Oil & Gas: Producer / Explorer

Transcription

1 CVN.asx Speculative Buy Carnarvon Petroleum Ltd (CVN) Oil & Gas: Producer / Explorer CARNARVON PETROLEUM LTD (CVN) A Busy Few Months It has been a busy few months for the gas sector in Western Australia with a series of domestic and LNG focused asset and corporate transactions and the drilling or planned drilling of a number of very high-profile wells. CVN will play its part in this developing landscape with the imminent drilling of the Phoenix South-3 well. On the M&A front, we have seen a number of deals targeting both the current demand for gas onshore WA from the mining sector and larger players starting to position themselves offshore for the next wave of LNG contracting (mid next decade). Key News flow overview and implications for CVN We review recent news flow related to CVN and WA Gas. CVN has announced that the GSF Development Driller-1 semi-submersible drilling rig has commenced the final leg of its journey to drill the Phoenix South-3 well (CVN 20%). After a minor (towing) delay the rig is now expected to be on location in late March, with the well drilled in April. AWE has recommended a takeover bid from Mitsui valuing the Company at circa $600m, leaving CVN as potentially the largest independent holder of uncontracted gas in WA (subject to appraisal). WPL has acquired a further stake in the Scarborough Gas Field, kicking off the start of deal activity in preparation for the next wave of LNG contracting. Western Gas acquires Equus from Hess, a potential competitive source of gas for the domestic market, but more likely we believe to be tied into an existing LNG project. Since the publication of our research note Mining for Gas in the Bedout Sub-basin (12 Apr 2017) (we outlined the strong argument for a gas pipeline to be built connecting WA to the Eastern States), it has been discussed widely in the press and received the strong support of a former Premier of WA, culminating in the Federal government commissioning GHD and ACIL Allen to carry out a pre-feasibility study on a transcontinental pipeline. The study is due to be completed in March If it was built it would obviously deepen the available market for upstream operators with uncontracted gas (who no longer would have to rely on the relatively small WA domestic market). Finally, Australia and Timor-Leste have signed a new Maritime Boundary Treaty. CVN s Buffalo Project (CVN 100%, WA-523-P) has also been affected by the boundary change. The Buffalo oil field will now fall within Timor-Leste s exclusive jurisdiction. Given its relative greater importance to Timor-Leste (compared to Australia) we would expect CVN to receive significant local support to pursue its exploitation. Investment View A Top Pick for Speculative Buy The imminent appraisal of Phoenix South and the drilling of Dorado-1 could result in CVN being one of the better performers in the oil sector in CVN s potential exposure to a recovering oil price is also possibly underappreciated, with Phoenix South potentially having a very high liquids content. Post the acquisition of AWE, a successful appraisal of Phoenix- South will also likely attract takeover interest, with CVN post appraisal success being one of the largest independent holders of of uncontracted gas in Western Australia. We rate CVN a Speculative Buy based on this combination of an attractive valuation (low EV/boe), newsflow, (unrecognised) oil price leverage and takeover appeal. Share Price: 12mth Price Target: Brief Business Description: Oil and gas explorer with assets in Australia 23 Mar 2018 $0.13 $0.25 Hartleys Brief Investment Conclusion Carnarvon Petroleum (CVN) is a conventional oil & gas explorer with key assets off-shore north-west Australia. The company and its JV partner(s) have drilled 4 out of 4 successful E&A wells in the Greater Phoenix area (CVN 20% interest). Chairman & CEO: Adrian Cook Peter Leonhardt Substantial Shareholders: None CEO Chairman Company Address: Level 2, 76 Kings Park Road, Perth, WA Valuation: Issued Capital: m - fully diluted m Market Cap: $133.8m - fully diluted $134.0m Current Debt Current Cash $0.0m $38.6m EV $95.3m Valuation Summary $m $ps Discovered Exploration Thai Royalty Stream Cash, less 1-yr spend Sub total Source: Hartleys Research A$ M Authors: Apr-17 Aiden Bradley Carnarvon Petroleum Aug-17 Industrials & Energy Analyst Nov-17 Ph: E: aiden.bradley@hartleys.com.au Mar-18 Volume - RHS Source: IRESS CVN Shareprice - LHS Sector (S&P/ASX 200 Energy) - LHS Hartleys Limited ABN (AFSL ) 141 Page St Georges 1 of 19 Terrace, Perth, Western Australia, 6000 Hartleys does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision. Further information concerning Hartleys regulatory disclosures can be found on Hartleys website

