Event
BPT held an investor day in Sydney yesterday. Management provided an update on current operations in the Cooper Basin, progress surrounding its international assets and also a comprehensive technical presentation highlighting its key findings surrounding fracability and completion techniques regarding its unconventional assets in the Nappamerri Trough.
Impact
Patchawarra flow rates imminent: Over the last 5 months it appears BPT
has undertaken an extensive study of the stress regime across the basin and optimal frac, well-bore & propant design. Nonetheless, given the shifting focus to the basin-centred gas potential of the Nappamerri Trough (where BPT sees 200tcf of GIP or double the potential of the REM shales) flow results at Moonta, Streaky and Hallifax are likely to provide more tangible evidence that BPT is cracking the unconventional code. Application of these findings to frac design, a doubling of the pumping rate and a larger number of frac stages is likely to contribute to higher initial flow rates.
Adding a new dimension to the Western Flank: While the original Western
Flank oil discovery at the Sellicks field was made 10 years ago, the new discoveries in PEL 91 appear to have added a new dimension to the Western Flank creaming curve. Following the successful Bauer discovery and
appraisal program (that has delineated 10mmbbls which is equivalent the total volume produced from PEL 92 to date), BPT estimates that the Pennington-1 discovery exceeds 2mmbbls which is more than 4 times the pre-drill target. By comparison Western Flank reserves additions targeted in the FY13
exploration program imply an average pre-drill target of merely ~340kbbls per well, which would appear conservative.
Adequate funding until the end of FY14: Following the A$350m capital
raising early this year BPT remains in a healthy financial position (with A$330m of cash balances as at November 2012). We forecast A$712m of operating cash flow over the FY13-14 period (vs. BPT‟s guidance of A$800m). While this cash flow will be almost entirely re-invested into the proposed capital program over the next 2 years, we forecast BPT will retain a healthy A$180m cash balance at the end of FY14.
Earnings and target price revision
Upgrades to NAV and earnings: We have made several changes which see
our NAV rise by 9.5% to A$1.84/sh, with a commensurate 6% move in our target price to A$1.70/sh. Our new target offers a total return of 17%. We have also upgraded FY13e and FY14e NPAT by 12% and 8% respectively.
Price catalyst
12-month price target: A$1.70 based on a DCF methodology.
Catalyst: An initial flow rate at Moonta-1 is expected next week.
Action and recommendation
Maintain an Outperform and a higher A$1.70/sh target price: With the
next stage of the unconventional program underway and completion of crude pipeline infrastructure expected by early next year, activity is set to accelerate in the next 6 months.
Macquarie Private Wealth Beach Energy
6 December 2012 2
Progress on all fronts
Beach Energy held an investor day in Sydney yesterday. Management provided an update on current operations in the Cooper Basin, progress surrounding its international assets and also a comprehensive technical presentation highlighting its key findings surrounding fracability and completion techniques regarding its unconventional assets in the Nappamerri Trough. There was little change to formal guidance (production guidance of 8.5-9.0mmbboe and capex guidance of A$350-450m for FY12 remains unchanged). We remain at the higher end for both production and capex.
It appears the base business (in particular the Western Flank) is performing well and BPT is coming to terms with the unique characteristics surrounding both the REM shale sequences and Patchawarra tight sands in the Nappamerri Trough. While there was no update on the Moonta-1 fracture stimulation and flow testing we understand results could come as soon as next week. Furthermore, with the Moonta-1, Streaky-1 and Hallifax-1 wells expected to be tested over the next 2-3 months and drilling of the Holdfast-2 horizontal well due to commence in mid-December (with a flow rate here expected in April next year), news flow surrounding the unconventional program is expected to accelerate over the next 6 months.
As a result of the investor day we have made several changes which see our NAV rise by 9.5% to A$1.84/sh, with a commensurate 6% move in our target price to A$1.70/sh. Our new target offers a total return of 16%. We have also upgraded FY13 and FY14 NPAT by 12% and 8% respectively.
