Teekay Offshore Partners' (TOO) CEO Peter Evensen on Q4 2015 Results - Earnings Call Transcript

| About: Teekay Offshore (TOO)

Teekay Offshore Partners L.P. (NYSE:TOO)

Q4 2015 Earnings Conference Call

February 18, 2016 12:30 PM ET

Executives

Ryan Hamilton - Investor Relations

Peter Evensen - Chief Executive Officer

Vince Lok - Chief Financial Officer

Kenneth Hvid - Chief Strategy Officer

David Wong - MLP Controller

Analysts

Michael Webber - Wells Fargo Securities

Spiro Dounis - UBS Securities LLC

Fotis Giannakoulis - Morgan Stanley & Co. LLC

Benjamin Brownlow - Raymond James & Associates, Inc.

Stanley Burns - Stifel Nicolaus

Bradley Lutz - Manulife Asset Management

Richard Mashaal - Senvest Partners

George Berman - IFS Raymond James

Operator

Welcome to Teekay Offshore Partners Fourth Quarter and Fiscal 2015 Earnings Results Conference Call. During the call all participants will be in a listen only mode. Afterwards you will be invited to participate in a question-and-answer session. [Operator Instructions] As a reminder, this call is being recorded.

And now for opening remarks and introductions, I would like to turn the call over to Mr. Peter Evensen, Teekay Offshore Partners’ Chief Executive Officer. Please go ahead, sir.

Ryan Hamilton

Before Mr. Evensen begins, I would like to direct all participants to our website at www.teekay.com, where you’ll find a copy of the fourth quarter 2015 earnings and business outlook presentation. Mr. Evensen, will review this presentation during today’s conference call.

Please allow me to remind you that our discussion today contains forward-looking statements. Actual results may differ materially from results projected by those forward-looking statements. Additional information concerning factors that could cause actual results to materially differ from those in the forward-looking statements is contained in the fourth quarter and annual 2015 earnings release and the fourth quarter 2015 earnings and business outlook presentation available on our website.

I will now turn the call over to Mr. Evensen to begin.

Peter Evensen

Thank you, Ryan. Good morning, everyone and thank you for joining us on our fourth quarter and fiscal year 2015 results and business outlook investor conference call. I’m joined today by Teekay Corporation’s CFO, Vince Lok; Chief Strategy Officer, Kenneth Hvid; and MLP Controller, David Wong.

During our call today, I’ll be walking through the earnings and business outlook presentation, which can be found on our website. On the call today, I’ll start off with a brief update on the fourth quarter and fiscal year 2015 results followed by forward financial guidance for 2016 and 2017 and a detailed business outlook.

Starting on Slide 3 of the presentation, let me first review some of Teekay Offshore’s recent highlights. For the fourth quarter the partnership generated cash flow from vessel operations or CFVO of $172.9 million in the fourth quarter, an increase of 19% from the prior quarter. The partnership generated distributable cash flow or DCF of $67 million in the fourth quarter, up 14% from the previous quarter resulting in DCF per limited partner unit of $0.62, an increase of 27% from the previous quarter.

The decision in December to temporarily reduce the partnerships distributions as a result of increasing reserves was a difficult decision and was caused by the inability to access competitively priced capital in the current negative capital market environment and was not caused by shortfall in the cash flows from our operations.

We strongly believe the reduction is in the best interests of long-term unitholders, as the reallocation of a significant portion of our internally generated cash flows in order to fund our profitable growth projects scheduled to deliver over the next several years will result in higher available distributable cash flow per unit in the future.

Since our call in December, we’ve nearly completed the sale of our four remaining non-core conventional tankers for a $130 million creating approximately $60 million of liquidity of which $30 million was secured in December. These asset sales take advantage of strong tanker asset prices and represent one of many ways we are able to supplement our internally generated cash flows to meet our funding requirements.

We completed the sale of the two conventional tankers on December 18 and we expect to complete the last two via sale-leaseback to a third-party in March. Lastly, offshore units and our fleet continue to operate with high uptime and utilization, generating stable cash flow, supported by a diversified portfolio of long-term contracts totaling $7.8 billion of forward revenues and an average contract length of five years with high quality counterparties.

Turning to Slide 4, despite the challenging macro energy environment affecting our customers, the partnership had a successful year in 2015 from a financial, commercial and operational perspective. Starting with our financial results, during 2015 the partnership grew with CFVO and DCF by 25% and 31% respectively from the prior year highlighting the stability and growth of our business, which plays an integral role in our customer's oil production logistics chain.

We also successfully raised approximately $2.4 billion in debt and equity financing highlighting the strong support from our bank group, which includes over 35 commercial banks and export credit agencies as well as our investors to finance our projects that are on long-term contracts.

The growth in our cash flows was driven by the completion of $1.7 billion of profitable growth during the year. On July 1, we completed our largest FPSO acquisition to date with Knarr FPSO, which is operating under a 10-year contract with Shell formerly the BG Group on the Knarr oil and gas field in the North Sea.

In June, our first unit for maintenance and safety or UMS commenced its three-year contract with Petrobras in Brazil. And during the first seven months of 2015, we completed the acquisition of six long-distance towing and offshore installation vessels.

We also signed the strategic East Coast Canada shuttle tanker contract with a consortium of nine major oil companies and we are now the sole supplier of shuttle tanker services for the region under a 15-year contract not including extension options. Lastly, we had a strong operational and HSEQ performance during the year with high uptime and fleet utilization in all of our businesses.

