FY Results for the Year Ending 31 December 2017

RNS Number : 0324J

Nostrum Oil & Gas PLC

27 March 2018

 

NOT FOR RELEASE, PUBLICATION OR DISTRIBUTION, IN WHOLE OR IN PART, IN, INTO OR FROM ANY JURISDICTION WHERE TO DO SO WOULD CONSTITUTE A VIOLATION OF THE RELEVANT LAWS OF THAT JURISDICTION

Amsterdam, 27 March 2018

Full Year Results for the Year Ending 31 December 2017

Nostrum Oil & Gas PLC (LSE: NOG) ("Nostrum", or "the Company"), an independent oil and gas company engaging in the production, development and exploration of oil and gas in the pre-Caspian Basin, today announces its full year financial results for the twelve months ending 31 December 2017, together with the 2017 Annual Report for Nostrum and its subsidiaries taken as a whole ("the Group").

2017 Financial and Operational highlights of the Group:

Financial

·     Revenue of US$405.5 million (2016: US$348.0 million)

·     EBITDA¹ of US$232.0 million (2016: US$194.0 million)

·     EBITDA margin of 57.2% (2016: 55.7%)

·     Net operating cash flows² of US$182.8 million (2016: US$202.1 million)

·     Closing cash³ for the period of US$127.0 million (2017: US$101.1 million)

·     Net debt of US$960.9 million (2016: US$857.9 million)

·     Total debt of US$1,087.9 million (2016: US$959.1 million)

·     Net debt / EBITDA ratio of 4.1x (2016: 4.4x)

·     Operating costs of US$4.1/bbl (2016: US$3.7/bbl)

·     Transport/boe cost reduced to US$4.8/bbl (2016: US$5.3/bbl)

·     Nostrum pushed outstanding debt maturities to 2022 through a successful refinancing campaign

·     New hedging agreement entered into in January 2018 equal to 9,000 boepd with a put strike price of US$60.0 until 31 December 2018

Operational

·     2017 average daily sales volumes of 37,844 boepd (2016: 39,043 boepd)

·     2017 average production after treatment of 39,199 boepd (2016: 40,351 boepd)

·     Construction of the third Gas Treatment Unit ("GTU3") continues and is expected to be completed in 2018

·   KazTransOil ("KTO") pipeline connection completed in Q2 2017 at a total cost of US$7 million significantly reducing crude oil transportation costs

·     Three producing wells brought online in 2017

·     2P reserve increase to 488 mmboe as at 1 January 2018 following Ryder Scott independent reserve report, up from 466 mmboe as at 1 January 2017

·     Contingent resources of 118.1 mmboe of liquids and 622 billion cubic feet of sales gas

Strategic focus for 2018:

·    Stabilise production by focusing drilling capex on production wells

·    Successfully implement low pressure system and commission GTU3 to increase liquid production

·    Recognise cost savings by targeting reductions in G&A and opex, and bring drilling costs and related capex as low as possible

·    Achieve 2P reserve growth through value accretive acquisitions of surrounding acreage

·    Following the completion of GTU3, focus on delivering shareholder value through generating post-tax free cash flow and reducing debt

Kai-Uwe Kessel, Chief Executive Officer of Nostrum Oil & Gas, commented:

"2017 was a challenging year operationally. We encountered a delay to the completion of GTU3 and some disappointing results from wells that watered out in one of our producing reservoirs, which led to a 3.1% decrease in sales volumes. However, we also received results that could open up a new northern area in the Chinarevskoye field, which suggests we have more reserves than initially thought in our producing field. We will be analysing these results further in 2018 to better understand our full reserve potential.

Financially, 2017 was more positive for Nostrum. We successfully refinanced all of our debt due in 2019 and now have no maturities until 2022. As we last went to market in 2014 when the oil price was over US$100 per barrel, a lower oil price environment meant that the cost of the refinancing in July 2017 was slightly higher. We refinanced when oil was below US$50 and we achieved a coupon of 8%. We were then able to bring this down in February 2018, when oil prices were above US$60 per barrel. Overall, I am very pleased that we are now fully refinanced and have no maturities coming due until 2022."