2 SUMMARY MODEL Carnarvon Petroleum Share Price CVN.asx CVN $0.13 Speculative Buy Key Market Information Directors Share Price $0.13 Peter Leonhardt Chairman Market Capitalisation $134m Adrian Cook Managing Director Current Cash est. (ex-royalty) $39m Bill Foster Non-executive Director Issued Capital m Dr Peter Moore Non-executive Director ITM options 0.0m Options 1.0m Issued Capital (fully diluted ITM options) m Substantial Shareholders Issued Capital (fully diluted all options) m EV $95.3m No substantial shareholders 12Mth Price Target $0.25 Investment Summary Carnarvon Petroleum ( CVN) is a conventional oil & gas Projects Project Operator CVN Interest explorer w ith key assets off-shore north-w est Australia. The company and its JV partner(s) have drilled 4 out of 4 successful E&A w ells in the Greater Phoenix area (CVN WA-435-P Greater Phoenix Quadrant Energy 20% 20% interest). The discovered resource now exceeds WA-437-P Greater Phoenix Quadrant Energy 20% economic threshold levels (subject to South Phoenix WA-436-P Greater Phoenix Quadrant Energy 30% testing). Very large follow up targets such as Dorado-1 WA-438-P Greater Phoenix Quadrant Energy 30% could add considerably to scale of the development. WA-521-P Greater Phoenix CVN 100% WA-523-P Buffalo CVN 100% WA-524-P Maracas CVN 100% Expected News flow WA-155-P(1) Outtrim East CVN 28.5% EP-490 Cerberus CVN 100% Apr-18 Phoenix South-3 w ell EP-491 Cerberus CVN 100% May-18 Dorado-1 w ell EP-475 Cerberus CVN 100% 1H18 Labyrinth Farm Out commenced February TP/27 Cerberus CVN 100% Mid 2018 Condor Farm Out commencing AC/P62 Condor CVN 100% 2018 Farm Out Outtrim (post Sw ell-1 result) EP-497 Santa Cruz CVN 100% Quarterly Cash Flow FY17 FY18 3Q 4Q 1Q 2Q Cash (Beginning) A$ m Valuation Summary Operating Cash flow A$ m Ac/share Exploration / Development Phoenix/South Phoenix/Roc Liquids Corporate overheads Phoenix/South Phoenix/Roc Gas Other Other discovered Exploration Cash (End) Farm Outs Post Asset Sale Cont. Payments Thai Royalty Stream Cash, less 1-yr spend Sub-total Analyst: Aiden Bradley Phone: Last Updated: 23/03/2018 Sources: IRESS, Company Information, Hartleys Research Page 2 of 19

3 HIGHLIGHTS It has been a busy few months for the gas sector in Western Australia with a series of domestic and LNG focused asset and corporate transactions and the drilling or planned drilling of a number of very high-profile wells. CVN will play its part in this developing landscape with the imminent drilling of the Phoenix South-3 well. On the M&A front, we have seen a number of deals targeting both the current demand for gas onshore WA from the mining sector and larger players starting to position themselves offshore for the next wave of LNG contracting (mid next decade). 1: AWE has recommended a takeover bid from Mitsui valuing the Company at circa $600m. Fig. 1: AWE bid premium Source: AWE AWE s key asset is the Waitsia dry gas field in the Perth Basin (AWE 50%). Waitsia s 2P reserves are currently 820PJ (Gross). Fig. 2: AWE 2P Reserves Source: AWE Page 3 of 19

