Liquefied Natural Gas Ltd — Update 26 April 2016

Liquefied Natural Gas Ltd — Update 26 April 2016

Liquefied Natural Gas Ltd

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Liquefied Natural Gas Ltd

Awaiting binding tolling agreements

EPC pricing validity extended

Oil & gas

26 April 2016

Price

A$0.58

Market cap

A$292m

US$/A$1.4

Net cash (A$m/US$m) at end December 2015

114/81

Shares in issue

503.1m

Free float

91%

Codes

LNG AU;
LNGLY US

Primary exchange

ASX

Secondary exchange

OTC

Share price performance

%

1m

3m

12m

Abs

2.7

(13.4)

(87.9)

Rel (local)

(3)

(9.3)

(84.8)

52-week high/low

A$4.9

A$0.5

Business description

Liquefied Natural Gas Ltd is an ASX-listed company devoted to the development of LNG export terminals in the US and Canada.

Next events

FERC NTP

2016

Tolling agreements

2016

Analysts

Will Forbes

+44 (0)20 3077 5749

Ian McLelland

+44 (0)20 3077 5756

Liquefied Natural Gas Ltd is a research client of Edison Investment Research Limited

Liquefied Natural Gas Ltd (LNGL) has continued to progress the Magnolia project, with EPC contracts signed in recent months that put the project on a much firmer footing and effectively fix costs for the development (now out to 31 December 2016). Although the contracts call for a higher capital cost than previously guided, Magnolia should still be at the lower end of LNG development costs and have lower operating costs, encouraging investment by tolling partners. We expect tolling agreements to be signed in 2016 to enable financial close (the FERC order has just been received). Given the low costs and continued need for global LNG supply, we continue to believe that Magnolia should proceed, albeit in a tougher environment. We have substantially remodelled the projects given the new information, resulting in a new NAV of A$1.0/share (US$2.8/ADR).

Year
end

Revenue
(A$m)

PBT*
(A$m)

Operating cash
flow (A$m)

Net (debt)/
cash (A$m)

Capex
(A$m)

06/14

0.0

(24.7)

(21.8)

47.3

(0.2)

06/15

0.0

(86.3)

(70.0)

47.0

(11.6)

06/16e

0.0

(110.9)

(98.7)

86.3

(0.0)

06/17e

135.1

92.1

98.1

(155.0)

(338.4)

Note: *PBT is normalised, excluding intangible amortisation, exceptional items and share-based payments.

Low-cost solution despite increased costs

Despite an increased capital cost, Magnolia should benefit from one of the lowest LNG break-even prices of development projects globally, given the low US gas prices and low capex/opex costs in the proprietary OSMR process, which has been given further boosts by increased guaranteed volumes by marquee contractors.

Awaiting FERC NTP and tolling agreements

The future of the project depends on the tolling partners seeing beyond the current depressed market sentiment and weak oil prices to global gas demand over the next 20-30 years. Given the low costs of the LNGL development solution and low US gas prices, it should compare well to other global developments, putting it in good stead for sanction. The FERC Notice to Proceed (NTP) could be issued in the short term, given that regulatory waiting times have now elapsed. The company is well placed to move rapidly once these pieces are in place. We are also encouraged by the recent DOE approval for non-FTA gas exports from Bear Head.

Valuation: NAV falls, but represents long-term value

After the increased capital costs implied by the turnkey EPC contracts, we have remodelled the projects. Although we see evidence that the projects should be able to command higher tolling fees than we had previously modelled, we see a drop in value vs previous estimates on a DCF basis. We note that as the Magnolia project is sanctioned and first LNG approaches, investors are likely to start looking at the cash flow metrics of utility peers, which allows for substantial increases in the share price over time. This means that, should investors be confident that a project will get the go-ahead, the shares could represent good long-term value. The company is well financed to see out any short-term delays.

Why have LNGL shares fallen so much?