¹ Defined as profit before tax net of finance costs, foreign exchange loss/gain, ESOP, depreciation, interest income, other income and expenses 

² IFRS term based on indirect cash flow method     

³ Defined as cash and cash equivalents including current and non-current investments and excluding restricted cash                               

 

Conference call

Nostrum's management team will present the FY 2017 Results and will be available for a Q&A session with analysts and investors today at 2:00 pm UK time, 27 March 2018. If you would like to participate in this call, please register by clicking on the following link and following instructions: Results Call

Download: Full Year Results Presentation

Download: Consolidated Group Financials

Download: 2017 Annual Report

LEI: 2138007VWEP4MM3J8B29

Disclosure of inside information in accordance with Article 17 of Regulation (EU) 596/2014 (16 April 2014) relating to Nostrum Oil & Gas PLC and Zhaikmunai LLP

Further information

For further information please visit www.nog.co.uk 

Further enquiries

Nostrum Oil & Gas PLC - Investor Relations

Kirsty Hamilton-Smith

Amy Barlow

[phone]

[e-mail]                                                                                                    

Instinctif Partners - UK                                                                                                 

David Simonson

Laura Syrett

George Yeomans

+ 44 (0) 207 457 2020

Promo Group Communications - Kazakhstan

Asel Karaulova

Irina Noskova 

+ 7 (727) 264 67 37

Notifying person

Thomas Hartnett

Company Secretary

About Nostrum Oil & Gas

Nostrum Oil & Gas PLC is an independent oil and gas company currently engaging in the production, development and exploration of oil and gas in the pre-Caspian Basin. Its shares are listed on the London Stock Exchange (ticker symbol: NOG). The principal producing asset of Nostrum Oil & Gas PLC is the Chinarevskoye field, in which it holds a 100% interest and is the operator through its wholly-owned subsidiary Zhaikmunai LLP. In addition, Nostrum Oil & Gas holds a 100% interest in and is the operator of the Rostoshinskoye, Darjinskoye and Yuzhno-Gremyachinskoye oil and gas fields through the same subsidiary. Located in the pre-Caspian basin to the north-west of Uralsk, these exploration and development fields are situated approximately 60 and 120 kilometres respectively from the Chinarevskoye field.

Forward-Looking Statements

Some of the statements in this document are forward-looking. Forward-looking statements include statements regarding the intent, belief and current expectations of the Partnership or its officers with respect to various matters. When used in this document, the words "expects," "believes," "anticipates," "plans," "may," "will," "should" and similar expressions, and the negatives thereof, are intended to identify forward-looking statements. Such statements are not promises or guarantees, and are subject to risks and uncertainties that could cause actual outcomes to differ materially from those suggested by any such statements.

No part of this announcement constitutes, or shall be taken to constitute, an invitation or inducement to invest in the Company or any other entity, and shareholders of the Company are cautioned not to place undue reliance on the forward-looking statements. Save as required by the Listing Rules and applicable law, the Company does not undertake to update or change any forward-looking statements to reflect events occurring after the date of this announcement.

Significant news after the reporting period:

Hedging

On 4 January 2018, Nostrum entered into a hedging contract equating to production of 9,000 barrels of oil per day. The hedging contract is a zero-cost capped collar with a floor price of US$60.0. The Group has covered the cost of the floor price by selling a number of call options with different strike prices for each quarter; Q1:US$67.5; Q2:US$64.1; Q3:US$64.1; and Q4:US$64.1. The amount of upside given away has been capped through the purchase of a number of call options with different strike prices: Q1:US$71.5; Q2:US$69.1; Q3:US$69.6; and Q4:US$69.6. There were no upfront costs to the Company for the hedging contract. The hedging contract matures on 31 December 2018 and is settled in cash on a quarterly basis.

Tender Offer and Consent Solicitation

On 18 January 2018, Nostrum announced a conditional call for notes issued by Zhaikmunai LLP in respect of Zhaikmunai's 6.375% Senior Notes, due February 2019 and 7.125% Senior Notes, due November 2019 ("Existing Notes"). Following this announcement, management participated in a series of fixed income meetings with global investors during a one-week roadshow.

On 16 February 2018, the Company called US$353.2 million of Zhaikmunai's Existing Notes using the proceeds of a new US$400 million issue to satisfy the call. The new issue has a coupon of 7.00%, is non-callable for a period of three years with a tenor of seven years, matures in February 2025 and was issued at a discount to par. The new issue saw significant demand from a wide variety of institutional investors. Proceeds from the new issue will be used to fund the Tender Offer for the Existing Notes, fees and expenses associated with the transaction and general corporate purposes. For further details please visit Regulatory News.