4 The Mitsui bid valued AWE s 2P reserves at circa A$8/boe, with almost 80% of its 2P reserves undeveloped. Fig. 3: EV/2P Multiples vs % of 2P Developed Source: Grant Thorton Implications for CVN: If Phoenix South-3 comes in as expected, the total net discovered resource (including Roc) for CVN would be close to 40mmboe. While this resource would initially be 2C and obviously all undeveloped, even assuming a A$4/boe multiple, would imply a valuation of A$160m or 15.5c per share (19c including net cash). Fig. 4: Phoenix South-3 and Dorado resource potential Source: CVN 2: Woodside (WPL) has acquired a further stake in the Scarborough Gas Field. Woodside Petroleum in February acquired a further 50% in the Scarborough Gas field (WA-1-R) from Exxon Mobil. Woodside now with 75% (BHHP 25%) has assumed operatorship. WPL is proposing to develop the Scarborough resource through 12 subsea, high-rate gas wells tied back to a semi-submersible platform moored in 900m of water. The 7.3 Tcf (100%) of dry gas (2C) is expected to be piped circa 400km to the Woodside operated Pluto LNG facility. Page 4 of 19

5 The project is expected to cost US$ bn (100%) in total (Upstream: US$6.0bn Downstream: US$2.5 $3.7bn). These estimates include a 25% contingency with prefinal investment decision activities expected to cost approximately US$0.5 billion. Fig. 5: Scarborough Upstream Concept Schematic Source: Woodside The onshore development concept is a brownfield expansion of the existing Woodside operated Pluto LNG facility. Studies have commenced on a potential Pluto NWS Interconnector, intended to unlock incremental value for both Pluto LNG and the North West Shelf Project. Feasibility studies on a 0.7 to 3.3mtpa second LNG train at Pluto were concluded in Woodside, is the operator of Pluto, with a 90% interest, other current partners are Tokyo Gas and Kansai Electric with 5% each. This deal we expect is Woodside positioning itself for the next wave of LNG contracting (with Japan), with the first deals likely to be signed early next decade for first delivery from 2025 (when existing contracts start to expire). Fig. 6: Japanese LNG demand versus contracted volume Source: Platts Analytics Eclipse Energy, Japan s Ministry of Finance Page 5 of 19

6 In the next wave of LNG contracting we expect WA s LNG operators to pursue the cheaper option of brownfield expansions, especially given the spare capacity that will exist at existing facilities from Fig. 7: LNG Plant Spare Capacity as plants come off plateau production Source: Wood Mackenzie We expect the Woodside Scarborough deals not to be the last as operators jostle for competitive position and to re-arrange the current misalignments between the various downstream and upstream stakeholders. Woodside is also proposing piping Browse gas to the North West Shelf (NWS). It is therefore feasible that it seeks further deals that more closely align Scarborough to Pluto and Browse to NWS upstream and downstream partners. At the moment the Scarborough JV is owned by WPL 75% and BHPP 25%, while the Pluto plant is WPL 90% and Tokyo Gas and Kansai Electric with 5% each. BHP has the option to acquire an additional 10% interest in Scarborough up until December 31, Similarly, Woodside s participating interest in the Browse resources is 30.6%, with Shell owning 27%, BP 17.33%. Japan Australia LNG (MIMI Browse) 14.40%, and PetroChina a 10.67% stake. The NWS JV in comparison is Woodside (16.67%), BHP (16.67%), BP (16.67%), Chevron (16.67%), MIMI (16.67%) and Shell (16.67%). So, one obvious deal would be for BHP to swap its stake in the NWS with Woodside for a share in Pluto. Implications for CVN: LNG export projects in WA are required (if economically viable) to sell 15% of their reserves into the domestic market. Page 6 of 19

