Panoro Energy ASA

John Hamilton - CEO Qazi Qadeer - CFO Richard Morton - Technical Director

Teodor Nilsen - Swedbank Henrik Madsen - Arctic Securities

Thank you for the introduction. Good morning everyone.

Thanks for participating in Panoro's third quarter 2016 conference call. My name is John Hamilton, Chief Executive Officer of Panoro Energy ASA.

And on the call with me this morning are Qazi Qadeer, Panoro's Chief Financial Officer; and Richard Morton, our Technical Director. Following a brief introduction, Richard will take through an update on the progress of our assets and then we'll turn over to Qazi, who will review our financial results for the third quarter, after which we can turn over to some Q&A.

As a reminder, today’s conference call contains certain statements that are or may be deemed to be forward-looking statements, which include all statements other than statements of historical facts. Forward-looking statements involve making certain assumptions based on the Company’s experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate under the circumstances.

Although we believe that the expectations reflected in these forward-looking statements are reasonable, actual events or results may differ materially from those projected or implied in such forward-looking statements due to known or unknown risks, uncertainties and other factors. For your reference our results announcement was released this morning, and a copy of the press release and our third quarter 2016 report are available on our Web site at www.panoroenergy.com.

I'd like to say a few words in beginning before asking Richard to take us through an operational update. Aje as you all know has had some mechanical issues which have temporarily impacted the initial production in the field.

These issues are of course incredibly frustrating for those of us at Panoro, for general potential partners, for our other stakeholders and of course for our shareholders. We have however made progress in addressing the issues with the gas lift almost operational and the intermediation of Aje-5 being planned.

I'd like to note, the cost of repairing the compression system that we've referred to are not for the account of the joint venture partners. The Aje-5 intervention program is being developed and we anticipate the cost at around $1 million to $2 million net to Panoro.

The first Aje crude sale went very well operationally and financially with no hiccups and with the proceeds received perfectly on time. We expect to sell another cargo probably in the end of December.

The Aje JV has made efforts to reduce the operating costs in the field and have had material success in this; and we look at ways of further continuing to reduce the operating cost in the field. At Dussafu, we continue planning for exploration and development activities, recent corporate announcements by our partner and operator Harvest are noted by Panoro, and we expect clarity on their situation and how it impacts Dussafu during the fourth quarter.

Finally, we continue to evaluate certain and several opportunities to grow our business in West Africa. I'll turn it over to Richard who'll describe activity on our assets beginning with updating you on the developments at the Aje field offshore Nigeria.

Thank you, John, and good morning everybody. Production from the Aje field continued in the quarter, and we're pleased to report that the first lifting of Aje crude was completed on the 15th of September, and proceeds from the sale of the crude were received by Panoro in our Norwegian bank account in October.

A total of 74,000 barrels of oil net to Panoro were lifted and sold to Glencore at a slight premium to Brent pricing at the time of the lifting. Panoro’s net share of proceeds from this sale before payment of royalty and taxes was $3.5 million.

This represents the first cash inflow from the Aje field and establishes Panoro as a production company. Production from Aje during the quarter continued to be limited by the performance of the Aje-5 well which, as we reported last quarter, requires subsurface intervention to remedy a mechanical problem.

In addition, availability of gas lift on the FPSO to optimize production rates was limited, and some modifications and repair to components of the system have been necessary. The gas lift system engineering work has been delayed, but is now well underway.

And the system is planned to be operational again in the very near future. The delay in using the gas lift system has impacted production during the third quarter, and will also affect the production expected in Q4.

The Aje-4 well, meanwhile, produced throughout the quarter and continues to perform better than anticipated in our earlier modeling. On average the Aje field produced at just over 600 barrels of oil per day net to Panoro during the quarter.

Preparations for the Aje-5 intervention program has started with procurement of long lead items and rig contracting. The intervention is scheduled to be undertaken at the end of 2016 and is designed to remedy mechanical issues with the completion of the well.

It is expected that the Aje field will be producing regularly at our earlier stated target rates of 7,000 to 9,000 barrels of oil per day once the Aje-5 well is successfully brought back online, and we anticipate that to be in early 2017. The Aje gas development project, which involves production and sale of gas and liquids from the 163 million barrel oil equivalent Turonian reservoir, is moving through the concept definition stage towards the final field development plan.