Operational Overview:

Sales Volumes Split:

The sales volumes split for FY 2017 was as follows:

Products	FY 2017 sales volumes (boepd)	FY 2017 Product Mix (%)
Crude Oil & Stabilised Condensate	15,292	40.4%
LPG (Liquid Petroleum Gas)	4,618	12.2%
Dry Gas	17,934	47.4%
Total	37,844	100.0%

Drilling

2017 Drilling overview

Drilling

·     43 wells producing at the Chinarevskoye field as at 31 December 2017 - 22 oil wells and 21 gas condensate wells

·     Completion of 2017 drilling programme saw three new production wells brought online in 2017

·     During Q4 2017, drilling activity was finished on two wells, which are currently undergoing stimulation and testing

·     Currently, there are two drilling rigs on field site drilling two new production wells. A third rig will arrive and be operational from the beginning of H2. This will allow for up to eight wells to be drilled during 2018. The first four wells drilled in 2018 will all be new production wells.

·     Drilling capex for 2018 is budgeted to be below US$90 million

Production schedule

Based on the current drilling programme stated above and taking into account the current oil price, we can provide the following production guidance. Should oil prices deviate materially, the production guidance will be updated accordingly:

·     2018 - Management estimates production will be flat over the year at around 37,000 boepd, taking into account the time it will take (three months) to bring the two new production wells currently being drilled online, in addition to the three-week shutdown required to link GTU1&2 to GTU3 in Q2 2018

·     2019 - Ryder Scott guidance assumes average production of 56,087 boepd

·     2020 - Ryder Scott guidance assumes average production of 68,211 boepd

·     2021 - Increasing the rig count to six at the field site to build production towards filling capacity beyond 2021

Progress on development of GTU3

Completion of GTU3 remains scheduled for 2018. When the GTU3 project is finalised, it will more than double raw gas processing capacity to 4.2 billion cubic metres per annum.

In Q4 2017, the construction of GTU3 entered the final mechanical construction phase. Pipe work welding, hydro-testing, cable-pulling and the completion of works inside the buildings, including process and compression units, has been a priority with the onset of winter conditions. Tying into GTU1&2 and hydro-testing are all forecast for Q2 2018.

The below figures reflect all future cash payments excluding VAT:

GTU3 Cash (excl VAT)	as at 31 December 2017
Expenditure remaining in 2018	US$64 million

Reserves and resources

	31 December 2016			1 January 2018
	Chinarevskoye	Trident	Total	Chinarevskoye	Trident	Total
Proven	147	0	147	124	0	124
Probable	233	87	320	234	131	365
2P	379	87	466	358	131	488

As at 1 January 2018, the Company's independent reserve reviewer, Ryder Scott, confirmed the Group's 2P reserves of 488 mmboe. 1P reserves at the Chinarevskoye license were 124 mmboe. The Ryder Scott Reserves Report also confirmed Nostrum has 2P reserves of 131 mmboe in the Rostoshinskoye, Darjinskoye and Yuzhno-Gremyachinskoye fields ("Trident Licenses")  adjacent to the Chinarevskoye licence, which were acquired for a consideration of US$16 million in 2013. This is in addition to having approximately 118 mmboe and 622 billion cubic feet of sales gas contingent resources.

Nostrum has been appraising, developing and producing crude oil and gas condensate in North-western Kazakhstan for over a decade. This has allowed the Company to accumulate considerable knowledge of the Chinarevskoye field and surrounding regional geology. The Company seeks to leverage this competitive advantage to pursue value-accretive transactions which enhance our commercial reserve base and allow the company to fully utilise its infrastructure beyond 2021.

Chairman's Statement - Atul Gupta

Our Vision

In 2018, we aim to ensure we establish the solid foundations on which Nostrum can become a leading London-listed E&P company. Nostrum's goal is to fully utilise its significant raw gas reserves and processing infrastructure in North-western Kazakhstan to deliver sustainable value to its shareholders. We are on target to complete our third Gas Treatment Unit ("GTU3") in 2018, which will give the Company the capacity to process over 4 billion cubic metres of raw gas per annum. Our mid-term aim is to fill our facilities to maximum capacity. To achieve this, we need to combine expansion through organic growth of our existing asset base alongside carefully considered acquisitions, while maintaining our high level of capital discipline.

From a social responsibility perspective, we will continue to invest in the local community and maintain our employee training programme to adapt to new technologies and industry standards. We are absolutely committed to improving our safety standards both for our own employees and third party contractors. From an environmental standpoint, we are constantly seeking to minimise the environmental footprint of our business, while also re-investing our cash to help create a cleaner environment in all the areas where we operate, to ensure we are a business designed for the future. This investment in our people, standards and infrastructure leaves us well placed to grow in a scalable and sustainable way.