Investors have seen LNGL shares fall materially since the peaks seen in May 2015. We attribute this to a number of factors:

Internally, the company has not hit the guided milestones (eg FEED and binding tolling agreements). Financial close, guided to be mid-2015 in 2013, has thus been pushed out. Delays not only disappoint investors on timing and execution, but may also signal a reduced probability of the projects going ahead. The project not going ahead continues to be a risk, we believe Magnolia remains attractive as a project to invest in for reasons we state later in the report. We also note that capital investment required in the plants has increased notably, reducing the value of the project to investors, despite increased revenues (vs previous expectations).

External factors include declining investor sentiment (and an emerging strong correlation with the falling oil price). These headline declines could well have had an impact on the confidence of potential tolling partners to sign agreements.

External factors

As can be seen in the charts below, there is a very strong relationship between the shares and the oil price, with an R2 of more than 0.85 since May 2015.

Exhibit 1: Share price (US$/ADR) vs Brent, $/bbl

Exhibit 2: Share price (US$/ADR) vs Brent

Source: Bloomberg, Edison Investment Research. Note: CO1 Comdty is Brent

Source: Bloomberg, Edison Investment Research. Note: CO1 Comdty is Brent

Exhibit 1: Share price (US$/ADR) vs Brent, $/bbl

Source: Bloomberg, Edison Investment Research. Note: CO1 Comdty is Brent

Exhibit 2: Share price (US$/ADR) vs Brent

Source: Bloomberg, Edison Investment Research. Note: CO1 Comdty is Brent

We attribute this relationship to investors linking the value to the chance that the projects reach project sanction and to the eventual EBITDA margin captured by the projects. We believe that both are heavily related to the underlying LNG pricing that LNGL’s prospective tolling partners believe they will be able to achieve. LNGL is running long-term projects, for which the short-term oil price is not as important as we believe investors attribute it to be.

LNGL has tracked Brent in a similar way to other peers, so is not alone. General market sentiment has fallen, taking many companies with it. Cheniere Energy, Golar LNG and Kinder Morgan have all been victims alongside LNGL. It is worth noting that although the correlation with the oil price has been to a high level in the past, the degree of this correlation (as measured by R2) was particularly strong in 2015 (see Exhibit 4).

Exhibit 3: Correlation of share prices with Brent oil price (trailing six-month basis)

Exhibit 4: Coefficient of determination with Brent oil price (trailing six-month basis)

Source: Edison Investment Research, Bloomberg

Source: Edison Investment Research, Bloomberg

Exhibit 3: Correlation of share prices with Brent oil price (trailing six-month basis)

Source: Edison Investment Research, Bloomberg

Exhibit 4: Coefficient of determination with Brent oil price (trailing six-month basis)

Source: Edison Investment Research, Bloomberg

Looking ahead implies a slow recovery in LNG prices

Long-term LNG margins should recover given continued LNG demand, recovery in oil pricing and healthy US natural gas supply keeping a lid on Henry Hub pricing

While the headline Brent pricing may have seen good correlations with the share price in recent months, it should not necessarily be the best guide to the future value of the company. Once the project is running, the company’s value should be independent of LNG or gas pricing (assuming a purely tolling agreement model).

Until then, it is clear that investors are using the oil price as a proxy for long-term confidence in LNG/energy demand, which itself may be seen as a measure of confidence in the project going ahead. Should investors want to see relationships between oil, gas pricing and LNG realisations, we calculate a forward price for LNG margins based on the differential between Henry Hub and Japanese LNG pricing (with forward movements based on movements with Brent 30 days previously). This shows that the LNG margins have suffered more than Brent, mainly despite Henry Hub prices moving down in recent months.

In the longer term, LNG pricing should recover and increase to a greater extent than Henry Hub pricing, providing more robust LNG differentials for LNG traders. On these data, the differentials are unlikely to reach the levels hit in 2012, but we believe margins of around US$5/mmbtu are not at a level to allow LNGL’s tolling partners to make profits. Thus the differentials will have to expand from the prices implied by this analysis if any future US-based LNG projects are to be justified.