7 Fig. 8: WA Domestic Gas Policy long-term contractual arrangements with WA Government Source: Source: DJTSI Western Australian Domestic Gas Policy Implementation Update, 12 September, circulated to the WA Gas Consultative Forum. Reserves estimates and LNG facility capacity figures are sourced from Wood Mackenzie. a Indicative commitment based on annual LNG production. Currently, there is no domestic gas production infrastructure in place. b Excludes domestic gas to be supplied by the North West Shelf under contracts struck prior to their 2015 agreement and any third-party tolling. Therefore, the timing and rate of LNG developments has a major bearing on available domestic supply. Fig. 9: Indicative Gas Availability and Market Outlook (TJ/day), Source: DJTSI Western Australian Domestic Gas Policy Implementation Update, 12 September, circulated to the WA Gas Consultative Forum. With average contract prices in WA impacted by the periods when domestic supply from LNG projects is available (lower prices) and not (higher prices required for other non-subsidised sources of gas). As outlined earlier we have entered a period when available LNG project supply has already been contracted, so any customers requiring gas in the next 6-8 years will need to source it from non-lng projects. A potential window of opportunity for domestic producers with uncontracted gas, which explains the broad interest from various parties in acquiring AWE. CVN with success at Phoenix South-3 will along with Western Gas now be one of only two independent operators with significant proven uncontracted gas in WA. Page 7 of 19

8 Fig. 10: Western Australian domestic gas processing capacity, consumption and prices Source: APPEA, BREE, GoWA, SKM 3: Western Gas acquires Equus from Hess We have long felt that a successful appraisal of Phoenix-South will likely attract takeover interest in CVN. As we highlighted in our note Mining for Gas in the Bedout Sub-basin (12 April 2017), post its drilling success to date, CVN along with AWE (AWE.asx) was one of two largest independent owners of uncontracted gas in Western Australia. Having retained the rights to market the gas independently, this would make them an appealing target for a number of large domestic gas users. Add in a continued medium-term gas shortage in WA and a very high liquids content in the Bedout Sub-basin, the takeover potential is compelling (especially for a mid to large mining operation). Post the takeover of AWE, CVN looked like being the only independent left with potential access to material volumes of commercial gas. A new company, Western Gas, has however acquired the Equus Gas Field from Hess Corporation (HES.nyse). The Equus project comprising 11 gas and condensate fields in the Carnarvon Basin, about 200 kilometres north-west of Onslow in Western Australia. These fields contain an independently certified resource of more than two trillion cubic feet (2 Tcf) of gas and 42 million barrels of condensate. However, we believe that the four largest fields (70% of reserves) would be of sufficient size to supply an existing gas plant, substantially improving the potential economics of any proposed development. This downsized (versus prior Hess proposals) could produce between 150 million and 250 million cubic feet of gas a day from the offshore fields, with condensates processed at a production ship, while gas would be piped about 220 kilometres to shore through a new pipeline costing about $US500 million. Implications for CVN: While we feel that Equus is an alternative for domestic gas supply, in terms of timing it sits behind Waitsia in the queue to market and likely behind Phoenix South assuming PS-3 is a success (due to the high liquids content and Page 8 of 19

9 cheaper development cost). As a result, given its relative proximity to Woodside Petroleum's Scarborough gas field, we feel that Equus is still likely to be developed as part of any Scarborough to Pluto LNG development (it may even be the domestic component of that project). Fig. 11: Equus Gas Project Source: Western Gas 4: Gas Pipe to the East In our research note Mining for Gas in the Bedout Sub-basin (12 Apr 2017) we outlined the strong case for a gas pipeline to be built connecting the undeveloped gas resources in WA to the consumer demand in the Eastern States. Since then the case for just such a pipeline has been widely reported in the press, has received the strong support of a former Premier of WA, culminating in the Federal government commissioning GHD and ACIL Allen to carry out a pre-feasibility study on a transcontinental pipeline. The study is due to be completed in March Our own version of a West-East pipeline would seem to be a win-win for all concerned: WA State Government would benefit from increased gas development activity and a boost to WA Economic activity through increased availability of gas. WA gas consumers do not have to lose out, in fact they would likely gain. They would be able to bid for gas at East Coast prices minus the pipeline tariff. As part of building the pipeline, offshore retention lease terms would have to be tightened so that operators could not blame a lack of commercial opportunity for not developing gas fields. Use it or lose it would have to be strictly enforced. WA gas operators those that simply want to hold the gas in the ground waiting for the once every years Japanese fed LNG contracting boom may be disappointed. The pipeline would open up East Coast gas markets (in addition to WA domestic and LNG export) as another viable commercial alternative. We have assumed a well head price of $5/GJ in our modelling, which is pretty close to the LNG netback price assuming a US$55-60/bbl oil price. So not the super returns expected Page 9 of 19

