased with 10 metres of Ostracod oil pay and put on production with initial rates of 450 barrels of oil per day (bopd). At Mikwan, a well was cased with five metres of Nisku oil pay in a new reef structure and has recently been put on production at 300 bopd.
As part of Fletcher Challenge Energy’s strategy of shifting toward higher impact gas exploration and development, it farmed-in on a privately held and funded exploration vehicle focusing on the proven Slave Point Reef play type in Northeast British Columbia. In the coming fiscal year extensive 3D and 2D seismic surveys will be completed and an exploration well drilled in the fourth quarter.
Fletcher Challenge Energy has interests in over 2,800 square kilometres in Block B (35 per cent interest) and Blocks A & CD (26.95 per cent interest). Following a comprehensive 3D seismic survey of the acreage, Fletcher Challenge Energy identified approximately 35 attractive prospects and leads.
The three prospects, Bendahara Selatan A-1, Laksamana Utara-1 and East Egret-1 were identified as having independent geological hypotheses ranging from the conventional deltaic shelf play to the relatively untested higher risk/higher reward turbidite play further offshore. Three wildcat exploration wells were drilled during the year, one into each prospect. One well resulted in a non-commercial gas discovery, whilst the other two wells encountered poor reservoir development. All wells were abandoned and the programme finished in July 2000.
The total cost for the three wells was US$16.9 million. However, due to the farm-in arrangements that Fletcher Challenge Energy had with joint venture partner Unocal, the cost to Fletcher Challenge Energy was limited to US$2.6 million. This was a significant achievement as the wells were drilled at approximately half the cost and twice the speed as comparable offset wells. While the exploration results are disappointing, the ability to drill low-cost wells has a positive effect on the attractiveness of the future exploration portfolio. The three exploration wells provided valuable geological information that will be integrated into the understanding of nearby prospects and leads and the prospect portfolio more generally. A comprehensive review of the Brunei prospect portfolio will be carried out in the first half of fiscal 2001 and is likely to conclude with a recommendation for future exploration activities in Brunei.
In Block B, several gas condensate prospects have been identified close to the Maharaja Lela field. Prospect evaluation is advancing. Drilling of these prospects is subject to the resolution of infrastructure and gas marketing issues.
The Brunei Petroleum Mining Agreements require 50 per cent of all exploration acreage to be relinquished every five years. Fifty per cent of Blocks C/D must be relinquished by March 2001. Fletcher Challenge Energy is preparing for this. Elsewhere in Brunei, acreage recently relinquished by Brunei Shell Petroleum (BSP), known as Block I, remains open and the Brunei Government has indicated that some or all of these open blocks could be offered to the Blocks A&C/D joint venture. Fletcher Challenge Energy is in continuous dialogue with the Government to promote the annexation of the open blocks to the A&C/D joint venture and, if assigned, data from the blocks will be reviewed to establish possible prospectivity.
The Brunei Government has informed
the exploration industry that it intends to open the
unexplored deep-water acreage for evaluation and bidding. A
promotional presentation is scheduled for October 2000. The
Brunei deep-water acreage is considered by the industry to
hold the promise of another major hydrocarbon province that
could contain significant oil and gas potential.
Fletcher Challenge Energy is actively positioning itself to take full advantage of its strong presence and position in Brunei. The intention is to actively participate in the deep-water evaluation with a view to securing equity in this prospective acreage. To leverage its strengths (data, land and relationships), Fletcher Challenge Energy is pursuing a deep water partnering strategy targeting international companies with the necessary complementary capabilities that are required for a deep-water venture to be successful. If successful in the bidding round, Fletcher Challenge Energy could be involved in deep-water exploration in Brunei from as early as calendar 2002.
Fletcher Challenge Energy produced 48.9 million barrels of oil equivalent (mmboe) during 2000, an increase of six per cent over 1999 and the second highest annual production level in Fletcher Challenge Energy’s history. Record levels of natural gas were produced and sold in both New Zealand and Canada. Combined with the first full year of production in Brunei, total gas sales for the year were 197.8 bcf, an increase of 17 per cent over the prior year.