Exhibit 5: Brent vs LNG pricing over time

Exhibit 6: LNG differentials from Henry Hub, past and future

Source: Edison Investment Research, Bloomberg. Note: CO1 Comdty is Brent, JK1 is Japanese LNG pricing

Source: Edison Investment Research, Bloomberg. Note: Implied future is defined by historical relationship of LNG prices to Brent, using our assumptions on long-term Brent price of US$70/bbl. We note that forward curve is much flatter than Edison’s 2023 assumption of US$53/bbl

Exhibit 5: Brent vs LNG pricing over time

Source: Edison Investment Research, Bloomberg. Note: CO1 Comdty is Brent, JK1 is Japanese LNG pricing

Exhibit 6: LNG differentials from Henry Hub, past and future

Source: Edison Investment Research, Bloomberg. Note: Implied future is defined by historical relationship of LNG prices to Brent, using our assumptions on long-term Brent price of US$70/bbl. We note that forward curve is much flatter than Edison’s 2023 assumption of US$53/bbl

EPC contract moves project forward

Over recent months, LNGL signed a lump sum turnkey contract with KBR lead KSJV and set up strategic alliances with Siemens, Chart and EthosEnergy. These set clear benchmarks on costs for the project, with targets for contractors to complete work on time and on budget. Further clarification on “other costs”, including ramp-up gas, insurance, O&M fees and others, have also been clarified and set. These add up to a materially larger capex bill (see later section), but give a far greater confidence in the new estimates and involve a number of marquee names.

The contract was summarised by LNGL as follows:

An EPC Contract LSTK cost of US$4.354bn for four LNG trains and associated facilities.

EPC guaranteed production of 7.6mtpa, or 0.8mtpa greater than previous guidance.

The EPC Contract LSTK plant design utilises LNGL’s patented OSMR technology.

Installed capacity EPC contract cost/tonne range of US$495 to US$544 based on final design at FID.

LNG plant fuel gas consumption of 8%, or 92% feed gas production efficiency guaranteed.

EPC Contract LSTK price is valid to 31 December 2016 (was previously to 30 April 2016).

We note that “other costs” of 13.5-15.5% of the EPC contract are expected.

Next steps: Awaiting binding tolling agreements and FERC Notice to Proceed

An excerpt from the FERC website (in Exhibit 7) gives an idea of the progress of Magnolia through the regulatory process. On 18 April, the company received the FERC order, step 17 of 20 in the regulatory cycle. As a result, only a few steps remain before the Notice to Proceed.

We note that the milestones achieved are still high and do not show a number of the important steps that have also been taken. These include the Schedule for Environmental Review, and submission of the Draft Environmental Impacts statement (DEIS) and the Final Environmental Impact Statement (FEIS). Progress made on non-FTA status is also excluded.

Exhibit 7: EA pre-filing Environmental review process

Source: www.ferc.gov

The project is awaiting a number of major final milestones before financial close. Until these are complete, the company has put the EPC and related contracts on hold to minimise cash burn, while enabling the projects to ramp up quickly once all the pieces are in place.

In particular, we would highlight the following

Final regulatory approval will result in a FERC NTP, which is the final regulatory step required to allow the project to start up. The required regulatory waiting times have now elapsed, meaning the NTP may be issued at any time.

On the commercial side, the project has a 1.7mtpa contract with Meridian, but needs binding contracts with tolling partners for the remaining volumes before financial close. From the FERC documents “Magnolia states that it has executed non-binding agreements with four potential customers, Brightshore Overseas, Ltd, Gas Natural Fenosa, LNG Holdings Corp., and AES Latin America Development Ltd, for approximately 6.1 MTPA of firm capacity and approximately 0.3 MTPA of interruptible capacity collectively.” The underlying market conditions have meant delays in signing contracts vs previous expectations.