Still optimistic on East Coast gas markets
The local strategy continues to be underpinned by management‟s optimistic view surrounding East Coast gas markets. That said, updated analysis from Core Energy Group points to domestic gas demand (ex LNG) remaining largely flat over the next 15 years (which is consistent with revised forecasts from other consultants and industry bodies). At last year‟s investor day BPT pointed towards a doubling of domestic gas consumption from 715PJ/a to 1,350PJ/a in 2025. Including demand for gas from LNG export projects, expected total East Coast demand in 2015 has fallen from ~3,500PJ/a last year to ~3,000PJ/a currently. Nonetheless management continues to believe east coast gas prices will trend towards A$6-9/GJ, which is increasingly the consensus view.
BPT‟s views regarding the East Coast gas markets are perhaps best characterised by the prolonged negotiation with STO regarding the 750PJ Horizon/GLNG supply contract. Although it has now been more than 2 years, BPT is yet to commit to this contract. Nonetheless over this period we have seen a significant tightening of the East Coast market as concerns surrounding deliverability of CSG into LNG grow. In hindsight BPT‟s reluctance to commit to the supply deal 4 years ahead of first gas appears to have paid dividends, particularly given the growing competition from domestic users and existing contract rollovers post 2016. With STO already highlighting that Cooper shale could be commercial at A$6/GJ under an
optimised development scenario and an increasing number of other companies (including BPT) investigating the unconventional potential of the Cooper Basin, we expect the cost structure here to fall as the resource is better understood and drilling efficiencies can be achieved as projects move through to development. As highlighted in Fig 1, this could flatten the cost curve in the long-term, potentially capping east coast gas price inflation.
Macquarie Private Wealth Beach Energy
6 December 2012 3
Fig 1 East Australian gas supply cost curves - BPT sees east coast prices settling in the A$6-9/GJ range – however this appears to take little account of its apparently vast unconventional potential
Fig 2 Supply shortages (and high prices) apparent from 2015-2020 before supply (including
unconventional) catches up in the longer term
Source: Macquarie Research, December 2012 Source: Macquarie Research, December 2012
Unconventionally busy
Over the last 5 months (since the Holdfast-1 flow result of 2.1mmscf/day was delivered) it appears BPT has undertaken extensive study of the stress regime across the basin and optimal frac, well- bore & propant design. Nonetheless, given management‟s shifting focus to the basin-centred gas potential of the Nappamerri Trough (where BPT sees 200tcf of GIP or double the potential of the REM shales), flow results at Moonta, Streaky and Hallifax are likely to provide more tangible evidence that BPT is cracking the unconventional code.
BPT expects to release further news on Moonta-1 next week. Following successful testing the Halliburton frac spread will complete a 10 stage frac program (predominately across the Patchawarra formation) at Streaky-1 and flow test by mid-December and a 15-stage frac across the full Permian section at the Hallifax- 1 well with flow testing expected in early January next year. With double the pumping rates being adopted (80bbls/min) compared to previous wells and given the more productive nature of the Patchawarra (as evidenced by the isolated 750,000scf/day delivered from one frac stage at Holdfast-1) expectations of initial flow rates are likely to be well above the 3mmscf/day delivered at Moomba-191 (and potentially as high as 4mmscf/day).
The Holdfast-2 horizontal well remains on schedule to spud in mid-December. The well will target the Murteree shale interval. Given the comingled nature of testing at previous wells, contributions from this section have not been disclosed. That said STO recently highlighted that 2.4mmscf/day (of a total 3mmscf/day) came from these intervals at Moomba-191. BPT is currently proposing a 15-stage frac program. However with flow testing not expected to commence until April 2013, results here are still at least 5 months away. That said given this well will be largely completed under a commercial setting, expectations regarding flow rates are likely to remain high.
With A$200m of capex already committed to the unconventional program in the Cooper Basin until 2013, it appears BPT is comfortable de-risking the play on a 100% basis rather than bringing in a partner early and diluting the upside. While this appears a risky strategy it also can be seen as a vote of confidence in the acreage potential. That said with 9 vertical and 3 horizontal wells expected to be fracture stimulated and flow tested by the end of CY13, BPT is likely to have much greater clarity regarding the optimal development model (whether it be vertical development of the Patchawarra or horizontal development of the REM shales). Consequently as drilling moves further towards a development setting in late 2013 the pressure to secure a funding partner is likely to grow.