We expect to submit detailed plans for the project for approval during the first half of 2017. Regarding the exploration potential in OML 113, outside of the Aje field itself, Panoro have almost completed a perspective resource review with the reserves auditing company AGR TRACS International.

We will provide a summary of this report during Q4. Moving onto Gabon now.

At Dussafu, we note the recent press releases from our partner and operator, Harvest, in which they state they’ve received two proposals for the purchase of Dussafu. We’re in close dialogue with Harvest on the project and their possible sale.

We expect to be able to announce progress on this project with a plan for developing the existing resources, transaction or exploration plans in the coming months. I’ll now hand over to Qazi, our CFO, to take us through at quarterly financials.

Qazi?

Thanks, Richard and good morning everyone. I’m now going to discuss the third quarter results in comparison to the second quarter 2016.

It is customary to note here that the results published this morning and discussed on this call are unaudited. The Aje field started production in May 2016 and the actual commissioning of the field followed two month later.

As a result, the accounting for production of oil and gas assets, the recording of revenue and expenses of the associated operational cost is a third quarter event, and has been reflected in our numbers in the current quarter. EBITDA for the current quarter was negative $0.8 million compared to $1.2 million in the second quarter.

The EBITDA for the current quarter comprised of $3.5 million of revenue offset by $1.1 million of pre-commissioning operating costs, $2.4 million of post-commissioning operating costs, including royalty and $0.9 million of general corporate overhead. In comparison, the second quarter EBITDA of negative $1.2 million did not include any revenue and operating costs, and comprised of higher exploration related costs and general and administration expenses.

This is the first quarter where we've recognized revenue on sale of Aje crude. And as per our accounting policy, revenue is effectively recognized on lifting of crude when risks and rewards of ownership of goods have transferred to the buyer.

The realized sales price during the quarter was around $47 per barrel. The pricing mechanism for Aje crude has a high correlation to Brent.

In connection with the sales proceeds recognized during the quarter, the Company had $3.5 million trade receivables, which was collected in full in October after paying for tax and royalty of $0.5 million. Field operating costs per production barrel were $29.79 per barrel and $32.8 per barrel with royalty included.

Through a carry arrangement, under the OML 113 Joint Operations Agreement, the Company’s share of capital and operating expenditure is 16.255%, whereas the allocation of revenue to the Company is at 12.1913%. Based on the net barrels produced, which the Company is entitled to sell, Panoro’s operating costs per barrel equated to $39.72 per barrel and $43.73 per barrel with royalty included.

The revenue allocation of 12.1913% will increase to 16.255% once certain pre-defined financial thresholds are met under the JOA. The composition of operating cost is largely a fixed cost base with very little variable cost element.

Due to lower than expected average field production during the period the operating cost per barrel is high relative to our initial estimates, which had been based on 9,000 barrels of oil per day gross. On a normalized production range of 7,000 to 9,000 barrels of oil per day, expected after successful remediation work on Aje-5, the operating cost per barrel is expected to reduce to be in line with previous estimates.

In addition, operating costs have been reviewed aggressively at the JV level and material savings are expected to be achieved through cost cutting measures and price renegotiations with key suppliers. Such savings will be achieved in the forthcoming months.

Depreciation charge for the current quarter was $1.3 million in comparison to $26,000 in the previous quarter; the increase is due to DD&A charge on production from Aje field. The group has reported a net loss from continuing operations of $2.2 million in comparison to$1.3 million for the second quarter; the net loss is largely driven by Aje production accounting, in particular, the higher depreciation charge for the quarter.

Net loss for the period from discontinued operations was $293,000 for the current quarter compared to a loss of $20,000 for the previous quarter. The relinquishment of licenses in Brazil is now pending ANP approval, and there's active engagement with the operator Petrobras to close matters by end of this year.

Meanwhile, management is making best efforts to keep exit costs to a minimum. As mentioned in the previous quarters, the cost in Brazil is subject to periodic fluctuations and hence the higher loss in current quarter; the loss comprised of expenses or relinquishment related cash costs and historical tax charge in Brazil.

Moving now to the balance sheet as of September 30, I'm going to discuss the movements in comparison to the balance sheet as of June 30. On an overall basis, non-current assets amounted to $94.5 million at September 30, representing a net decline of $1.6 million compared to the second quarter.