Turning to Slide 5, we provided a breakdown of our forward fee-based revenues that support the partnership stable and growing cash flows. On this slide, we provided a breakdown of our existing contract portfolio of forward fee-based revenues totaling $8.2 billion with an average contract length of five years excluding extension options based on revenues attributable to our existing assets currently in operation and revenues attributable to our existing growth projects, which are expected to provide incremental CFVO and DCF growth in the future.

Our portfolio of $5.2 billion of forward revenues related to our existing operations and are contracted with oil majors, but we are not sitting still. In the current market environment, we continue to focus on extracting maximum cash flows from our existing assets by implementing various cost reduction initiatives and fleet efficiencies, including operating our assets with higher uptime and utilization, while at the same time focusing on the future extension or redeployment of our existing assets.

We have an ongoing dialogue with our customers regarding exercising options on existing contracts and with potential customers on redeploying our assets, our long-term charters as the units become available.

Our portfolio of new growth projects and associated forward fixed revenues of $2.6 billion are scheduled to deliver and commence their respective long-term contracts between the latter half of 2016 through the first half of 2018. This portfolio will grow if we secure a charter contract for our second UMS newbuild and as we start building a book of contracts for our towage newbuilds. Our focus here is to execute on our existing committed growth projects and ensure these projects deliver on time and budget, while not adding new projects.

Turning to Slide 6. We provided our proportionally consolidated estimate for our run rate 2017 CFVO incorporating the delivery of our growth projects over the next two years and the impact of our cost-saving initiatives which more than offset lost cash flows from vessel sales and the Varg FPSO contract termination which I will touch up on later. We provided a more detailed breakdown of our 2016 and 2017 CFVO guidance by segments from our consolidated and equity accounted vessels in the appendix of this presentation.

CFVO is expected to increase from the implementation of various cost-saving initiatives that are expected to translate into OpEx and G&A cost savings and the delivery of our portfolio growth projects, including the Petrojarl I FPSO scheduled to commence its five-year charter contract with QGEP in the third quarter of 2016. The delivery of our four state-of-the-art long-distance towing and offshore installation vessels throughout 2016.

The Gina Krog FSO that is scheduled to commence its contract with Statoil in the first half of 2017. The Libra FPSO that is scheduled to commence its 12-year contract in early 2017 with a consortium of major oil companies and the delivery of the first two newbuilding shuttle tankers that will operate on a 15-year contract for East Coast Canada.

These increases more than offset the lost cash flows from the sale of our four conventional tankers I touched upon earlier and three older shuttle tankers and the Varg FPSO contract termination, which contributed annual CFVO of approximately $50 million.

The combination of these factors are expected to result in run rate 2017 CFVO of approximately $860 million on a fully delivered basis, which represents an increase of 27%. Note that this run rate figure excludes the third East Coast Canada shuttle tanker delivering in early 2018 and the two remaining unchartered UMS units.

Turning to Slide 7. We lay out our cash flow forecast for 2016 and 2017 highlighting our estimated sources and uses of cash in each year. Starting at the bottom with our sources of 2016 cash, we highlight our committed debt financing that have already been secured for various growth projects. Bank debt financings that are in process which includes both new debt facilities and refinancing of existing bank debt maturities that were already in discussions on with various banks.

Significant examples include the bank financing of East Coast Canada shuttle tankers delivering in late 2017 and early 2018 in various debt refinancing such as the refinancing of the Varg FPSO facility in mid-2016.

Next is CFVO from our operations including dividends received from our Brazilian FPSO joint ventures and committed asset sales that have already been secured. When compared to our cash uses which includes our capital expenditures on growth projects bank debt maturities, debt and equity service costs and bond maturities you will note that the majority of our funding needs are met with retained operating cash flows and committed and anticipated financing..

However, there still remains a funding need of approximately $250 million and $90 million in 2016 and 2017 respectively. It’s important to note that we removed UMS number two and UMS number three from our forecast because we've reached an agreement to delay the delivery date of UMS number three until 2019 and are in discussions regarding UMS number two. So having to find the funding shortfall in order to keep our liquidity balance consistent at the $280 million level as of December 31.

On Slide 8. Let's review the various alternatives available to address our funding needs in the future. We believe we can secure additional debt financing amounts on our under-levered and unmortgaged assets. For example, we could potentially secure second lien financing on assets or secure financing on certain assets that are unmortgaged. We will also look to the unsecured bond markets as they become available with acceptable pricing.

Sale-leasebacks using our offshore assets we’re looking at replicating a 10-year sale-leaseback financing our sister company Teekay LNG recently secured on two LNG carriers which were on five-year charters with Cheniere, with a Chinese leasing company. Asset divestitures here we’re pursuing two avenues, the sale of minority interest in some of our offshore units that are currently in operations and our future growth projects to financial partners as well as outright sales.

Past examples include the sale of 50% of our Cidade de Itajai FPSO project in Brazil following project award and of course the recent sale of our four non-core conventional tankers. Finally, we are evaluating hybrid equity securities. Overall, we’re very focused on this with several of these initiatives already in progress and we’re confident we’ll be able to fulfill our remaining funding requirements.

Turning to Slide 9. In light of the challenging macro and capital markets we’re pivoting our business development strategy to focus on extending contracts and redeploying existing assets on the new contracts versus our past focus on developing new organic growth project.

At the same time some things don't change, including our focus on executing our existing pipeline of growth projects ensuring projects remain on time and budget. And finally the message we’re hearing from our customers is that fabrication and operating costs have to come down across the Board. This will be true even if oil prices quickly rebound, which we don't think will have.

