Production and Operations

Gross average daily field production for the year ended 31 December 2009 was 1,535 stbd (2008: 2,550 stbd). The production facilities’ uptime performance was 51 per cent (2008: 88.2 per cent). The decrease in production was the result of an extended shut-in to repair the field’s offshore mooring facility. Adverse marine conditions compounded the time taken to finish the repairs. The field recommenced production on 24 January 2010 at a rate of 3,336 stbd. In 2009 the joint venture extended the contract of the PY-3 field’s production facility for one year up to 24 January 2011. The new contract provides for a 40 per cent reduction from the previously contracted rate. Gross average daily production for February 2010 was 3,450 stbd. Currently the field is producing at a gross rate of 3,400 stbd. We anticipate that the PY-3 field will average
gross daily production of 3,000 stbd for 2010.

In February 2009, the Company completed the re-entry and drilling of an extended lateral section in the PY3-PD4-RL well. With the assistance of nitrogen lift, the well flowed at 700 stbd of oil with 30 per cent water-cut. However, the well was unable to be re-activated as a self flowing well. The well has been completed as a producer with a gas lift valve to allow for future production when gas lift compression facilities are installed on the FPU. Hardy has subsequently revised its geological and reservoir simulation models to incorporate new data gathered from the PY3-PD4-RL well. The revised model will be used to plan future in-fill drilling and production facility requirements.

Actual gross field production for the year ended 31 December 2008 was 2,550 stbd (2007: 4,150 stbd). The production facilities’ uptime performance was 88.2% (2007: 96.8%). The decrease in production is due to the conversion of well PY3-3RL into a water injection well (as the well ceased to produce due to water loading), unplanned maintenance and natural decline. In addition, work on well PD-4 commenced on 15 October 2008 to drill a lateral well from the existing surface location.

Production for January and February 2009 was 2,846 stbd and 2,787 stbd respectively. We anticipate that the PY-3 field will average gross daily production of 3,000 stbd for 2009. Currently the field is producing at a gross rate of 3,200 stbd.

For the year ended 31 December 2008, the average water injection rate was 7,139 bwpd (2007: 5,800 bwpd) which, at current production levels, is sufficient to maintain voidage replacement. Voidage replacement is important for maintaining pressure levels in the field that should ultimately enhance overall recovery of oil from the field. Injection facilities’ uptime performance was 84.5% (2007: 86.8%).

The PY-3 field was shut down twice in 2008. The first shut-down occurred between the 3rd to 12th of February 2008, due to Normor Buoy inspection and the renewal of jumper hose as per ABS requirements. The field was again shut down from 26 November to 29 December 2008, due to the FSO loading hose, mooring hawser back-up rope failure during tropical cyclone Nisha.

Oil production from the PY-3 field in the nine month period ended 30 September 2007 averaged 4,560 bopd (821 bopd to the Group). The reduction in production was largely attributable to the natural decline of the field and, as announced on 10 August 2007, the shut-in of PY-3-3RL due to water breakthrough. Average daily production during October and November 2007 from the PY-3 field was 3,364 bopd.

PY-3 Background
The PY-3 field came on stream at the end of November 1997 with 4 subsea wells (PY-3-2; PY-3-3; PD-3 and PD-4). Since production start-up, the field showed a steady decline from an initial production rate of 12,000 bopd, with abandonment originally expected in 2001. After the Company acquired HEPI in September 1999, it actioned measures to improve production and reduce costs.

Following the acquisition of HEPI by the Company, HEPI initiated phase II of the field’s development by re-entering three vertical oil producers, drilling the two deepest lateral wells in India and putting them on production.

In November 2002, well PD-3 was lost when the drillship, after having successfully drilled and tested a lateral from the original vertical hole, was driven off location following a break in the anchor chain. The wellhead assembly was sheared off, but there were no injuries, loss of life or environmental damage. The well was made secure shortly thereafter. The successful re-drill of PD-3 in May 2004 increased production to 7,200 bopd which subsequently declined to 6,660 bopd as at 31 December 2004.

In September 2003, HEPI implemented water injection through the PY-3-2RL lateral well which has been essential for maintaining reservoir pressure and maximising recovery from the field. These developments have considerably extended the economic field life of the PY-3 field.

The facility at PY-3 consists of the floating production unit, ‘‘Tahara’’, and a 65,000 DWT tanker, ‘‘Endeavor’’, which acts as a floating storage and offloading unit. There are four sub-sea wells tied back to Tahara. Tahara has a three-stage crude oil separation system, with the first two stages being three-phase separators and the third stage a two-phase separator. Actual liquid processing capacity on Tahara is 20,000 bopd with 17 MMscfd of gas handling capacity.

For the nine month period ended 30 September 2007, average water injection rates were approximately 6,643 bwpd which is sufficient to maintain voidage replacement. The field produces associated gas of 3.7 MMscfd. This produced gas is used as fuel gas, with excess gas being flared. Current stabilised crude oil is pumped from Tahara to Endeavor for storage and offloading to shuttle tankers.

Crude oil from the PY-3 field is sold to CPCL at its refinery in Nagapatsham, near Chennai. As operator of the field, HEPI advises CPCL of a date range during which cargo will be ready for lifting. CPCL then nominates a tanker to make the lifting and it is transferred to the CPCL terminal in approximately 100,000 bbl lots. The price at which the cargo is sold is determined under the crude oil sales agreement between CPCL and HEPI (as Operator), dated 26 September 2003 (and effective for all sales since 1 October 2001) which stipulates a price of Brent minus 35 cents per barrel, dependent on the crude meeting the quality standards stipulated in the agreement.