New Zealand gas sales were 129.2 bcf, an increase of 13 per cent. In Canada, Fletcher Challenge Energy’s gas production of 53.7 bcf combined with stable oil production brought total Canadian production to the record level of 14.1 mmboe. In its first full year of operation, the Maharaja Lela project in Brunei contributed production of 2.9 mmboe.
Total oil production fell 12 per cent to 14.7 mmboe. The decrease occurred in New Zealand’s Maui B and McKee oil reservoirs. Oil production in Canada was stable.
LPG production increased four per cent as
export markets to China and Papua New Guinea were
Gas production in New Zealand reached the record level of 129.2 bcf, an increase of 13 per cent over the 1999 level. In particular, this record production level was underpinned by high gas demand from Methanex throughout the year, and a combination of low hydro inflows and high levels of competition in the electricity sector resulting in elevated levels of gas fired generation.
Oil and condensate production was 9.2 million barrels (mmbbls), down 20 per cent from the 1999 level. This decline was experienced across all primary production fields in New Zealand and reflects the mature state of the reservoirs.
Condensate (a high quality light oil) is produced from Maui in conjunction with gas production. Condensate production levels for the year declined three per cent to 5.2 mmbbls despite increased gas production. This decline was a consequence of the restricted ability to produce from the highest condensate-to-gas ratio wells during the year due to development work being undertaken on the Maui B platform. Additionally, declining condensate-to-gas ratios are naturally experienced in the field over time as early priority is given to high condensate-to-gas ratio wells.
Crude oil production from Maui was down 41 per cent to 1.7 mmbbls (Fletcher Challenge Energy share), in line with the predicted natural decline of the F sand reservoirs. Additional development in the Maui BD oil reservoirs to offset the F Sand decline has been delayed and is discussed in more detail in the Development section of this report. Continued high Floating Production Storage and Offloading (FPSO) vessel uptime (average 91 per cent for the year) has partially offset the negative impact of BD drilling delays on Maui oil production.
McKee oil production declined 26 per cent during the year to 1.3 mmbbls as the field moves from being managed for oil production to gas production. Late in the financial year, an infill oil well, McKee 9A, was successfully drilled into the McKee field, accessing oil bypassed in the waterflood of the field. This well has boosted production rates by 22.3 per cent to 3,600 bopd.
The Waihapa and Ngaere fields continued to produce at an average of 528 bopd while the Tariki and Ahuroa fields produced an average of 23.6 mmscf per day and 924 barrels of condensate per day over the year, net to Fletcher Challenge Energy.
Canadian gas production for the year was 53.7 bcf, an increase of six per cent on the prior year and a record for the business. This increase was due to successful completion of the second Hatton infill drilling programme in Saskatchewan, an 18 well Viking development programme in Provost, and continuing development at St. Albert in the Central District. Gas production for the year averaged 147 mmscf per day, up from 139 mmscf per day in fiscal 1999. The gas exit rate for the Canadian business was 159 mmscf per day.
Canadian oil and liquids production for fiscal 2000 was 5.2 million barrels, in line with the previous year. All heavy oil properties were back to full production by mid-year. Additional developments at Hayter and Reward in Saskatchewan, and Hamilton Lake and Wolf Creek in the Provost District, have increased Canadian oil production. This has mitigated steep declines in some of Fletcher Challenge Energy’s more mature properties. The exit rate for oil at 30 June 2000 was 14,800 barrels per day, and the average for the year was 14,191 barrels per day.
Gas production of 14.9 bcf and liquids production of 0.39 mmbbls were in line with expectations.
Gas and condensate production for the fiscal 2001 year is expected to be similar to that of fiscal 2000 with variations only due to BLNG demand. Oil production is expected to reduce in fiscal 2001, as the two producing oil reservoirs deplete in line with expectations.
Operation of Fletcher Challenge Energy’s New Zealand production facilities was smooth during fiscal 2000, with no significant interruptions to production.