Therefore we’re working to increase our relevance to our customers by working with them and our suppliers to find efficiencies in order to help reduce our customers operating costs and implementing various cost saving initiatives across the organization.

Turning to Slide 10. We look at the future role of offshore and deepwater oil production in the global energy mix, which is expected to continue to increase driven by future demand for new field development. It is a reality that the recent collapse in global oil prices and subsequent oil company spending cutbacks is having a negative impact on the offshore production market in the near-term.

We anticipate that very few knew offshore production projects will be sanctioned while oil prices remain at current levels. However, we believe that long-term future for offshore and deepwater remains good. Global oil demand is expected to increase significantly over the next 25 years due to a rising global population and higher transportation fuel demand from a growing middle class.

In addition, a large amount of new oil production will be needed just to offset declining supply from existing conventional oil fields. According to the IEA production from existing oil fields is expected to decline by two-thirds between now and 2040, meaning that new sources of oil will need to be found in order to make up shortfall.

According to a recent report from ExxonMobil global deepwater production is expected to increase - is expected to capture an increasing share of global oil supply going forward with an estimated 70% increase in production from deepwater to around 10 million barrels per day by 2040. This equates to compounded annual growth rate of just over 2% over the next 25 years requiring a massive investments in new offshore oilfields and infrastructure.

So turning to Slide 11, let's look at the medium-term opportunities in the FPSO space. Despite the weak near-term outlook for FPSO contract awards a number of projects are still in development. In fact, we count over 55 potential FPSO project opportunities in the North Sea and Brazil, which could be awarded as the oil market recovers.

Field operators are waiting for a higher oil price before proceeding with new projects, but they're also trying to reduce costs so that those projects can move forward at a lower breakeven price. In this regard, we are seeing a great deal of progress with rapid deflation in field development and project cost across the offshore value chain including lower exploration costs from lower offshore drilling, seismic and subsea as well as of course the appreciation of the U.S. dollar relative to the Norwegian Kroner and Brazilian Real.

In a recovering oil market, the message we are hearing from our customers is that they expect to be using existing production systems to deliver quick and cost-effective solutions for field development at a lower total investment and reduce dollar per barrel breakeven cost than more expensive newbuild FPSOs.

We believe that on the water medium-sized FPSO units will play a key role in many of these new developments as a more flexible and lower cost alternative to the newbuildings. As such, we believe that TOO's fleet of on the water units built to North Sea and Brazilian standards and requirements combined with Teekay having lower operating costs than our customers, puts us in a good position to take advantage of the new FPSO opportunities as market conditions improve in the coming months and years.

Turning to Slide 12, we provide a summary of the contract status of our FPSO fleet. In the near-term, the only FPSO that is expected to roll off its existing contract is the Varg FPSO, which I’ll touch on in more detail.

It’s important to note that FPSOs typically stay on their respective fields for the life-of-field, as there is high switching costs. Which means as long as the field is producing oil the contract extension options will generally be exercised. Excluding the Varg FPSO, our current FPSO fleet produces at an average cost to our customers of approximately $11 per barrel highlighting a low marginal cost of production.

Turning to Slide 13, we highlight our future plans for the Varg FPSO. In late November, we received a termination notice from the charter Repsol based on a hardship termination right that is specific to the Varg FPSO contract citing the field being uneconomical at current production levels of approximately 6,000 barrels per day at current oil prices.

The Varg, which is expected to leave the field in August 2016, contributed approximately $50 million of annual CFVO representing approximately 7% of the partnerships 2016 CFVO, which is unfortunate, but as I highlighted earlier will be more than offset by the delivery of future growth projects and various cost saving initiatives.

The unit meets the strict Norwegian offshore standards, which provides flexibility as unit can operate anywhere in the world and also has very little competition for new North Sea projects as there are very few available FPSO's that meet these strict standards.

In addition, the unit has the capacity to produce 57,000 barrels of oil per day, assuming the same daily rate as the contract with Repsol and producing at the unit's capacity of 57,000 barrels per day. The average cost of production would be approximately $5 per barrel, which makes it a very cost-effective solution for our customers.

We are already in discussions with several oil companies to redeploy this asset on a new fields in the North Sea. With the strong operating platform and our leading market position in Norway as the number one least FPSO operator in the North Sea, we believe we are well-positioned to redeploy the Varg on a new contract.

Turning to Slide 14, we want to emphasize that redeployments are a fact of life that we are familiar with at Teekay Offshore. We want to highlight the Petrojarl I’s redeployment track record having already been operating on 10 different fields in the North Sea since its delivery in 1986. The unit is now scheduled to commence operation on its 11th field under a new five-year charter contract with QGEP in the third quarter of 2016 on the Atlanta field offshore Brazil.

The unit is currently undergoing upgrades for fully built-up cost of approximately $250 million, which includes field specific upgrades and life extension work to extend its useful life by 15 years. The unit which is expected to generate annual CFVO of approximately $50 million will operate as an early production system with the potential to be a permanent solution for the field compared to a larger more expensive solution.

Like Varg, Petrojarl I was NORSOK compliant and therefore had the flexibility to operate in both the North Sea and Brazil. Petrojarl I was attractive to our customers as it was a cost-effective unit and quick-to-market with approximately 18-month lead time. In addition this medium-sized FPSO unit provides flexibility and lowers execution risks during the field development and customers are able to invest less upfront and test the field prior to making a larger investment.

Turning to Slide 15, we provide an update on the high returning Libra FPSO project in Brazil. The Libra FPSO will operate on the larger Libra pre-salt field in the Santos Basin that has an estimated reserve of 8 billion to 12 billion barrels of oil equivalent. And it’s currently considered to be the largest oilfield offshore Brazil. This field is a high priority for the strong consortium of international partners, including Total, Shell, CNOOC, CNPC and Petrobras.

