This report provides an overview of Apache's global upstream assets. It also highlights the distribution of the company's top regions in terms of commercial value, maturity and relevance to the company's upstream portfolio.
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The upstream oil and gas industry conducts activities against a backdrop of growing energy and environmental challenges. Political instabilities, international conflicts and government and environmental regulation have all impacted the production process.
This has forced companies to re-examine their corporate strategy, moving away from high-risk exploratory drilling to lower-risk exploration in mature basins as they search for increased returns.
This Upstream Oil and Gas Portfolio report provides in-depth portfolio analysis, including individual asset summaries, key upsides and downsides, regional timeline of strategic events, SWOT analysis and our take on how this company’s strategy will evolve.
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1. John Brookes (Apache 55%): John Brookes is a gas/condensate field located in 70 metres of water, 55 kilometres west of Varanus Island in the Carnarvon Basin. The development consists of an unmanned platform tied in to the ex-East Spar production facilities on Varanus Island. The facilities required upgrading to deal with the higher CO2 content of the John Brookes gas.
Production started in the second half of 2005, with the field supplying a number of domestic customers in Western Australia. First gas from the field was delayed, which meant that the JV had to buy 14 bcf of gas from the Harriet JV to make up the shortfall and ensure it met its contractual commitments.
In June 2008 an explosion on Varanus Island shut-in all production facilities for Harriet and John Brookes. Production at John Brookes resumed in August 2008 and has periodically produced at rates above 300 mmcfd. Production can fluctuate depending on customer demand.
John Brookes gas is primarily individually marketed by Apache and Santos, but some of the early deals were supplied jointly.
2. Reindeer (Apache 55%): The Reindeer gas field is located in the Dampier sub-basin of the Carnarvon Basin off the coast of Western Australia. The development consists of an unmanned offshore platform tied back to a new gas processing plant at Devil Creek, 50 kilometres southwest of Karratha. The Devil Creek plant is the third major domestic gas hub in Western Australia and delivers gas directly into the Dampier to Bunbury Gas Pipeline.
The Final Investment Decision (FID) was taken in April 2008 but a binding Gas Sales Agreement (GSA) was not signed until January 2009, which delayed the start of development. Three other gas sales agreements have been since signed with Rio Tinto, Murrin Murrin Operations and an unnamed party.
First gas was delivered in December 2011. Field performance has been better than expected, but in 2014, production has been restrained by customer demand. From 2015, we assume customer offtake recovers to a peak plateau of 97-102 mmcfd.
3. Macedon (Apache 28.57%): Macedon (formerly known as the West Muiron gas field) was discovered in 1992, and is located offshore Western Australia. The low calorific value of the gas, high development costs and complex field geology initially delayed development. However, increasing domestic gas prices in Western Australia and changes to legislation, allowing leaner gas into the domestic network enabled the field to be developed.
FEED was completed in July 2010 and the Final Investment Decision (FID) was made in September 2010. The project includes four subsea wells, tied back to an onshore gas processing plant at Ashburton North. The gas is transported 67 kilometres to the Dampier to Bunbury pipeline, then delivered to market. First gas was achieved in August 2013.
The field has performed better than expected with strong daily production rates reaching over 200 mmcfd.
4. Pyrenees Area (Apache 29.3%): The Pyrenees Area includes a number of offshore heavy oil fields in the Exmouth sub-basin of the Carnarvon Basin. The fields lie in shallow water, close to the Enfield, Vincent, Van Gogh and Stybarrow FPSO developments.
The Final Investment Decision (FID) was taken in July 2007. Three fields - Crosby, Ravensworth and Stickle - were initially developed through a purchased Floating Production Storage and Offloading (FPSO) vessel. Production commenced from the Crosby and Stickle fields in March 2010, with Ravensworth coming onstream in August 2010.
A second phase of development began in August 2013 to stem a sharp natural decline in field output. This included three further development wells on Stickle and Ravensworth, plus three wells and the subsea completion of the nearby Moondyne field. The field was brought onstream in April 2014, raising production rates by around 8,000 b/d.
We expect additional development.
5. Van Gogh/Coniston/Novara (Apache 52.5%): Van Gogh is within a cluster of commercial heavy oil fields in the Exmouth Sub-Basin, offshore Western Australia. Like its neighbours, it has been developed through the use of a standalone Floating, Production, Storage and Offloading vessel (FPSO). The Van Gogh field was confirmed as a commercial development in 2006, and Apache and INPEX took FID in May 2007.
First oil had been planned for early 2009, but a fire onboard the FPSO whilst it was undergoing conversion delayed first production until February 2010. After initially producing in excess of 50,000 b/d, production was constrained later in 2010 and into 2011, due to cyclones and FPSO reliability issues. The Van Gogh partners purchased the FPSO for US$185 million in January 2012, to allow them to control maintenance and modifications. We expect the field to produce until late-2020.
The Coniston/Novara development will be tied into the Ningaloo Vision FSPO, with production start-up delayed from Q3 2014 into 2015.
6. Halyard-Spar (Apache 55%): The Halyard and Spar fields lie in Federal waters offshore Western Australia, approximately 70 kilometres from Varanus Island. The fields are developed through subsea completions, tied back to the Varanus Island gas hub for gas processing. Both fields will supply gas to the domestic market.
Spar has lain undeveloped since it was discovered in 1976 by the Gorgon JV. Halyard was discovered by Apache in 2008, in a sole-risk well. In 2010, Apache acquired a 55% operated interest in Spar from Santos, whilst Santos paid to exercise its back-in right to equity in Halyard. This aligned the equity in both assets and allowed joint development.
FID was taken on Halyard in August 2010 and first production was in June 2011. The field is produced through the existing East Spar manifold and is controlled from the John Brookes platform. Spar was initially expected to be brought onstream within a year of Halyard, but we do not expect the field to be onstream until 2015.
7. Other fields: Apache has a 33.3% operated interest in the Stag heavy oil field, south of the Reindeer Area. The company has been very successful in prolonging field life through a targeted infill drilling campaign. It has also been able to reduce drilling costs to justify ongoing activity. We expect production from Stag to cease in 2019. The company also has an 81% operated stake in the Harriet Area, a collection of over 30 oil and gas fields located in the Barrow sub-basin on the North West Shelf. Production has been in decline since 2010, and we expect the project will cease output in 2018.
Australia: exploration potential
Valuation and key assets
UK: portfolio review
UK: asset overview
Central North Sea
Northern North Sea
UK: exploration potential
Foreign exchange rate assumptions
In this report there are 34 tables or charts, including:
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Company report | Mar 2015
Apache corporate - global upstream portfolio analysis
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