10 to be achieved during the once every two decades Japanese LNG buying frenzy (they can still be captured at those times) but a reasonable return all the same. Federal Government would help solve the East Coast gas supply crisis and generate an adequate return on the pipeline through increased offshore production and related taxes and a boost to National GDP from increased gas availability for industry. An additional benefit is that it would bring forward the development of WA s offshore gas reserves. A reserve that may be under threat from rapid developments in renewable energy technology, and as a result in years facing the possibility that the market for such gas may have diminished or disappeared, and it becomes a stranded resource (some in the oil and gas industry may view this as unlikely but given the pace of developments in the renewable sector, it has to be a consideration). Implications for CVN: The argument in favour of a West-East pipeline does seem quite compelling. If it was built it would obviously deepen the available market for upstream operators with uncontracted gas (who no longer would have to rely on the relatively small WA domestic market). In the meantime, any major gas consumers wanting to make sure they are not disadvantaged by the continued gas shortages in WA and now the East Coast Australia, have no choice but to either compete for what 3 rd party gas is available in the market or be more proactive and go now and acquire their own upstream production. This stark choice facing gas users brings us back to CVN and underpins our positive outlook for the company. Fig. 12: Delivered cost of WA offshore gas to the East Coast Source: Hartleys Research 5: Australian and Timor-Leste sign a new Maritime Boundary Treaty. The Australian and Timor-Leste Governments have signed a new Maritime Boundary Treaty. While the treaty settles the sea border dispute, the disagreement over how to share the potentially lucrative Sunrise gas field is ongoing. For the Sunrise gas field, Australia has offered to share profits in Timor Leste's favour, but with the oil and gas processed in Darwin. Timor Leste wants a split but with processing done in its own country to encourage the growth of a domestic processing industry. Page 10 of 19

11 Implications for CVN: CVN s Buffalo Project (CVN 100%, WA-523-P) has also been affected by the boundary change. The Buffalo oil field will now fall within Timor-Leste s exclusive jurisdiction (refer Figure 13) while a portion of WA-523-P will remain within Australia s exclusive jurisdiction. Fig. 13: Maritime Boundary Change relative to WA-523-P Source: Hartleys Research The signing of the new Maritime Boundary Treaty will require CVN to secure a PSC from Timor-Leste. Given its relative greater importance to Timor-Leste (compared to Australia) we would expect CVN to receive significant local support to pursue its exploitation. CVN believes that the Buffalo Field contains 31mmbo recoverable (RISC audited 2C resource), sweeping oil from the unproduced structural attics. Any future development would likely cost just US$150m, replicating previous facilities, with operating costs expected to be US$80m to $100m p.a. based on 4-year production life. The utilisation of modern technology has enabled the identification of the unproduced oil in this high-quality reservoir, where in the original development the initial production from two wells was around 50,000 bopd. The original Buffalo Project was still producing 4,000 bopd when production ceased. The recent recovery in oil prices has obviously also provided support for any future commercial redevelopment of this project. Page 11 of 19

12 Fig. 14: Buffalo Structural Attics Source: Hartleys Research 6: Last and most importantly, the GSF Development Driller-1 rig is on its way. CVN has announced that the GSF Development Driller-1 semi-submersible drilling rig has commenced the final leg of its journey to drill the Phoenix South-3 well (CVN 20%). After a minor (towing) delay the rig is now expected to be on location in late March, with the well drilled in April. The well is expected to take 90 days to a target depth of 5,156m, 65 days to the top of the reservoir. essel:gsf%20development%20driller%20i Phoenix South-3 well is only circa 560 metres from the Phoenix South-2 gas and condensate discovery and will target an estimated gross mean recoverable prospective resource of 489 Bscf of gas and 57 million barrels of associated condensate. The Phoenix South-3 well will be followed up by the drilling of the Dorado prospect in May. The Jack-up rig contract (ENSCO 107) for Dorado-1 (CVN 20%) well has also been signed with drilling expected to commence in May 2018 (45 days to target depth of 4,400m, 35 days to the top of the primary reservoir). The Company also seems to be adequately funded for this programme with CVN recently releasing its December 2017 Quarterly report, ending the year with $48.49m of net cash (versus $50m prior). Estimated cash outflow for the current quarter is $9.86m. Page 12 of 19