The billion-dollar Libra FPSO remains on budget and we’ve secured $800 million of long-term debt financing. In December the partnership provided its 50-50 joint venture partner Odebrecht Oil & Gas or OOG a put option, which if exercise will require Teekay Offshore to buy up to 25% more of the equity. Ownership in the Libra FPSO project had a discount in April 2016.

In addition, the partnership also provided a call option to OOG to buy back the shares in January of 2018 at a premium. If the put option is exercised and the call option is not exercised, we will seek to sell a partial interest in the project to restore our ownership to the 50% level. If both the put and call options are exercised, we will recognize the gain.

Turning to Slide 16. We highlight that the strong shuttle tanker market remains tight and Teekay Offshore shuttle tanker fleet is largely sold out for 2016. We anticipate global shuttle tanker fleet utilization to increase driven by a combination of more listing points and new fields coming on stream faster when fields are rolling off. Providing further support to an already tight North Sea shuttle tanker market. In 2016, we expect the number of shuttle tanker listings in 2016 for our CoA fleet to increase by 24% or 12% compared to 2015.

On the vessel supply side there are currently no unchartered newbuildings on order as all newbuilds are already earmarked for specific project. The shuttle tanker market represents a mature market where we view our main competition to be Knutsen. With leading market positions in all three shuttle tanker basins including the North Sea, Brazil and East Coast Canada and are strong operating platform we are able to achieve higher fleet utilization. We have the flexibility to interchange assets between basins.

For example, this past year we moved the Hispania Spirit shuttle tanker from our CoA fleet in the North Sea to operate on the new 15-year contract in East Coast Canada. And in 2016 we’ll move the Navion Anglia shuttle tanker from Brazil to operate in the CoA fleet in North Sea where we’re tight on vessel capacity to meet our customer's requirement. The CoA fleet is also a differentiator as it gives us the flexibility to secure new contracts.

Turning to Slide 17. In summary, we remain focused on addressing the remaining funding needs that I outlined project management and execution, ensuring our existing growth pipeline remains on time and budget, finding efficiencies and implementing various cost-saving initiatives while at the same time pivoting our business development strategy to focus on extending contracts and redeploying existing assets versus new organic growth projects.

Thank you all for listening and operator I'm now available to take questions.

Question-and-Answer Session

Operator

Thank you. [Operator Instructions] Your first question will come from the line of Michael Webber of Wells Fargo. Please go ahead.

Michael Webber

Hey, good morning guys. How are you?

Peter Evensen

Fine. Thanks.

Michael Webber

Peter, I wanted to start off around the Libra, the options - I think first preference, in a filing by Odebrecht for the Brazilian antitrust regulator. Just curious, some color around why the options are granted and, maybe, some timing around how that would work? Is it April within the deck around when you might have to exercise or when they could exercise the put? One, is that reflected in the $250 million gap. And two, when would you stop and start needing to look for bias to that if it is exercised?

Peter Evensen

So this was part of a bigger negotiation that involved the $800 million debt facility. There was some concern by the banks that OOG might not have the capability to fulfill all of its requirements given that it has some other financing needs as it relates to offshore.

Therefore we worked out between the banks and OOG that OOG would have the ability to sell us half of their ownership, but in return they believe that they will ultimately achieve an acceptable restructuring and therefore they wanted the ability to buy it back and that seemed to work well for the banks.

It didn't exactly work as well for us because it added to our potential funding shortfall, but we have to think long-term here. And so that's why - that’s the background for how we agreed to it. And I will turn it over to Vince to talk about the financial effect of it.

Vince Lok

Yes, Mike in terms of the funding gap on Slide 7, we did assume that they would exercise the put option as we noted in - note to in that slide. So that's reflected and included in the 250 million already.

Michael Webber

Okay. That's helpful. In terms of thinking about debt negotiation around the options, were you able to extract any value out of the fact that you are taking on some additional risks that you weren't anticipating stepping into that JV?

Peter Evensen

Yes. So without being drawn on exactly the numbers. If they do exercise the put option we will buy that at a discount to the amount that is required in terms of equity. And if they exercise their call option and approximately the beginning of 2018, we will realize a gain because they have to buy it back at premium. So if you will there's an embedded high funding cost on that. While we’re not in the business of being a bank per say, we are in the business of making sure that we’re in a position to satisfy our customers and complete the Libra.

Michael Webber

Fair enough. Just one more and then I will move on. If you were to find - if they were to exercise the put and you were to find a buyer for the remaining stake, is that completely up to you in terms of who that buyer would be, or would they need to go do a regulatory process in Brazil, as well? Is that list inherently restricted, in any way?

Peter Evensen

The bank financing allows for us to sell a minority portion and I don't believe there would be any regulatory thing you called on that, as long as Teekay remains the operator and technically, manage it along with our joint venture down in Brazil, which would still be the case.

Michael Webber

Fair enough. Moving onto funding, and first of all, Peter, I looked at the deck and didn't see it, but I think in your remarks you mentioned when you were talking asset sales and sale leaseback, I believe you mentioned the Cidade de Itajai as a potential asset you would look at.

And then maybe, separately, around the sale leaseback opportunity, you mentioned what you had done at PGP. Can you contrast the Chinese appetite for sale leaseback deals in LNG versus something a little bit more intricate, potentially shorter-term in the contracts in the offshore space?