Operational Performance

2017 has been a challenging year operationally. We experienced drilling results that were below our expectations, but we also achieved some unexpected successes. The biggest challenge we faced was a higher decline in production than we had anticipated. This was primarily due to the loss of two producing wells and the inability to bring on new production wells in time to replace this lost production. A priority for 2018 is to learn from this experience, and to recover our planned growth path. We will also be working hard to complete the construction of GTU3 once we are through the winter months. As a result of the 2017 production decline, we will focus first on drilling four production wells in the first half of 2018. The second half of the year will depend on the results we achieve from existing wells under test production and new production wells. 2018 is an opportunity for us to demonstrate that we can extract the significant hydrocarbon potential of the Chinarevskoye field economically. In the Rostoshinskoye field, we also achieved some success which could lead to a material upgrade in our expectations from this field. We will further analyse the potential of this field and the other two Trident fields once we have stabilised production at Chinarevskoye.

Financial Performance

Our 2017 financial performance was impacted by our operations and the continued oil price volatility. However, we continued to reduce costs and will aim to maintain this control through 2018. We have continued to enhance the stability of our balance sheet. We successfully refinanced almost two thirds of our debt during 2017 and completed the final part in the first quarter of 2018. As a result, we have no debt maturities coming due until July of 2022 and this provides a solid foundation from which to focus on the operational side of the business and increasing production over the next four years. To ensure that we are not over-exposed to oil price volatility during 2018, we have entered into a hedge on 9,000 boepd with a floor price of US$60 per barrel for the rest of the year. This reaffirms that we are able to fully finance GTU3 completion under any oil price scenario.

Governance

Nostrum attaches great importance to achieving best practice corporate governance standards. I took over the Chairmanship of the Board in April 2017 under challenging circumstances following the departure of the Executive Chairman, Frank Monstrey. Mr Monstrey resigned from the Board as a consequence of a freezing order and charging order obtained by BTA Bank on Nostrum shares held by two companies owned by him. Such freezing order and charging order were subsequently lifted in June 2017 pursuant to a settlement between Mr Monstrey and BTA Bank, as a result of which BTA Bank became a shareholder in Nostrum.  Nostrum was not a party to any legal proceedings between BTA Bank and Mr Monstrey or his companies. However, as a result of these developments the Board deemed it essential to stabilise the Company's position going forward and took the following steps during 2017 in order to do so. First, we improved our governance structure and independence. We welcomed Martin Cocker as a non-executive director and established, for the first time in the Company's history, an equal balance of four independent to four non-independent directors. In addition, the Board welcomed Michael Calvey, who represents Baring Vostok's 17% stake in the Company. Baring Vostok increased their holding in Nostrum from 15% to 17% during the fourth quarter of 2017. Baring Vostok has been an investor since 2009 and, alongside Mayfair, brings a wealth of experience investing in the former Soviet Union. Second, we entered into a mutual waiver of claims with BTA in January 2018, which removes any risk of the Company being made party to any of the claims made by BTA. I believe we have an excellent Board with a broad range of expertise and experience that was able to navigate us through some difficult periods in 2017. I look forward to leading Nostrum into 2018 and beyond.

Corporate and Social Responsibility

CSR is a central tenet of Nostrum's business ethic. We recognise that we need to ensure that high standards of QHSE are established and maintained. We are also cognisant that, due to the nature of the Oil & Gas industry, our business must operate with the right safeguards to prevent damage to the environment and danger to our employees.

During 2017, we saw our Lost Time Injury Frequency increase to 2.48 and we will be focusing on this acutely during 2018 to ensure the safety of our employees and contractors is constantly assessed and improved. In relation to emissions and environmental impact, I am pleased to note that an independent environmental audit found Nostrum complied with all relevant regulatory and legislative requirements in relation to environmental monitoring. While we did see an increase in our GHG emissions intensity ratio, this was primarily a result of commissioning a gas turbine power station, which we anticipate will help reduce our environmental impact in the future. We remain focused on reducing our GHG emissions, and also developing a better understanding of and response to climate change risks in 2018.

Our people

We have a strong team with a wealth of experience on the Chinarevskoye field. I was happy to see their commitment to tackling the Company's financial and operational issues over the last 12 months. In order to achieve the objectives we have set ourselves for 2018 and beyond, we will strive to ensure that Nostrum continues to be an attractive place to work. We place a high level of importance on developing the skills of our local employees through training and sponsorship, with 947 out of 989 staff employed by the Nostrum Group based in Kazakhstan. In addition, we seek to ensure we can retain our key talent while also being able to attract new staff. The quality and commitment of our people will be critical to us achieving our goals for 2018.