Financially, we believe the agreement with Stonepeak is on a firm footing. With Stonepeak having recently raised a further US$3.5bn (raising its assets to US$5.7bn), it has the capacity to increase its investment if it chooses without the Magnolia investment becoming an overly large part of its portfolio. We currently assume a cap of US$900m of equity at Magnolia and US$0 (zero) at Bear Head, for which Stonepeak requires a 14% pre-tax IRR.

Another step that would enhance the value of the project is non-FTA approval for volumes. We do not believe this is required for the project to get the go-ahead, but it would be useful for negotiations with tolling partners.

Changes to project and modelling

We have made a number of changes to our modelling, given recent newsflow and developments.

Increased capex: we have firmed up our capex estimates following the announcement of the contract, moving capex to US$4.4bn for four trains (two phases). This is a significant increase from our last assumptions, but the project lies on a firmer basis with higher guaranteed volumes (7.6mtpa, 0.8mtpa greater than previously). The cost per ton remains at the lower end of global projects, so should still be attractive to LNGL’s tolling partners looking for commercial advantage.

The additional cost does bring the funding of the development into greater focus. Even with debt funding doing the majority of the heavy lifting (and with Stonepeak’s contribution helping), the additional capital investment required means that LNGL will need to find equity funding of its own for the project (most probably for trains three and four). This may come from an additional equity partner in the Magnolia project itself (perhaps as part of a deal on the offtake) or at group level. However, shareholders are likely to see their existing holding in the project reduced to fund it. On a non-discounted basis, this shortfall amount totals around US$200m by 2019 for Magnolia (although this will depend on the tolling fees achieved and the equity LNGL retains as a result). In our valuation, we account for this cash shortfall by taking the NPV10 of the capital in the projects and applying a 15% cost of equity.

The addition of a success/production payment to the contractors was not something we had previously assumed. The payment of $0.07/mmbtu for production means cash outflow of up to US$30m per year from the project.

Exhibit 8: Magnolia at low end of cost curve

Exhibit 9: Global LNG NPV10 break-evens

Source: LNGL

Source: Ophir Energy. Note: Green bars are LNG schemes in which Ophir is involved.

Exhibit 8: Magnolia at low end of cost curve

Source: LNGL

Exhibit 9: Global LNG NPV10 break-evens

Source: Ophir Energy. Note: Green bars are LNG schemes in which Ophir is involved.

Increased revenues/EBITDA: we had previously anticipated EBITDA of US$2.00/mmbtu, as guided by the company in 2014. This has increased following the realisation that higher capital costs will require higher fees to achieve required rates of return. An analysis of peer projects indicates that US$2.75/mmbtu would still be at the lower end of the peer spectrum and should still encourage investment by tolling partners. However, recent market changes are likely compressing margins and we expect that tolling partners will require lower charges to make returns for their trading operations. For the moment, we assume a US$2.30/mmbtu margin, but are aware that there is notable uncertainty in this expectation.

We retain a tax rate of 38% (although in the fullness of time this may turn out to be too low as the company may be able to negotiate state tax breaks).

Exhibit 10: Summary of selected tolling fees at peers

Company

Client

Fee, US$ per mmbtu

Gas sourcing cost

Timescale

Cheniere

BG

$2.25-3.00

115% of Henry Hub

20 years

Cheniere

Gas Natural Fenosa

$2.49

115% of Henry Hub

20 years

Cheniere

KoGas

$3.00

115% of Henry Hub

20 years

Cheniere

GAIL

$3.00

115% of Henry Hub

20 years

Cheniere

Total

$3.00

115% of Henry Hub

20 years

Cheniere

Centrica

$3.00

115% of Henry Hub

20 years

Golar LNG

Ophir

$3.50 (+$0.5/for mods)

Source: Various

Debt financing: we had previously estimated that 70% of the project would be debt financed. We have increased this to 75% as the plants from Freeport LNG and Cameron LNG have reportedly achieved this level. IHS CERA has estimated that since 2000 LNG projects have on average used debt financing of 71% since 2000. The project will have low political risk (being in the US), although the new application of technology may require a small risk premium (albeit this should be offset materially by the EPC guarantee volumes). Looking at Exhibit 11, we would expect this percentage to need revision if the project is not fully derived through long-term contracts.