13 Fig. 15: Phoenix South-3 and Dorado resource potential Fig. 16: CVN Asset Portfolio Source: CVN Source: CVN Page 13 of 19

14 A$m Hartleys Limited Carnarvon Petroleum Ltd (CVN) 23 March 2018 INVESTMENT VIEW A TOP PICK FOR 2018 The delay in drilling the Dorado-1 well (from 2H17 to 1H18) impacted the price performance of CVN in However, the appraisal of Phoenix South and confirmed drilling of Dorado-1 should result in CVN being one of the better performers in the oil sector in CVN s potential exposure to a recovering oil price is also possibly underappreciated. Phoenix South looks likely to have a very high liquids content. Discoveries to date in the Roebuck Sub-Basin (especially Phoenix South Caley) have contained a very high liquids content and is a potential game changer in terms of the economics of any potential development in the sub-basin and a huge differentiator in comparison to the investment returns from a dry gas field such as the developed (similarly sized) Reindeer Field. Fig. 17: Liquids content Phoenix/South Phoenix and Roc Source: Hartleys Research In fact, the liquids component could be so high that the liquids cash flow would come close to paying for the whole development (the gas gets produced for free!). Fig. 18: NPV10 of Liquids only at various oil prices (P/PS/Roc development) $ $50.00 $0.00 ($50.00) ($100.00) ($150.00) US$/bbl Source: Hartleys Research We continue to believe as outlined before that the market has applied a discount to CVN due to the perception it is a dry gas play and that any commercialisation will likely Page 14 of 19

15 be hostage to Quadrant s broader portfolio requirements. We believe the risk from the latter is also overstated and these misconceptions make for an appealing investment opportunity. Quadrant requires the gas to be developed: CVN is indeed a smallish minority partner (20%) in a JV with the dominant (non-lng) gas producer in WA, Quadrant Energy. There may be concerns that CVN will become hostage to Quadrant s broader development plans and the Bedout Sub-basin discoveries are pushed down the development queue. However, a number of key projects underpinning Quadrant s existing reserves and supply contracts are set to deplete middle of next decade and its recent exploration efforts have had mixed success. In fact, the Bedout Sub-basin has the potential to be the foundation asset* for Quadrant s ongoing supply efforts next decade (*requires proving up of Caley resource in South Phoenix and/or Dorado discovery to place it top of the development queue). Liquids component is the game changer: In the following chart, we highlight the implied acquisition gas price to a potential acquirer at various cash payments to CVN for its stake in Roc/Phoenix and South Phoenix only (assumes liquids content as before covers cost of development i.e. NPV10 close to zero at a US$60/bbl long run oil price). The implied price of the gas would obviously fall or rise if oil prices are above or below US$60/bbl respectively, and/or the actual cost of funding the development is below or above the standardised 10% we used in our modelling. Fig. 19: NPV10 of CVN s free gas at various transaction prices Source: Hartleys Research Most mid to large gas users (or potential users as gas has not been easily accessible) in WA would jump over backwards to secure potentially 200bcf of gas at a price sub $3/GJ. However, that is exactly what you get in CVN if you pay <$250m or less (subject to Phoenix South-3 proving the recoverable gas and condensate as outlined in Figures 4 and 17). In our valuation of CVN we assume acquisition interest at the attractive implied price of $1.50/GJ level, this would likely rise post a successful appraisal with South Phoenix-3. CVN s gas is also ideally located to supply this low-cost gas to existing customers at Karratha or Port Headland or supply new customers as far north as Broome. Page 15 of 19