Future Growth

2018 promises to be a very exciting year for Nostrum. We look forward to bringing the Company's processing capacity to over 100,000 boepd and we are seeking to build a low cost base from which to realise the full value of the licences we own. This requires us to focus on stabilising production in the first half of the year, before looking at expanding production in the second half through advancing our drilling campaigns, while preserving our disciplined approach to capital. We have now completed all our refinancing, allowing us to focus purely on the critical operational targets for 2018.

CSR priorities for 2018

·     Reducing health & safety incidents

·     Continuing to finance local social infrastructure projects

·     Targeting a reduction in our emissions intensity ratio

·     Developing a better understanding of and response to climate change risks

Atul Gupta

Chairman

Chief Executive's statement - Kai-Uwe Kessel

Q: How did Nostrum perform in 2017?

A: 2017 was a challenging year operationally. We encountered a delay to the completion of GTU3 and some disappointing results from wells that watered out in one of our producing reservoirs, which lead to a 3.1% decrease in production. However, we also received results that could open up a new northern area in the Chinarevskoye field, which suggests we have more reserves than initially thought in our producing field. We will be analysing these results further in 2018 to better understand our full reserve potential.

Financially, 2017 was more positive. We successfully refinanced all of our debt due in 2019 and now have no maturities until 2022. As we last went to market in 2014, when the oil price was over US$100 per barrel, a lower oil price environment meant that the cost of the refinancing in July 2017 was slightly higher. We refinanced when oil was below US$50 and we achieved a coupon of 8%. We were then able to bring this down in February 2018 when oil prices were above US$60 per barrel. Overall, I am very pleased that we are now fully refinanced and moved our debt maturities out to 2022.

Q: How strong is Nostrum's financial position?

A: The Company is now in a strong position in relation to its balance sheet with no debt maturities until 2022. This gives the Company an excellent platform to focus on delivering all our operational objectives over the coming months and years to stabilise and then ramp up our production.

We have over US$100 million of cash on our balance sheet, which gives us plenty of headroom to both finalise GTU3 and to then focus on executing a smooth drilling programme. We will look to preserve the balance sheet to avoid running our cash balances too low while ramping up the drilling programme.

Q: Can you provide an update on the timeline for the GTU3 project?

A: We look forward to completing GTU3 during 2018 and to seeing the benefits from additional LPG production. The hydro-testing and link up with GTU1 & 2 remain on target for Q2.

Q: What are your expectations for production in 2018?

A: We had a challenging year production-wise in 2017, so the key focus for H1 2018 is to stabilise production by drilling four production wells. The time it will take to drill these four wells means that production will start to stabilise and increase in H2 2018. Stabilising then growing production, is our primary focus in 2018 as increased sales volumes will lead directly to improved cash flows and drive further value for the Company.

There is no doubt that in our Chinarevskoye and Trident fields we have a very significant amount of hydrocarbons, which was confirmed by an increase in overall 2P reserves following an independent review. We need to maximise the full potential of our fields by efficiently and quickly extracting as many hydrocarbons as possible prior to the end of our licences in 2031-2033. In 2017, although our proven reserves declined, we have seen an increase in our 2P reserves as we continually improve our understanding of the field. An example of this is the potential to unlock reserves in the northern area of the field where historically no reserves have been booked. Well 724 has shown there is the possibility of additional near-term production from this area.

Q: What are your development plans for Chinarevskoye and what are your expectations for costs?

A: We aim to fully develop the Chinarevskoye field prior to the end of the licences in 2031-2033 and we have shown over the last two years that we employ strong capital discipline. Our aim is to keep the operating cost base as low as possible and maintain that level whilst we grow. The target is to decrease operating costs on a boe basis over the medium term.

We also plan to keep our drilling costs as low as possible. After the completion of GTU3, drilling expenditure will become the single largest cost for the Company over the next four years. Therefore, it is imperative to closely control these costs. This requires focus across the whole business, from finance to procurement through to drilling, to ensure we are negotiating the most beneficial contractual terms and operating the rigs in an efficient manner.

Q: What is the status of your Rostoshinskoye, Darjinskoye and Yuzhno-Gremyachinskoye (Trident) fields?