0 2 4 6 8 10 12 14 16 18 20 0 50,000 100,000 150,000 200,000 250,000 300,000 A$/GJ 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 Domestic QCLNG GLNG
APLNG Shell Supply
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6 December 2012 4
While a commercial development is unlikely prior to 2015, BPT expect to commence an extended pilot program as early as late 2013. Production here could potentially be tied into the nearby raw gas pipeline and potentially Moomba/Ballera gas processing infrastructure with little incremental capital. While we do not expect these third party sales will attract premium gas prices (BPT is realising merely A$2.5/GJ from the Middleton/Brownlow Wet Gas Pilot Program), a growing production base is likely to build confidence regarding the ultimate production profile. Both Encounter and Holdfast remained on flow test for only 4-6 weeks. Over this testing period the flow rate at Holdfast declined from 2mmscf/day to as little as 700,000scf/day.
While there are still many moving parts our analysis suggests that if BPT can increase flow rates and lower well costs to match those seen in the US, then unconventional wells could deliver a 12% return with a gas price of only $5/GJ.
Fig 3 Possible evolution of wells costs and initial production rates in the Cooper…
Fig 4 …are likely to see required break-even gas
prices fall over time
Source: Macquarie Research, December 2012 Source: Macquarie Research, December 2012
Western Flank supporting near-term earnings growth
The Western Flank continues to be a prospective asset for BPT, with 10 successful wells already delivered in FY13 from 11 wells drilled. The current exploration program across PEL 91, PEL 92 and Senex-operated acreage incorporates 19 wells targeting 6.5mmbbls (gross). This implies an average pre-drill target of only ~340kbbls per well (which appears conservative). While the original discovery at the Sellicks field was made 10 years ago, the new discoveries in PEL 91 appear to have added a new dimension to the Western Flank creaming curve. On an unrisked basis the reserves upside at Bauer, recent success at Pennington-1 and moderate further exploration success could add 6Acps to our BPT NAV.
With discoveries totalling 15mmbbl (of which 10mmbbls has been produced) and exploration success rates of over 40%, PEL 92 continues to represent the lion‟s share of BPT‟s Western Flank production base (current net production here is 3,750bopd and this is expected to grow to 5,2500bopd next year or ~50% of BPT‟s production target). The Windmill-1 discovery successfully recovered oil from the Birkhead formation (which has been successfully targeted in PEL 91), extending this play 25km further South.
In PEL 91, reserves at Bauer continue to rise following successful appraisal wells. The current 10mmbbl gross reserve estimate does not incorporate the recent Bauer-9 well (which
appraised the North West extent of the field) hence reserves could grow further. Nonetheless BPT highlighted that the Bauer North discovery, located 3.4km north of the original Bauer discovery well, appears to be a separate structure. Separately BPT confirmed that the recent Pennington-1 discovery could exceed 2mmmbbls gross (which is over 4 times the pre-drill mean estimate). Relative to PEL 92 it would appear BPT is at an earlier stage on the creaming curve here, suggesting further scope for positive surprises.
6 8 10 12 14 16 18 1 2 3 4 5 6
Years into pilot program
0 1 2 3 4 5 6 7 8 9 10
Well Capex (LHS) IP rate (RHS)
Capex (U$m) Initial production (mmscf/day) 0 2 4 6 8 10 12 1 2 3 4 5 6
Years into pilot program Break-even gas price
(A$/GJ)
Break-even gas price require under US capex and IP assumptions
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6 December 2012 5
BPT‟s net production target of 9,000-10,000bopd from the Western Flank remains largely unchanged. Completion of the Hanson production facility in 4Q12, commissioning of the Bauer-to-Lycium pipeline in 1Q13 and completion of Bauer-2&4 as producers will result in further production increases in coming quarters. While trucking is being used in the interim, completion of the main 15,000bopd Lycium hub to Moomba line is all but complete (the same pipe-laying crew is expected to commenced construction of the Bauer-to-Lycium line this week).With production being limited by pipeline capacity (indeed the Bauer-1 flowed at an unconstrained free-flow rate of 15,000bopd alone) and further exploration success likely, BPT could look to install pumping to increase throughput capacity in the near future. In hindsight it appears the A$21m investment made in pipeline infrastructure was a fruitful one.