16 Fig. 20: Commercialization options Source: CVN This valuation alone excludes other exploration potential in the Bedout Sub-basin (including the large Dorado prospect) and play fairway extension into the Rowley Subbasin (which we remain more sceptical on). Beyond the Roebuck Basin, CVN has used its experience here to build a portfolio of interesting potential farm out opportunities. While a gas consumer may not be interested in the exploration portfolio, it is potential additional value we believe is also not captured in the current CVN share price. Fig. 21: Valuation Summary Source: Hartleys Research CVN Valuation Asset Type W.I. Gross Net NPV/boe Net Risked Value mmboe mmboe US$/bbl A$m A$/share Phoenix South / Phoenix / Roc Liquids 20% Phoenix South / Phoenix / Roc Gas 20% Other discovered Exploration Farm outs (Maracas, Buffalo, Cerberus, WA-521-P (all 100%)) Post Asset Sale Contingency Payments Thai Royalty Stream Cash, less 1-yr spend Page 16 of 19

17 Conclusion To date we believe the market continues to value CVN as a dry gas play, with commercialisation hostage to Quadrant s broader portfolio requirements. This is incorrect and makes for an appealing investment opportunity. In our valuation of 25c per share for CVN we make the following assumption; Successful appraisal of Phoenix South with the PS-3 well. Larger gas users recognise the obvious potential in the Roc/Phoenix/Phoenix South discovery through CVN retaining the marketing rights to the gas and the high liquids content subsidising the full field development (at circa US$60/bbl oil). Gas user acquires CVN s 20% stake in these discoveries for an implied gas price (to them) of A$1.50/GJ. Implies a cash payment to CVN of $122m. We additionally include very little value for the large identified prospective resource beyond the Roc/Phoenix and Phoenix South discoveries. We value this net 164mmboe in the Bedout Sub-basin (now a proven oil and gas play with prospects such as Dorado on trend and in close proximity to a large discovered resource) at just $88m. Finally, we also include no value for potential farm outs of Maraca, Buffalo, Cerberus and WA-521-P, all have some merit and are currently 100% leased by CVN. Page 17 of 19

18 Fig. 22: Key assumptions and risks for valuation Assumption Commercial development in the Bedout Sub-basin Risk of not realising assumption Downside risk to valuation if assumption is incorrect Comment Low High Post the success of Roc and initial results from Phoenix South we now view a commercial gas development in the Bedout Sub-basin as highly likely. As a result, we expect there to be significant interest in CVN s potential 20% stake in the project from a range of large gas users. In our valuation, we currently assume a conservative $122m valuation based on the likely transaction price a gas user would be willing to pay. Successful appraisal of Phoenix South Upside beyond Roc and Phoenix South Low Moderate CVN failed to fully test the Phoenix South Caley reservoir with Phoenix South-2. As a result, a further well (PS-3) will be required to firm up the resource. While there is some risk associated with every well, the key risk here is that the prospective resource is not as large as currently predicted by the company. It could in fact turn out to be larger, so there is upside risk as well. Medium Low We have included very little value for upside beyond what we see as the core Roc / Phoenix / Phoenix South development hub. So, large targets such as Dorado if they fail would individually have limited impact on our valuation, while offering significant upside in a success case. We have included zero value for potential farm outs of acreage beyond the Bedout Subbasin, although we view these positions as each having merit. Cash funding adequate Medium Moderate Offshore exploration remains an expensive business even in this currently deflated oil environment. Wells in the Roebuck Basin for CVN and its JV partner can cost between US$50-80m gross. CVN had $48.5m in cash at the end of the last quarter, however this could fall to circa $10m by year end (depending on the drilling programme and insurance payment). Securing sufficient capital to continue to participate in the JV is a risk but given the attractiveness of the acreage it is the cost of this capital and not whether CVN can access it that is the key risk. Conclusion Source: Hartleys Research We believe that post the drilling results at Roc and Phoenix South, there is likely to be a commercial development in the Bedout Sub-basin. Future testing at Phoenix South and exploration at Dorado will determine the size, timing and value of the development. CVN remains to a certain degree hostage to Quadrants plans for the gas, but we believe it is towards the top of Quadrants queue to develop. Given the continued gas shortage in WA, we expect a major gas user to be interested in acquiring CVN s equity interest in the development (when it is adequately de-risked). This will remove any concerns about how CVN can fund a development. The key risks for CVN (like most junior oil & gas companies) is a combination of exploration success and performance of the production assets (if any). Although some disappointments can be short term and are only a timing issue, other disappointments can be materially value destructive and can sometimes overhang stocks for a long period of time. Such disappointments can be very difficult to predict and share price reactions can be severe and immediate upon disclosure by the company. High financial leverage would add to the problem. Investing in explorers is very risky given the value of the company (exploration value) in essence assumes that the market will recognise a portion of potential value before the results of an exploration program are known, conscious that the ultimate chance of success is low. Page 18 of 19