We continue to assume a debt cost of 7.5%, but note that the rate arrived at will have a material impact on the project, given the high percentage of debt funding. A 1% increase in this rate would decrease the total project NPV by c 4%. Given Stonepeak’s fixed return, it would have a greater impact on LNGL’s equity stake.

These factors result in a lower NPV for LNGL’s stake: the increased equity investment from Stonepeak and the higher capital investment for the project results in a lower NPV.

Exhibit 11: Debt can take on a greater role as long-term contracts increase as a percentage of output

Source: https://www.diw.de/documents/publikationen/73/diw_01.c.494837.de/dp1441.pdf

Delays at Bear Head

We have taken the opportunity to push Bear Head further into the future. While the project should be strongly value accretive for LNGL, the development process has not been as fast as we had expected and has delayed our timelines. A clear line of sight to gas supply is required before tolling partners can be brought in. However, the state of the site and progress on permitting (including a recent authorisation from the US DOE for gas exports to the project) should enable swift progress on the project once gas supply is secured. We note that options for gas supply remain either sourced from the Marcellus Shale in the US or from discoveries/prospects offshore Nova Scotia.

Non-FTA approval for Bear Head is encouraging

On 8 February, the US DOE issued final authorisation for Bear Head to export LNG derived from US-produced natural gas to countries without free trade agreements with the US. Bear Head is now the first and only proposed Canadian LNG export facility to obtain nonFTA authority and all the initial regulatory approvals to commence project construction, with approvals achieved in less than 12 months. The DOE also declared that no permit was required for any Canadian gas to go through US pipelines in transit to the site.

These elements remove a key risk for the project and its ability to source gas from a range of sources. Currently, we assume that gas will either come from onshore gas supplied from the US (probably shale gas from the Marcellus) or from offshore Nova Scotia. These permits now clear the way for the project to source from either of the sources and export globally, which should increase the attractiveness of the project to both tolling partners and potential equity partners.

Other news – personnel changes

On 4 April 2016, LNGL announced that Maurice Brand, founder and long-time MD, was stepping down. He is to be replaced by Gregory (Greg) Vesey, a professional with 35 years’ experience at Chevron where he was responsible for global gas marketing and trading activity including extensive LNG development work. His previous appointments covered the introduction of new technology, international operations and included commercial and execution responsibilities as well as liaising with stakeholders. Maurice Brand will continue as an executive director (based on his existing Employment Agreement) until his retirement by June 2017.

On 20 November 2015, LNGL announced the appointment of Anthony Gelotti as chief development officer based in Houston, Texas, US. He brings a wealth of experience from Chevron LNG supply and trading.

LNGL also announced that Mr John Baguley, chief operating officer for Magnolia LNG will assume the additional responsibilities of LNGL’s chief technical officer. John, who is based in Houston, replaced Mr Paul Bridgwood, who wished to remain in Perth and left the company on 30 November 2015.

On 18 August 2015, LNGL announced the appointment of Ms Kinga Doris as general counsel and joint company secretary, based in Houston, Texas, US.

Valuation

Following the changes to modelling, our valuation for the company falls materially. This is mainly due to the increased capex incurred at Magnolia (partially offset by expected increased EBITDA). We have not adjusted the riskings for the project, but note that Bear Head has been pushed out (even though non-FTA approval is a very encouraging step). This results in a NAV of A$1.0 or US$2.8/ADR, which is well above current market prices.