Fig 5 Bauer reserves continue to grow following successful appraisal results
Fig 6 The recent discoveries in PEL 91 are adding a new dimension to the creaming curve in the Western Flank
Source: BPT, Macquarie Research, December 2012 Source: BPT, Macquarie Research, December 2012
Manageable international exposure with material upside on offer
Despite the growing unconventional and Western Flank program in the Cooper, BPT continues to expand its international business with assets now in Egypt, Tanzania, Romania. PNG and NZ. Importantly, with only 10% of the FY13 budget devoted to these assets and high equity interests (which could present opportunities to farm-down exposures to manage costs), the capital obligations across these assets remain more than manageable. Given the early stage of activity we currently value these assets at only 7Acps in our BPT NAV. However these assets could potentially be worth as much as A$1.16/sh on an unrisked basis (albeit unlikely).
Egypt remains BPT‟s largest international exposure, with assets spanning exploration to production. At the North Shadwan concession production is expected to grow to 2,500bopd from the NS385 and NS377 fields as oil transportation transitions from third-party pipeline to trucking in FY13 and following completion of the NS385-1 development well (although this well has been recently side-tracked which could prolong completion). The Burtocal discovery (NS-384) will be developed via a monopod tied back to existing infrastructure and could potential come online in early CY15 at a rate of 7,500bopd (gross). BPT also expects to spud the Burtocal East exploration well mid-next year which will target the more productive (but deeper) Nubia sandstones.
0.8 2.0 3.5 4.5 6.7 10.0 0 2 4 6 8 10 12 Mean pre- drill Post discovery
21-Sep-11 31-Dec-11 1-Jul-12 5-Dec-12
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6 December 2012 6
In the Abu Sennan concession BPT has enjoyed a 67% exploration success rate (vs. 33% across the broader Western Desert). The 4 existing discoveries remain on extended production test. While the wells initially tested at 2,400bopd (and ~3mscf/day of gas), production testing has been constrained to 800bopd due to limits regarding associated gas flaring. The JV is currently drilling the first of 3 exploration wells in the currently drilling program. While the remaining program will take ~6 months, if the JV can reach critical mass regarding associated gas resources for a commercial gas development (assuming further exploration success), oil production could be materially higher. In the Mesha concession, operator Melrose Resources (now Petroceltic International (PCI LN, £0.07, Outperform, TP: £0.09)) spudded Mesha-1 in October with the well expected to reach target depth in early 2013. The well will test the flank of a large structure defining from the recent 2,900km 2D seismic program. BPT continues to guide towards >100mmbbl targets.
BPT continues to move through the first phase of the work program at the Lake Tanganyika South concession in Tanzania, following completion of a 2,080km 2D seismic program (increased from 1,800kms) in August this year. Processing is expected to be completed in 1Q13, however preliminary results suggests similar shallow lowside rollover structures that have been successfully exploited by Tullow 900km north at Lake Albert. Importantly these prospects could be drilled with deviated onshore wells, which should keep drilling costs down and allow BPT to potentially retain a 100% exposure. Separately BPT has also mapped potentially larger stacked targets in the centre of the lake. Drilling of these targets is likely to require a funding partner given the high costs associated with breaking down a larger rig and transporting it 900km inland. BPT continues to guide towards >200mmbbl targets.
In mid-September BPT farmed into a 30% interest in the Est Cobalcesu Block offshore Romania. The block was awarded in 2010 after a territorial dispute with neighbouring Ukraine and remains largely unexplored. The JV is currently reprocessing existing 3D seismic (which covers the entire block) ahead of drilling in the next 12 months. Again activity here remains at an early stage, however the JV is targeting similar Lower Pontian targets as the recent 3tcf Domino discovery made by ExxonMobil this year.
A busy work program ahead
With a A$350-450m capital program in place and up to 123 wells proposed this financial year (although the non-operated SACB/SWQ JV contributes 55 wells) and much of this activity yet to commence, there is likely to be a rich vein of news flow over the next 6 months. This will include further testing of unconventional potential of the Nappamerrri Trough, the ongoing STO-operated infill drilling program in the SACB JV, further Western Flank exploration and development activity, ongoing exploration and production testing in the Abu Sennan block and a wildcat exploration well in the Mesaha concession in Egypt and confirmation of prospects across the Lake Tanganyika concession in Tanzania following 2D seismic interpretation. While incremental success in the Western Flank is high margin and therefore will be meaningful to NAV (a 1mmbbl net discovery adds ~2Acps to our NAV on an unrisked basis), further de-risking of the vast unconventional