Peter Evensen

Okay. So first let me say what I gave as an example was that we’re able to sell minority stakes and I gave us an example of what we did a few years ago selling 50% of the Itajai. Having said all that we there is a diverse universe of investors as well as financial institutions.

What we see out of the Asian sale-leaseback opportunities that we have is that they value very highly our long-term contracts. And so we’re able to achieve that obviously with the Teekay LNG we achieved it with six to eight year contracts, here we have things like the 15-year contracts that we have on East Coast Canada and we have other one.

So I think that it’s the nature of the underlying cash flows i.e. those contracts that make it good or that make it possible. If you think about a lot of our contracts, we have 10-year contracts with Shell and shuttle tankers, we have East Coast Canada with 15-year contracts, we have Libra with 12-year contracts.

And so we feel pretty good about our ability to execute on that, but there is also financial players that are interested in sale leaseback, so it's a question of finding the right risk premium and obviously the lowest cost of capital. And so when we’re looking at all these alternatives, our whole goal here is to look at - is to balance the short-term and long-term, obviously if we’re selling out certain parts of what we’re doing or doing sale leaseback's, we are increasing our cost of capital or losing cash flow.

But our underlying goal here is to increase distributable cash flow per unit. All of these alternatives to address our funding requirement come at a cost and therefore we’re balancing out all of those. What would you add to that Vince?

Vince Lok

Yes, I think that’s right. Our ultimate goal here is to maximize our DCF per unit and part of that of course is to make sure we fill these funding requirements so that is our goal here.

Peter Evensen

And filling the funding requirements is also necessary in order to restore the distributions.

Michael Webber

Sure. Sure. My next question is around that, Peter. I think you mentioned somewhere in your prepared remarks, the second lien market on existing assets. I'm just curious. One, and this may be a question for Vince, too - but, just how far along you guys are in looking at second liens on assets like the Knarr.

How robust that market is here. And, maybe, Peter on a bigger scale - if you think about the constellation of potential liquidity levers, where does that fall in the timeline and how would you rank order without being too specific? I know you wouldn't draw on it, I guess. How would you prioritize your liquidity options here? Maybe start with the second lien stuff and then prioritize.

Peter Evensen

Yes. Mike, I can't really comment on specifics. I would say that we’re looking at - we have multiple alternatives as we listed here and various of these already in progress at different stages. So I wouldn’t necessarily put a priority over one, over another it really depends on the relative economics and looking at different criteria.

So I think basically we are looking at various alternatives and we feel very confident that being able to use these different alternatives not only to meet the minimum amount that we’ve identified is the gap, but I think to make sure that we have enough liquidity buffers going forward as well.

Vince Lok

I mean as a general comment I would just say that the market changed so quickly right. We were confident depending on outside capital and then that outside capital both became expensive and not available in terms of having reduced capacity. So I'm really proud that the finance team has been able to pivot and look at other sources of capital to go forward.

And obviously in this presentation we’ve defined the problem if you will, quantified it and I'm confident that finance team will come up with the right solution that will meet the goal of ultimately restoring the distributions and increasing the DCF per unit.

Michael Webber

Fair enough. Great. I will turn it over. Thanks for the time, guys.

Vince Lok

Thank you.

Operator

And your next question will come from the line of Spiro Dounis from UBS Securities. Please go ahead.

Spiro Dounis

Hey, hello again, Peter and Vince. Just wanted to get a sense of how much capital would be required, if any, to move or retrofit the Varg at the new field. Was that, at all, included in those CapEx figures?

Kenneth Hvid

Yes, it’s Kenneth here. First of all I think to your last question, no we’ve not included any upgrades on the Varg in the CapEx figures. So we’re looking at a couple of different options so one that would require a very little operates, if not zero operates and other that would be a bit more.

It’s difficult to say what the range would be right now, but would probably be in the 100 to 200 if you works to a larger upgrades that was required, but there are a couple of options where essentially the Varg you know would be able to produce more and then as this condition. Remember it’s sitting on the field now and could essentially have continued to produce for a number of years on the existing Varg field. So unit is fully operational so it will all depend.

Spiro Dounis

Got it. And am I right in thinking there's a direct link between if you did have to put in capital, you would obviously be charging a higher rate? You wouldn't necessarily be just one way, right?

Peter Evensen

That’s correct. So the example we’ve used when we talked about $5 production is based on the current rate and no upgrades and using the existing nameplate capacity that we have in there, so the right way to think about it is, it’s obviously that if there were other fields then that would go up somewhat, but it would be filled into the rates over the term period.

Spiro Dounis

Got it.

Vince Lok

And then we of course would make sure if there are any upgrade cost so will secure the financing to fund the upgrades just over the package all supported by the charter against them.

Spiro Dounis

Got it. Okay. That's helpful. It sounds like you've got a lot in progress right now, to close this gap. I'm just wondering, in terms of timing - these deals are not always easy to structure, depending what you've got going on. Would you expect - would seeking bridge financing, to bridge that time period ahead of something? Or, do you think you would be able to do these deals before payments come due?

Vince Lok

I think we’ll conclude before the payments come due. We start with a good cash balance and so there really isn't anything big until the next bond maturity in 2017. So I think we’ve got a good runway to complete.

Spiro Dounis

Got it. Last one from me, in terms of FPSOs and sale leaseback, if London Petroleum did one a few weeks back, and one of the things we are hearing from our counterparts in Europe is that the lenders on the other side of that transaction want, I guess, guarantees on the field and performance. I'm just wondering, if you think that would, in any way, be an impediment. Whether or not your customers would be willing to give any guarantee to ensure that the sale-leaseback would go through.