Exhibit 12: NAV summary

Asset

 

 

 

Net risked

Value

 

Country

Working Interest

CoS

value

risked

Risked

 

%

%

US$m

A$/share

US$/ADR

Net (debt)/cash (Dec 2015e)

78

0.2

0.6

G&A

(64)

(0.2)

(0.5)

Project development costs Jan-Jun 2016

(7)

(0.0)

(0.0)

Risked NPV of cost of raising equity Magnolia (assumed equity cost 15%)

(7)

(0.0)

(0.1)

Risked NPV of cost of raising equity Bear Head (assumed equity cost 15%)

(1)

(0.0)

(0.0)

Magnolia Trains 1&2

United States

40%

60%

199

0.6

1.6

Magnolia Trains 3&4

United States

40%

60%

124

0.3

1.0

Bear Head Trains 1&2

Canada

70%

20%

20

0.1

0.2

Bear Head Trains 3&4

Canada

70%

20%

8

0.0

0.1

Bear Head Trains 5&6

Canada

70%

0%

0

0.0

0.0

Fisherman's Landing

Australia

100%

0%

0

0.0

0.0

NAV

350

1.0

2.8

Source: Edison Investment Research

We employ this DCF-based approach given the pre-cash flow stage of the company, but would expect the shares to trade on an EV/EBITDA or P/E in line with peers as first cash flows approach. We note that infrastructure/utility-type companies continue to trade on healthy metrics. With LNGL holding a material stake in an 8mtpa project at Magnolia, throwing off perhaps US$800-900m of EBITDA per year, the value of the company has plenty of room to increase markedly as and when the project is launched.

Exhibit 13: P/E of infrastructure/utility-type peers

Exhibit 14: EV/EBITDA of peers

Source: Bloomberg, Edison Investment Research

Source: Bloomberg, Edison Investment Research

Exhibit 13: P/E of infrastructure/utility-type peers

Source: Bloomberg, Edison Investment Research

Exhibit 14: EV/EBITDA of peers

Source: Bloomberg, Edison Investment Research

Sensitivity to different tolling fees

Given the uncertainty over tolling fees, it is important to see the effect that varying the tolling fees would have. Given the fixed return demanded by Stonepeak, higher tolling fees will result in an expanded equity position for LNGL. Our analysis indicates that for every US$0.1/mmbtu increase in tolling fee, the value net to investors will increase by c 25% as the effect of the higher equity is magnified.

Exhibit 15: Sensitivity to headline tolling fee (US$/mmbtu)

2.20

2.30

2.40

2.50

2.60

2.70

Valuation A$

0.7

1.0

1.2

1.5

1.8

2.0

Valuation US$

2.1

2.8

3.5

4.3

5.0

5.7

Percentage ownership of project (Magnolia)

31.7%

40.0%

47.5%

53.0%

57.5%

61.0%

Change in unrisked NPV, Magnolia

(26%)

0%

28%

54%

80%

106%

Source: Edison Investment Research

Financials

With A$114m (US$81m) in the bank and no debt at end December 2015, the company is well funded to continue to progress its projects – it believes that the cash reserve can supply the company until 2018. As we discuss in the report, it will likely need some external (equity) finance to help fund the Magnolia project, even with the increased Stonepeak contribution and an increased level of debt funding available (in line with peers at 75%).

The critical junction for investors is the financial close, which will require a number of milestones to be crossed first, not least the signatures of tolling partners in sufficient volumes to make the project commercial.

Exhibit 16: Financial summary

 

 

A$'000s

2012

2013

2014

2015

2016e

2017e

June

 

 

IFRS

IFRS

IFRS

IFRS

IFRS

IFRS

PROFIT & LOSS

Revenue

 

 

0

0

0

0

0

135,100

Cost of Sales

831

190

275

668

497

109

Gross Profit

831

190

275

668

497

135,209

EBITDA

 

 

(17,431)

(13,540)

(23,781)

(86,774)

(111,279)

92,970

Operating Profit (before amort. and except.)