The waterflood programme in the McKee field, designed to enhance oil production rates, was suspended during the year. Selected infill drilling prospects were identified, targeting pockets of oil that were not swept by the waterflood. Two of these prospects were drilled; the first, McKee-9A, was brought into oil production in early June at a choke-restricted rate of 800 bopd. A second infill well, McKee-2C, only encountered a residual oil column and was abandoned in July 2000.
Operating cost control is one of the essential challenges in managing production from maturing oil and gas fields. In Fletcher Challenge Energy’s Canadian business, efforts to control and reduce operating costs by shutting in low productivity wells and redeveloping existing properties through infill drilling have met with some success. However, the underlying reason for the high cost structure is a portfolio of mature properties with declining production and rising water-cut. Additionally, the increase in heavy oil production with its relatively higher costs compared to gas has led to further increases in operated lifting costs, and third party lifting and processing tariffs have also risen. Lifting costs increased three per cent to C$5.25 per barrel of oil equivalent (boe) compared to C$5.11 per boe in the previous year.
Fletcher Challenge Energy took the decision to dispose of a number of properties that incurred much of the increased operating cost. A package of properties was offered for sale towards the end of the fiscal year and bids totalling C$23 million were received. By 30 June 2000, Fletcher Challenge Energy had disposed of 1.5 mmboe for proceeds of C$12.2 million. The average operating cost of the disposition properties was approximately C$7.70 per boe. Production from these properties was approximately 550 boepd.
Fletcher Challenge Energy will continue to divest high operating cost properties in Canada during fiscal 2001.
The Maharaja Lela field production facilities in Brunei comprise two offshore platforms (central and satellite) that are connected by sub-sea pipeline to an onshore separation and processing plant. In 2000, the field successfully completed its first full fiscal year of production and is now in its second year of contractual production. Total Fina Elf S.A. operates the field. Fletcher Challenge Energy has a 35 per cent working interest and, as a consequence of the development funding structure, Fletcher Challenge Energy is expected to have rights to 40.29 per cent of production for the full project life.
Offshore, all six wells are now available for
production, following successful interventions on two wells.
Modifications to the satellite platform allow full
contractual production from either platform. This
significantly enhances system reliability. Onshore, the
plant is operating smoothly.
The Maharaja Lela development is now substantially complete and the performance enhancement focus has shifted to operating costs. With a high level of fixed costs, the main driver of operating costs is staffing levels. Fletcher Challenge Energy continues to work with Total Fina Elf S.A. to ensure that staffing levels, particularly amongst expatriate staff, are appropriate for the operation. With the finalisation of the development phase, staff levels are falling.
An excellent relationship exists between the operations personnel of the joint venture and our primary customer, BLNG. This operational relationship has enabled a high level of flexibility in managing the operations of both the Maharaja Lela facility and the BLNG facility. For example, gas production rates from Maharaja Lela have proved to be sustainable around 20 per cent above the contractual plateau rate. On several occasions during the year, BLNG has asked for gas to be supplied at above contractual rates to compensate for production shortfalls from their other supplier.
Scheduled maintenance was performed as planned during the year and unscheduled shutdowns were few and of short duration.
WORK IN PROGRESS
In fiscal 2000, development expenditure in New Zealand was $58 million ($12 million onshore and $46 million offshore). The majority of this expenditure was incurred on the Maui BD incremental oil project. This project was originally intended to target untapped oil reservoirs in the lower Maui D Sands through the drilling of three new horizontal wells from the Maui B platform. Oil production from the first of the wells was projected to begin in March 2000.
In July 2000, after a series of problems, Fletcher Challenge Energy approved the recommendation of the operator, Shell Todd Oil Services, that the original project objectives could no longer be achieved and that the remaining programme be substantially modified. The difficulties centred on the ability to drill the horizontal wells through the coaly sequences as proposed.
Rather than continuing with the horizontal wells, the decision was taken to sidetrack well MB-7 and complete it as a conventional deviated producing well. While this option considerably lowers the technical risk associated with the well, expected reserves recovery from the project has also been reduced significantly. Decisions on the future progress on well MB-6 and a third well are dependent on the outcomes of the revised MB-7 scope. By late July 2000, total expenditure on the project had reached $54 million compared to a budget of $45 million (Fletcher Challenge Energy share) for the total original project.