This is due to $0.8 million investment in Nigeria and Gabon licenses, offset by $1.1 million expenses of pre-commissioning operating costs and $1.3 million of depreciation charge. Since commencement of commercial production from Aje field, the capitalized development costs have been straight to reflect that the depreciable costs of Aje Cenomanian oil field and non-depreciable cost based in the license.

Current assets, in total, amounted to $8 million as of September 30, compared to $8.3 million as at June 30; the current assets comprised of unsold crude oil inventories entitlement of $0.5 million; trade and other receivables of $4 million; and cash and cash equivalents of $3.5 million. The decline in current assets compared to previous quarter is a result of decline in cash and cash equivalents with investments in licenses and corporate expenses.

The decline in cash equivalents is partially offset by recognition of a trade receivable of $3.5 million on sale of crude oil during the quarter. Moving to the total equity, the amount was $95 million as of September 30, compared to $97.5 million as of the previous quarter.

The change is impacted by loss for the period. The non-current liabilities amounted to $6.2 million and remained largely unchanged from June 30.

These comprise of deferred tax and asset retirement obligation in relation to the Aje field. Minor reduction into the asset retirement obligation due to accretion of interests in line with account standards, whereas a minor reduction in the deferred tax liability is due to partial unwinding of the liability on commencement of production from the Aje field.

The last item in the balance sheet is the current liabilities, in total amounting to $1.3 million at September 30, having increased by $0.5 million in comparison to June 30. The increase is mainly due to recording of royalty and tax accrual on crude sale.

This concludes my review of our financials. And I will now turn back the call to our CEO, John Hamilton for closing remarks and open up for questions.

Thanks, Qazi. Before we open up for questions, I’d like reiterate management and the Board are committed to repositioning the Company for growth and future success, and to deliver shareholder value.

Operator, could you please open up for some questions now, please?

Just couple of question, one on operating cost. You mentioned that there were some pre-commencement costs in third quarter.

Is it fair to assume that OpEx going forward will be lower than $3.3 million you reported for third quarter?

Yes, that is correct Teodor. So $1.1 million was one-off charge, which was cost accumulated since start of first oil to the commencement of operation.

So that $1.1 million is not expected to repeat in the forthcoming quarters.

And then with regards to lifting of oil, you said that you expect to lift some oil, one more cargo in the fourth quarter. Is it likely that you actually will have two payments in fourth quarter, one in October, that’s the already quarter, and then another one in December?

At the current moment, we are planning another lifting; probably right at the end of December is the current window being discussed; it's not affirmed yet, that’s the intention. The payment terms that we have with the buyer, our standard for the industry are 30 days.

So it'll probably be similar to what we had in the third quarter, which is we might have a lifting during the quarter, payment in the subsequent one.

So, so this is production revenue in the fourth quarter approximately like in third quarter though, lift revenue?

Yes, that is correct. So, if there's a cargo lifting in the fourth quarter, we'll book the revenue and then the proceeds will follow, probably depending on when the 30 days are up from the date of sale.

Then finally on Dussafu. How would you view your own owner share in that license going forward, assuming that there actually will be some developments in the license oil in next couple of years?

Look, we've a good position in Dussafu. We have a third of a block.

Depending on the structure of Harvest sale, let's assume for the moment that they're successful in selling their stake in Dussafu. Depending on the structure of that transaction, we have the option of potentially selling down part of our stake in exchange for cash or in exchange for development or drill and carry.

So, we think that we've got quite a bit of running room within our current asset position there, and that would probably be our first protocol in terms of funding any future developments at Dussafu.

Just a quick question, if I may, on the Aje gas project versus the phase 2 Cenomanian project. You guys are discussing the progress towards an FID on the gas project this quarter.

But how does that relate or compare to those potential two secondary wells on the Cenomanian, which at least from my perspective, I've interpreted that's usually looking to come before the gas project. Is that something that has changed or are you still progressing that at the same time?

No, we're progressing both, obviously. I mean it's too early to comment on any of those two things, either phase 2 or there some sort of gas FID.

I think the point we're trying to make on the gas FID is that, final investment decision of course is when all of the joint venture partners decide that they're going to proceed with the project. But coming ahead of that is obviously a field development plan, a concept selection on what that development might look like.