(17,498)

(13,595)

(23,832)

(86,884)

(111,389)

92,860

Intangible Amortisation

0

0

0

0

0

0

Exceptionals

0

0

0

0

0

0

Other

0

0

0

0

0

0

Operating Profit

(17,498)

(13,595)

(23,832)

(86,884)

(111,389)

92,860

Net Interest

831

189

(833)

627

496

(745)

Profit Before Tax (norm)

(16,667)

(13,407)

(24,665)

(86,257)

(110,893)

92,115

Profit Before Tax (FRS 3)

(16,667)

(13,407)

(24,665)

(86,257)

(110,893)

92,115

Tax

0

0

0

(50)

33

0

Profit After Tax (norm)

(16,667)

(13,407)

(24,665)

(86,307)

(110,860)

92,115

Profit After Tax (FRS 3)

(16,667)

(13,407)

(24,665)

(86,307)

(110,860)

92,115

Average Number of Shares Outstanding (m)

266.8

267.7

461.9

503.1

503.2

503.2

EPS - normalised

 

(0.1)

(0.1)

(0.1)

(0.2)

(0.2)

0.2

EPS - normalised and fully diluted

(0.1)

(0.1)

(0.1)

(0.2)

(0.2)

0.2

EPS - (IFRS)

 

 

(0.1)

(0.1)

(0.1)

(0.2)

(0.2)

0.2

Dividend per share

0.0

0.0

0.0

0.0

0.0

0.0

Gross Margin (%)

N/A

N/A

N/A

N/A

N/A

N/A

EBITDA Margin (%)

N/A

N/A

N/A

N/A

N/A

N/A

Operating Margin (before GW and except.) (%)

N/A

N/A

N/A

N/A

N/A

N/A

BALANCE SHEET

Fixed Assets

 

7,512

605

292

12,120

12,033

350,363

Intangible Assets

0

0

0

0

0

338,440

Tangible Assets

252

123

291

12,120

12,033

11,923

Investments

7,260

482

0

0

0

0

Current Assets

 

9,177

2,635

51,438

184,611

91,465

5,198

Stocks

0

0

0

0

0

0

Debtors

176

40

343

2,485

748

748

Cash

6,892

1,583

47,771

46,971

86,267

0

Other

2,109

1,012

3,324

135,155

4,450

4,450

Current Liabilities

 

(1,206)

(1,373)

(3,919)

(14,883)

(12,661)

(12,661)

Creditors

(1,206)

(1,373)

(3,412)

(14,880)

(12,652)

(12,652)

Short term borrowings

0

0

(507)

(3)

(9)

(9)

Long Term Liabilities

 

(324)

(301)

(210)

(239)

(112)

(155,061)

Long term borrowings

0

0

(12)

(9)

(6)

(154,955)

Other long term liabilities

(324)

(301)

(198)

(230)

(106)

(106)

Net Assets

 

 

15,159

1,566

47,601

181,609

90,725

187,839

CASH FLOW

Operating Cash Flow

 

(9,232)

(7,735)

(21,765)

(69,976)

(98,651)

98,079

Net Interest

(0)

(1)

(6)

(1)

(1)

(854)

Tax

0

0

0

0

0

0

Capex

(32)

(10)

(248)

(11,624)

(40)

(338,440)

Acquisitions/disposals

0

0

0

0

0

0

Financing

20,144

0

70,250

204,997

16

0

Dividends

0

0

0

0

0

0

Other

(9,802)

2,437

(2,043)

(124,196)

137,972

0

Net Cash Flow

1,078

(5,309)

46,188

(800)

39,296

(241,215)

Opening net debt/(cash)

(5,807)

(6,892)

(1,583)

(47,252)

(46,959)

(86,252)

HP finance leases initiated

0

0

0

0

0

0

Other

8

0

(519)

507

(3)

0

Closing net debt/(cash)

 

(6,892)

(1,583)

(47,252)

(46,959)

(86,252)

154,964

Source: Edison Investment Research, company accounts

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Frankfurt +49 (0)69 78 8076 960

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Germany

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280 High Holborn

London, WC1V 7EE

United Kingdom

New York +1 646 653 7026

245 Park Avenue, 39th Floor

10167, New York

US

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Level 25, Aurora Place

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New Zealand

The North American Income Trust — Update 26 April 2016

The North American Income Trust

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