Peter Evensen

I'm not familiar with that particular deal, but Teekay Offshore already wants that its performance so sale-leaseback wouldn’t change that as it relates to our customers. The contract that you have with customers regarding the operation is there guarantee you don't really need any extra guarantee on that.

Spiro Dounis

Got it. That makes sense. Thanks for the color guys.

Peter Evensen

Thank you.

Operator

And your next question will come from the line of Fotis Giannakoulis of Morgan Stanley. Please go ahead.

Fotis Giannakoulis

Yes. Hi guys. I understand that apart from the accommodation that you have put forward, there must be some changes in the CapEx schedule. If I remember well, in the previous quarter, you had guided towards $235 million CapEx for Q4. It seems that it was quite less than that. Can you tell us what was the difference?

Peter Evensen

I don’t think I mean obviously there is always changes to especially conversion costs that can switch from month-to-month, but I don't think there is anything maturely that’s changed. We’ve shown on Slide seven the growth CapEx for the two years and then the committed financings so apart from the removing or differing the UMS unit I don't think anything materially change other than the sort of shifting the timing of certain payments perhaps.

Fotis Giannakoulis

Okay. Maybe I can follow up a little bit later. Can you remind us, if I remember well, there is a note from the parent for the Knarr FPSO. Is that still outstanding? Is there a plan to be paid back?

Vince Lok

Are you referring to from the parent company?

Fotis Giannakoulis

Yes.

Vince Lok

Yes, there is roughly $200 million that’s still outstanding owing to the parent company.

Fotis Giannakoulis

Is there a time schedule about the repayment of that amount?

Peter Evensen

No. There isn’t a specific timetable, no.

Fotis Giannakoulis

Okay. Thank you. I understand that there are negotiations in the schedule about the extension of the FPSO contract. Can you - I'm not talking only about the Varg, I'm talking about the other three vessels that came out of contracts. Can you comment on the which of these vessels can be extended at the same field and which of the FPSOs might have to be redeployed at some new field? What is expected, the CapEx for any potential deployment?

Peter Evensen

That’s a lot of questions in detail Fotis. But as we showed under the contract status we really only have the Varg available everything else is longer-term. So I'm not going to get drawn on our contract discussions that we have with various customers, but on the whole if you look at 2016, 2017 we feel confident in our numbers. As I said with the exception of the Varg.

Fotis Giannakoulis

Would you be able to share with us the cash cost of this field over each of these three rigs, FPSOs they're coming off contracts in2018? You mentioned about the $11 per barrel numbers, but if you can focus on these three ones.

Peter Evensen

Yes we are not going to get drawn on each individual one Fotis because each one is little different and there's a whole bunch of moving parts sometimes the oil company wants to do more drilling, which brings in other reserves or they want to tieback other fields into that.

So just to sit and look at the existing oil production doesn't make you really any smarter and that isn’t actually what the oil company go - that isn’t what goes into their decision-making. Their decision-making goes into how much do I have to invest in order to keep the production going.

We never actually kind of run out of oil physically. You just run out of it being profitable to live. And the oil companies right now want to retain their options because they like us don't believe $30 oil will exist here forever. But they are trying to balance out their short-term cash needs and so they look at the marginal cost, but they are very well aware that they need to continue field production and they don't want to close down productions just to see oil prices rebound.

And then they should never have shut down. And there's huge cost to shutting down and trying to restart. So it I understand you want to just look at production and look at per barrel but I just have to emphasize it’s a far more complicated calculation by our customers.

Fotis Giannakoulis

Thank you, Peter.

Vince Lok

Fotis, I just wanted to respond to your first question I think I know what the other differences relating to the CapEx schedule. Before we had shown the Libra CapEx on a pro rata gross basis and now that we’ve secured the long-term financing on Slide 7 now as we noted in note two that we are including the equity CapEx with a lever project so that's why the gross number looks lower than what you’ve seen before probably.

Fotis Giannakoulis

Okay. Thank you very much Vince.

Vince Lok

Okay.

Operator

And your next question will come from the line of Ben Brownlow of Raymond James. Please go ahead.

Benjamin Brownlow

Hi, guys thanks for taking the questions. Just to dovetail on the last commentary with the production, can you give any color around what the production bonus was tied to the Spirit and the trigger opportunity there for future bonuses?

Kenneth Hvid

The production bonus was around $8 million on the Voyageur and essentially if we can produce greater than 95% capacity throughout the year. Any amount achievement over that 95% we don’t result in that bonus. And so with the strong operations of our Voyageur this year we were able to capitalize on that.

Benjamin Brownlow

So is that paid on annual at the end of each fiscal year? Is that a quarterly?

Kenneth Hvid

It’s annualized, its annual payments.

Benjamin Brownlow

Okay. So that one if that were to come about, it wouldn't be until the end of this year.

Peter Evensen

Correct.

Benjamin Brownlow

Okay. Then, just to touch on the towage segment, there's a pretty big ramp in the CFVO. I think the annual amount outlook was $39 million this year and $77 million next year. I know the timing of the ALP deliveries is roughly four throughout this year. Can you give a little bit more color around those four deliveries? How should we think about what the visibility and confidence is in those rates?

Kenneth Hvid

Yes. First on the newbuildings, is correct that we’re going to expect all four newbuildings to deliver this year. The first one has had a bit of delay has been picked up by the main press, the shipyard have had some cost overruns on building and there is a delay on it, but it works pretty well for the projects that we’re bidding on at the moment. The tows that are out there and they also may lease obviously that are due because of the delay on the first unit.