19 HARTLEYS CORPORATE DIRECTORY Research Trent Barnett Head of Research Mike Millikan Resources Analyst John Macdonald Resources Analyst Paul Howard Resources Analyst Aiden Bradley Research Analyst Oliver Stevens Research Analyst Michael Scantlebury Junior Analyst Janine Bell Research Assistant Corporate Finance Dale Bryan Director & Head of Corp Fin. Richard Simpson Director Ben Crossing Director Ben Wale Associate Director Stephen Kite Associate Director Scott Weir Associate Director Scott Stephens Associate Director Rhys Simpson Manager Registered Office Level 6, 141 St Georges TcePostal Address: PerthWA 6000 GPO Box 2777 Australia Perth WA 6001 PH: FX: info@hartleys.com.au Note: personal addresses of company employees are structured in the following manner:firstname.lastname@hartleys.com.au Hartleys Recommendation Categories Buy Accumulate Neutral Reduce / Take profits Sell No Rating Speculative Buy Share price appreciation anticipated. Share price appreciation anticipated but the risk/reward is not as attractive as a Buy. Alternatively, for the share price to rise it may be contingent on the outcome of an uncertain or distant event. Analyst will often indicate a price level at which it may become a Buy. Take no action. Upside & downside risk/reward is evenly balanced. It is anticipated to be unlikely that there will be gains over the investment time horizon but there is a possibility of some price weakness over that period. Significant price depreciation anticipated. No recommendation. Share price could be volatile. While it is anticipated that, on a risk/reward basis, an investment is attractive, there is at least one identifiable risk that has a meaningful possibility of occurring, which, if it did occur, could lead to significant share price reduction. Consequently, the investment is considered high risk. Institutional Sales Carrick Ryan Justin Stewart Simon van den Berg Digby Gilmour Veronika Tkacova Wealth Management Nicola Bond Bradley Booth Adrian Brant Nathan Bray Sven Burrell Simon Casey Tony Chien Tim Cottee David Cross Nicholas Draper John Featherby Ben Fleay James Gatti John Goodlad Andrew Gribble David Hainsworth Murray Jacob Gavin Lehmann Shane Lehmann Steven Loxley Andrew Macnaughtan Scott Metcalf David Michael Jamie Moullin Chris Munro Michael Munro Ian Parker Matthew Parker Charlie Ransom (CEO) Mark Sandford David Smyth Greg Soudure Sonya Soudure Dirk Vanderstruyf Samuel Williams Jayme Walsh Disclaimer/Disclosure The author of this publication, Hartleys Limited ABN ( Hartleys ), its Directors and their Associates from time to time may hold shares in the security/securities mentioned in this Research document and therefore may benefit from any increase in the price of those securities. Hartleys and its Advisers may earn brokerage, fees, commissions, other benefits or advantages as a result of a transaction arising from any advice mentioned in publications to clients. Any financial product advice contained in this document is unsolicited general information only. Do not act on this advice without first consulting your investment adviser to determine whether the advice is appropriate for your investment objectives, financial situation and particular needs. Hartleys believes that any information or advice (including any financial product advice) contained in this document is accurate when issued. Hartleys however, does not warrant its accuracy or reliability. Hartleys, its officers, agents and employees exclude all liability whatsoever, in negligence or otherwise, for any loss or damage relating to this document to the full extent permitted by law. Page 19 of 19