And the comments we've made in today's report reflect the work that has been done towards that field development plan, which we expect to, work is underway on that now. And we expect to culminate that work in the first quarter of 2017.

But that does not equate to a final investment decision; that will take longer, clearly. And in the meantime, it’s phase 2 or drilling additional oil wells is always in the discussion.

So follow-up on that, if I may, then; a potential phase 2 drilling here. What is that contingent on now?

Is that pure oil price? You relative to stabilization of production from the first two wells and then potentially can be a 2017 type of decision or are we further on that usage?

I think that timeframe is right, Henrik. I think it’s the mixture of oil price partners’ desires, varying desires to do things.

We have five partners in the block; and obviously the performance of the wells. So, I don’t think it’s farther up in near 2017.

But it’s too early for us to say anything other than that in terms of that planning.

And the final question for me then follow-up on Teodor’s question on lifting. How many lifting should we assume, and then also, I guess, payments should be assume per quarter, assuming that production stabilizes?

It’s a really good question, Henrik. I think obviously it depends on two things.

One is the actual production coming up, how quickly does the boat fill-up and depending what the production levels are, that could be quite a different answer. The second issue is that we’re using Glencore at the moment.

Glencore often do what they call top up cargo. So they may be stopping off at Aje to pick-up a few hundred thousand barrels, the top up against the bigger cargo.

I think if you need to assume something for your modeling, it’s probably every three months, or maybe four times a year. However, that could vary a little bit again depending on operational parameters, like Glencore’s desire to pick-up some crude, which we have the ability to let them do in smaller quantities.

I have a few questions on the Aje production. You mentioned the current production is 600 barrels per day.

I wonder if -- you mentioned that Aje-4 is producing more than expected. Why this low production only 600 barrels per day when Aje is producing well?

The 600, this is Richard. The 600 number is the amount net to Panoro.

The gross number is more like 5,000 in average over the last quarter. So it's producing obviously less than targeted our 7,000 to 9,000 and the reason is Aje-5 has not been performing and is being shutting for a period during the quarter.

So once we get Aje-5 back we’ll be aiming towards the 7,000 to 9,000. But yes, the 600 is just net to Panoro, not the gross number.

You mentioned on the last quarter report that when gas lift was fully operational, you expected to produce 7,000 to 9,000 barrels before Aje-5 was in full production. Now you estimate this production level after Aje-5 is back on track?

The 7 to 9 number is a conservative number we're adopting at the moment. We haven't really changed the guidance, and we're linking the gas lift and the production from Aje-5 together.

Once we've got two wells going through the same manifold so there's some restrictions on total production we can produce from the field. We need to manage the reservoir carefully.

So those are the things we're bearing in mind when we're talking about the 7,000 to 9,000 target range. So I think it was possible that Aje-4 on its own could make 7,000 barrels a day with the gas lift when it was, if that was fixed, when we started the work.

But with the two wells producing, we have to balance production from both wells and keep within quiches for the field. So, that's where the 7,000 to 9,000 barrel number comes from.

So, it's a little bit conservative. We could be better.

But it's still just guidance, at the moment.

Is the Glencore a preferred off-taker from Aje?

Yes, at the moment, they've lifted up our first cargo. They did a -- we believe a very good job on it.

There were no operational hiccups from either our side or theirs; payment was received perfectly. We believe they sold the cargo quite well.

We received a slight premium to Brent, which for very first cargo with new crude and the first crude coming out of the subsurface, we feel was a pretty good result. So at the moment, they're in full position.

But clearly people have an interest in this crude. So, we're keeping our ears open in terms of other traders as well.

But at the moment, Glencore has done a good job for us.

And final question, now that Aje is on production, how do you concede the reserve based lending possibility?

Well, we always maintain dialogue with lending banks and of course trading companies as well often offer maybe not RDL, so to speak, but pre-payment style structures. I think the banking market is still quite weary of lending to the oil sector at the moment.

And you see obviously a lot of refinancing and things like that; but new loans are very few. Having said that, we do maintain good relationships and good dialogues with parties; and clearly introducing some debt into Panoro is of course a possibility, at least on a modest basis.

So I don't think we're seeking to do a high yield bond of any sort. But certainly some more conservative lending is something that we do entertain

I’d like to thank everybody for dialing in this morning. And look forward to updating you again in the future.

Thank you for listening. Bye, bye.