I think in terms of performance of the fleet, we would expect to have a slight uplift in rates on these new more modern, higher volatile vessels than the average of our existing fleet. Right now we’ve had reasonably good utilization, but a lot of it has been a little bit hand to mouth contracts as I’d say where we've totaled our drilling rigs short-term notice.

But obviously, what we are really have invested in and what we’ll be focusing on is the large tows that will have a full booking of the big FPSOs that requires multiple towage vessels. And that’s really when we refer to the book to be build that vessel type of projects that we’re looking at and we have next dialogue on pretty much all of the FPSO that are being delivered from the shipyards over the next 24 months.

Benjamin Brownlow

That’s helpful. And then just one last one for me on the FSO Navion Saga, how should we think about the opportunity to redeploy that asset?

Kenneth Hvid

Well, first of all, it’s an asset that’s been operating on the Volvo field for many years and as such have written down value more in our books, so it’s exceeded really the contract life we expected on. So for us it’s really a free option to either look at finding and redeployment which would totally require some life extension work and investment on it, or alternatively sell it to someone that make will use of it or it’s essentially written down to scrap value in our book.

So it’s a good vessel and that it has the SGL mooring system, which is unique and that can be reused, but it would - of course we buy significant operates after a number of years in the Volvo field.

Benjamin Brownlow

Great. Thank you.

Operator

And your next question will come from the line of Stanley Burns with Stifel. Please go ahead.

Stanley Burns

Hi, good afternoon everyone. Just in terms of, when you look at slide 7 with the cash flow forecast, and you have the bank debt maturity, some bank that Amer Jason, is there the opportunity for some, if not most of that, to be extended or rolled over with the current bank groups, given what seems to be a very good relationship with the company?

Peter Evensen

Yes. I guess you are identifying the sort of the duration of our liabilities and you’re right that’s in a lot of the offshore financing especially for FPSOs, the debt amortization is quicker than normal. I think that is an alternative, obviously it requires approval from the bank group to do something like that, but that is an alternative that other people have used before. So that is for consideration.

Stanley Burns

I don’t know if you could share with us, I mean have you had discussions with those different bank groups as well potentially amending, extending any amounts due this year?

Peter Evensen

No not at this time so not yet.

Stanley Burns

No. Okay. And in the shuttle tanker market, you mentioned conditions remain very strong. I know there were a number of contracts that were expiring in 2016. Is it fair to take away from your cash flow bridge that you don't show any decline in shuttle tanker CFVO, that those tankers that were expiring this year have been renewed at similar rates to where they had been, previously?

Peter Evensen

That’s correct.

Vince Lok

Yes.

Stanley Burns

Okay, great. And then, another question. Can you, maybe, comment on your overall relationship with Petrobras, at this time? Have they been paying on time? Any issues you've had with them, at this point given, obviously, the challenges they are facing?

Peter Evensen

Yes, on the whole as supplier to Petrobras we continue to have a good relationship with them, but the key is to be part of their production chain. They need our assets in order to generate revenues. Other folks that we speak with if they don't need your assets then they have a different attitude, but for example our UMS last June they helped us to get back quickly on to the field because they needed that capability in order to maintain their units.

So I would call it - so we’ve a good relationship with them, but I would call it very specific and how they're going about, but we have a great relationship with them for example on the Libra field there in the yard with us looking at it and they are keen to get that unit and start producing oil on the Libra oil field.

Stanley Burns

Great. And all the current vessels…

Peter Evensen

Sorry. And they have - we are not - we have experienced no delay in payments from Petrobras. Sorry...

Stanley Burns

No that's fine. That's great news. Last question for me, maybe a little more on the technical side. On Varg, if I heard correctly, the CFVO was $50 million a year, or was it half a year?

Vince Lok

That’s per year.

Stanley Burns

Per year. So then is it kind of fair to say that for the 703 CFVO you have for 2016 just maybe only about $25 million of that in there from Varg?

Peter Evensen

That was actually probably less than that because Repsol has exercised or given us notice that can in 2015 will actually get the zero CapEx durable rate effective February 1 of this year, so there is actually very little EBITDA relating to Varg in the 2016 figures.

Stanley Burns

Okay. So despite the $50 million loss from 2015 right you've kind of more than made up with getting to the 703 than?

Peter Evensen

That’s right.

Stanley Burns

Great. Thank you and good luck.

Vince Lok

Thank you.

Operator

Your next question will come from line of Brad Lutz of Manulife Asset Management. Please go ahead.

Bradley Lutz

Hi, thank you for the overview, today. If I can stay with slide 7, I'm looking at that 2016 uses stack. Do you have that stack broken out on a quarter to quarter basis, please? If that stack is $1.4 billion, what is 1Q, 2Q, 3Q and 4Q pacings?

Vince Lok

I would say that it’s for 2016 it’s probably fairly even between the first half and the second half with the exception of probably some the CapEx of the project especially for Petro 1 which is delivering and starting up in the third quarter. So I would say the CapEx requirements are a little bit higher in the first half than the second half. The second thing I would point out is we had our Norwegian bond that matured in late January and so that’s the part of the - you see that in the top part that of course the bond maturities. That was already paid in January using our existing liquidity.

Bradley Lutz

That January 2016 maturity satisfied that lighter green top slice of bond majorities?

Vince Lok

Correct, yes.

Bradley Lutz

The balance sheet posts $470.6 million of current portion of long-term debt. But, that bond maturity slice plus the bank debt maturity slice looks to sum up to less than $470 million. What is all included in the balance sheet?