This has been a disappointing project for both the Operator and Fletcher Challenge Energy. However, we have moved to ensure that all possible lessons from the project are captured and incorporated into future work.
McKee reserves were fully re-evaluated during the year leading to a downgrading of reserves by 13.6 mmboe. The downgrade was approximately equally split between gas and oil reserves. An infill well, Toetoe-6B, drilled in November, proved the position of a major thrust fault, confirming the reservoir geometry model and supporting the reserves downgrade.
Development activity in Canada continued to focus on increasing gas production in all Districts in order to take advantage of strong natural gas markets. Towards the end of the year Fletcher Challenge Energy also reactivated a number of heavy oil development projects previously deferred due to low oil prices. Development spending comprised 63 per cent of the total capital budget.
In the Saskatchewan District, the second phase of the Hatton infill drilling programme commenced in July 1999. Despite delays due to heavy summer rains, all wells were completed and in production by the end of the second quarter, adding two mmscf per day to Canadian gas production. At Hayter, the 10-well horizontal programme was successfully completed with all wells tied in and producing 500 bopd of incremental production previously unrecoverable due to high water content. At Reward, Fletcher Challenge Energy drilled 12 development wells that are now on full production, adding 500 bopd. A total of 91 development wells were drilled in the Saskatchewan District, of which 56 were completed as gas wells, 34 as oil wells and one was dry and abandoned, a success rate of 99 per cent.
In the Provost district, eight development wells were drilled and tied-in to the Monitor gas plant. A Viking oil programme at Hamilton Lake added 100 bopd of light oil production. A total of 26 development wells were drilled, of which 18 were completed as gas wells, six as oil wells and two were dry and abandoned, a success rate of 92 per cent.
In the Central District, St. Albert continues to produce 12 mmscf per day with the addition of a new zone and two new Belly River wells. Activity in Central Alberta was less intense, with a total of 12 development wells being drilled. Of these, nine were completed as gas wells, one as an oil well and two were dry and abandoned, a success rate of 83 per cent.
Fletcher Challenge Energy continues to generate an active inventory of gas and oil development projects and will spend approximately C$95 million in the coming year, representing 75 per cent of the Canadian capital budget. Of this, spending will be split evenly between oil and gas.
In Argentina, Fletcher Challenge Energy has a 25 per cent interest in a joint venture in the Neuquen Basin with partners Chevron San Jorge (operator – 60 per cent) and Australian Worldwide Exploration (AWE), a listed Australian explorer (15 per cent). In the first half of the year, three wildcat exploration wells were drilled by the joint venture into the onshore Block CNQ-16A. All wells resulted in gas discoveries.
The commercial development of two of these discoveries was approved by the joint venture in July 2000 and first gas production is currently planned for mid-2002.
The roll-out of the Challenge Petroleum brand of retail stations in New Zealand continued strongly throughout the year. Challenge now has 98 branded petrol stations located from Albany in the North to Bluff in the South, three times the number in June 1999. In addition, there are 31 fuel stops servicing road transport fleets nationally.
In October 1999, a further major milestone in the history of Challenge was reached with the opening of a 17,000 tonne oil products terminal in Timaru. This terminal formed the beachhead through which Challenge’s growth in the South Island was launched. In the nine months since launching in Timaru, 56 independent service station owners are now marketing under the Challenge brand – more than one site conversion per week, an impressive achievement.
During the year Challenge sold and leased-back the land and buildings on which many of its company-owned sites are located. As a result, $17 million cash was released from the business.
continued to be very tight throughout the year as rising
refined oil product prices and a declining NZ-US dollar
cross-rate dramatically increased costs. Spot refined
product prices rose from NZ$29 per barrel in March 1999 to
over NZ$81 per barrel in August 2000. Intense competition
meant these increased costs were not fully passed on.
Emphasis on cost reduction continues to be a primary business focus within Challenge. Distribution costs in particular have been an area of focus for the business. Challenge’s exclusion from participation in the economic benefits of the distribution infrastructure shared by the major oil companies remains an obstacle. A number of initiatives to reduce distribution costs have been implemented.
Challenge has continued to maintain its impressive safety record. No lost time injuries occurred during the year either amongst the 225 strong team that supports the Challenge service station network, or in the Owens Tankers whose delivery fleet has travelled almost five million kilometres delivering product to Challenge customers.
In Brisbane, the terminal operation continues to trade profitably.
Capstone Turbine Corporation is a Los Angeles based designer and manufacturer of micro-turbines. The turbines produce electricity (30kw and 60kw units) as well as very clean exhaust. With one moving part, rotating at 96,000 rpm, the turbines use air bearings rather than liquid lubricant, which, coupled with innovative burner design, result in extremely low emissions. Advanced power electronics are a further feature of the turbines. The turbines were first conceived as a vehicle power unit to meet Californian clean air requirements. In 1988, Fletcher Challenge Energy recognised the potential of the design in stationary applications and began discussions with the company, then known as NoMac.
Fletcher Challenge Energy made its first equity investment in Capstone in 1995, when it also secured the marketing rights to stationary applications in certain regions. This was an investment in the development of new energy and distribution technologies as part of Fletcher Challenge Limited’s resources-to-customer chain and integrated energy company strategies. Fletcher Challenge Energy’s strategies are now focused on upstream oil and gas exploration and production.
Capstone Turbine Corporation listed on the NASDAQ market on 29 June 2000. Trading closed on 30 June at US$45.06 per share. Fletcher Challenge Energy owns 8,123,131 shares in Capstone, and is the largest shareholder. The value of Fletcher Challenge Energy’s investment in Capstone at 30 June 2000 was $781 million. This valuation, net of book value of $51 million, is carried in the Revaluation Reserve within Fletcher Challenge Energy’s Balance Sheet. This is a US GAAP requirement.
During the year Fletcher Challenge Energy sold its marketing rights back to Capstone for US$20 million cash plus 1.25 million Capstone shares valued at US$9 million. Given its “one-off” nature, this US$29 million has been recognised as a NZ$61 million Unusual Item in Fletcher Challenge Energy’s Net Earnings. Proceeds of US$9 million were received during the year with the balance of US$11 million received in July 2000.
Fletcher Challenge Energy now considers the shareholding in Capstone Turbine Corporation as non core and is reviewing options to maximise the value of this investment for shareholders.
On 19 July 2000, Fletcher Challenge Energy announced an agreement with a listed Australian explorer, Petroz NL, to take an equity interest in that company. The agreement is subject to Petroz shareholder approval. If approved, the interest will be acquired through the exercise of an option to buy shares, a placement of new shares, and the underwriting of a rights issue. In combination, these mechanisms will result in Fletcher Challenge Energy owning between 33.7 per cent and 58.6 per cent of Petroz for an average price of A$0.39 to A$0.35 respectively per Petroz share. Total cost of the transaction to Fletcher Challenge Energy is expected to be NZ$81 million to NZ$128 million.
In June 2000, the High Court in New Zealand ruled that the 17 year gas sales and purchase contract entered into between Electricity Corporation of New Zealand (ECNZ) and Fletcher Challenge Energy in 1997 was binding. ECNZ, through its agent Genesis, had disputed the validity of the contract. However, the Court held that the parties had intended to be bound and that the contract was workable. ECNZ has appealed the decision.
Fletcher Challenge Energy continues to defend actions brought against it by the Commerce Commission in relation to its purchase of further interests in the Kupe field in 1997.
HEALTH, SAFETY AND ENVIRONMENT
Fletcher Challenge Energy is committed to continued improvement in its management of health, safety and environmental (HSE) issues. This is reflected in our annual Health, Safety and Environment Report. We expect to release our next report in December 2000. The previous HSE Report can be found on the Fletcher Challenge Energy website (www.fce.co.nz/finance).
Details on Fletcher Challenge Energy and its operations for the year ended 30 June 2000 can be viewed at the Fletcher Challenge Energy World Wide Web site at: (www.fce.co.nz/finance).
Information on the financial
performance and position of the Fletcher Challenge Group
(including the Financial Statements) is contained in the
Fletcher Challenge Group Results Announcement.