Vince Lok

That should be basically what you see there in terms of the debt service, the debt service on Slide seven of course include interest expense as well as distributions to equity holders, but that should pretty much total what you see on the balance sheet, the only slight difference I would say is on the Norwegian bonds, the balance sheet is mark-to-market based on the balance sheet date foreign currency rate, where as we've hedged that. So the Norwegian - the actual Norwegian bond amounts in cash on a hedged basis little bit higher than what’s on the balance sheet.

Bradley Lutz

If I look at those balance sheet line item of 471 million for a portion of long-term debt, is there interest expense accrued interest expense included in that? Or, those are mark-to-market maturities due in calendar 2016? Please.

Vince Lok

Yes, those would be principal payments that would be due in 2016 including the bonds as well as the bank debt maturities, which are balloons that we would refinance during the course of 2016. So that’s those are principle amounts not interest.

Bradley Lutz

In your slide deck from the second quarter 2015, please, you had $188 million of gross CapEx attributed to UMS new builds, and then 2017 that number was $174 million. Does the current slide set incorporate UMS CapEx? I guess that would be for 2 and 3, or have 2 and 3 UMS CapEx been taken out of these new 2016 and 2017?

Vince Lok

That’s correct both two and three have been taken out - out of this slide deck as Peter alluded to.

Peter Evensen

They are taken out because the deliveries have slid to the right.

Bradley Lutz

Do you still have cash CapEx commitments in spite of moving delivery to the right?

Peter Evensen

Not in 2016 and 2017.

Bradley Lutz

Okay. Thank you for the overview.

Peter Evensen

Thank you.

Operator

And your next question will come from the line of Richard Mashaal of Senvest. Please go ahead.

Richard Mashaal

Hi, Peter just had a safety back on - I think the major reason. One of the major reasons stock has reacted so poorly. People are worried about these funding requirements like on Slide seven and I guess the more confidence the market has that these funding requirements will be taken care of that really help you guys.

On Slide eight, you talk about some of the alternative you have or additional secure debt, on under levered and unmortgaged assets, what kind of number is that like how much availability do you have? Can you give us any idea?

Peter Evensen

In terms of the unmortgaged assets, we have some shuttle tankers and FSOs that are - they’re older assets, so that’s why we haven’t secured any financing in them. Those are probably valued I’d say roughly about $75 million or so in terms of unmortgaged assets, so that’s the figure.

Richard Mashaal

What about under levered assets?

Peter Evensen

I think it's hard to put a number on it, but we have a number of FPSO's and shuttle tankers that as I mentioned have a fairly quick amortization profile on the existing first lien debt. And so when you look at where they are at various stages, some of them are relative to their values under levered. I think that's sort of we added all up and also the other point is when you look at the sort of the net debt to EBITDA for TOO, it's actually on a delivering trend especially as these projects deliver. And so I think there's equity value there to allow us to secure additional financing against those assets.

Richard Mashaal

So is that additional financing, or is that a conversation with your existing bankers to say, hey, can we space out these amortizations or extend amortization, or is it both? Can you let us know - how have the conversations gone on with your bankers? I would imagine it's very much in their interest to help you out a little, do some deal with you, given all the business you're doing with them and given the fact that you've got an excellent runway of increasing cash flow going forward. As you mentioned, the deleveraging will happen. Can you give us any feel for that?

Peter Evensen

Well, first of all I agree with your points and second point is we have a very supportive group of banks and we’ve always have that and we are very grateful for that. I don't think I can really comment on specific conversations yet with the banks, but I think we will report back in due course as we make progress on these.

Richard Mashaal

Okay. Thank you.

Peter Evensen

Thank you.

Operator

And your next question will come from the line of George Berman from IFS Raymond James. Please go ahead.

George Berman

Good afternoon gentlemen. Thank you for taking my call. The funding shortfall $250 million I understand that does include if the Odebrecht put option is exercised, correct?

Peter Evensen

That's correct, yes.

George Berman

Okay. Overall would you be financially in a position to maybe take some of your public traded debt out of the market early through buybacks at a discount?

Peter Evensen

Obviously, where that our bonds are trading at a discount and so our priority right now is to close the funding shortfall that we have which I think is the right thing to do. If we have surplus funds whether they come from asset sales or other areas then we will of course optimize by looking at buying back our bonds at a discount and/or seeing the fact that our stock is trading incredibly cheap compared to the underlying cash flows, but I just want to emphasized everyone that our requirement right now is to close the funding requirement first, but what that effectively means is there's no incentive for us to go find new growth projects right now.

George Berman

Okay. The financial statement in your Page eight. You’re showing a net income of about $46.7 million if I add to depreciation amortization $72 million to it that would give me your essential operating cash flow correct?

Vince Lok

I think it’s probably better if you look at Slide or Page four of the earnings release which is our cash flow from vessel operations broken down by segment, because the income statement includes other non-cash items so it’s difficult to do that off of net income. So you can see in the fourth quarter of 2015 our total CFVO including the equity accounted vessels is about $173 million.

George Berman

Great. Perfect. Okay, thank you.

Peter Evensen

Thank you.

Operator

And we have no further questions. At this time, I'd like to hand it back over to Mr. Peter Evensen for closing remarks.

Peter Evensen

All right. Thank you all very much. This was a little bit of an unconventional earnings call, but I felt that it was important that we show our investors what our funding shortfall is as well as the fact that we have several alternatives and initiatives underway to close that remaining funding requirement. Thank you all for listening and we look forward to reporting back on our progress next quarter. Thank you.

Operator

Ladies and gentlemen, this concludes the conference call for today. We thank you for your participation. You may now disconnect your line and have a great day.

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