A: We continue to see potential in the Trident fields and will aim to develop these over the coming years. We were encouraged by the initial testing results from the Rostoshinskoye 3 well which provided a basis for us to believe there are more hydrocarbons than had previously been anticipated under this licence. Our independent reserve review found 2P reserves at the three Trident fields amounting to 131 mmboe. Whilst our current focus is on near-term production at Chinarevskoye, we will seek to set out a development strategy for Trident during 2018 to maximise its value.

The licence providing for the exploration of hydrocarbons from the Rostoshinskoye field expired in February 2017 and the exploration licences for Darjinskoye and Yuzhno-Gremyachinskoye expired in December 2017. Applications for extension of the three licences have been submitted to the Competent Authority.

Q: Are you still looking at M&A opportunities?

A: Our focus on M&A is very specific. We are only currently looking at the area around the infrastructure we have built. In the same way we acquired Trident, we will look to analyse local licences to determine whether they could tie in to our infrastructure. At the same time, we will only pursue assets we consider to be value-accretive to Nostrum as we have plenty of existing reserves to focus on in the near-term within the Chinarevskoye field. Thus, our approach to M&A is judiciously balanced between the returns we can generate from our own licences and the added value of any new licences.

Q: How did Nostrum deliver against its QHSE commitments during the year?

A: This is an area we intend to focus on more during 2018. We are disappointed with our Total Recordable Injury Frequency results and are committed to fully investigating and addressing what caused the increase in 2017 and how we can resolve these issues. We believe it was primarily as a result of increased construction activity throughout the year and contractor road traffic incidents. We will review our contractor management systems and focus on implementing improved road safety procedures amongst all of our contractors, particularly in relation to the transport companies we engage. We plan to review working conditions to ensure compliance with established health and safety requirements, as well as conduct meetings with contractors to improve safety awareness. This will be complemented by the further development and implementation of our 2018 HSE Competency Program which will be focused on continuous training of Group personnel and contractors.

While we saw an increase in our GHG emission intensity ratio in 2017, this was largely as a result of emissions associated with the commissioning of a gas turbine power station, which we anticipate will have many future benefits. The electricity generated by this station is used to power our internal operations including drilling rigs and is also supplied to administrative and household consumers. The fact that we have replaced old diesel generators which used to power the drilling rigs at site with electricity from our power plant has led to an overall reduction in emissions at field site.

Q: What will your capital allocation priorities be once production is ramped up? Will you reinstate the dividend?

A: The near-term focus is production growth to deliver increased cash flow and deleverage the business. At the same time, we will look to add reserves both organically and inorganically if the returns can be justified. We have invested over US$1 billion into gas processing infrastructure and aim to maximise the value of these assets through filling them for as long as possible. The assets are unique to North-western Kazakhstan, which is an area rich in wet gas, and we will ensure that they realise maximum value over the coming years.

Kai-Uwe Kessel

Chief Executive Officer

Financial review and update (all figures in US$m unless otherwise stated):

	FY 2017	FY 2016	Change FY 16 to FY 17
Revenue	405.5	348.0	57.6
EBITDA (1)	232.0	194.0	38.0
EBITDA Margin (%)	57.2	55.7	1.5
Net cash used in investing activities (2)	192.4	200.4	(7.9)
Cash and Equivalents (3)	127.0	101.1	25.8
Net Debt (4)	960.9	857.9	103.0
Net Income	(23.9)	(83.0)	59.1
Average Brent crude oil price on which Nostrum based its sales (US$/bbl)	54.7	45.1	9.6

⁽¹⁾  Defined as profit before tax net of finance costs, foreign exchange loss/gain, ESOP, depreciation, interest income, other income and expenses.

⁽²⁾  IFRS term based on indirect cash flow method

⁽³⁾  Defined as cash and cash equivalents including current and non-current investments and excluding restricted cash

⁽⁴⁾  Defined as total debt minus cash and cash equivalents

Results of operations for the years ended 31 December 2017 and 2016

The table below sets forth the line items of the Group's consolidated statement of comprehensive income for the years ended 31 December 2017 and 2016 in US Dollars and as a percentage of revenue.

	For the year ended 31 December
In thousands of US dollars	2017	% of revenue	2016	% of revenue
Revenue	405,533	100.0%	347,983	100.0%
Cost of sales	(177,246)	43.7%	(182,180)	52.4%
Gross profit	228,287	56.3%	165,803	47.6%
General and administrative expenses	(33,303)	8.2%	(34,758)	10.0%
Selling and transportation expenses	(66,441)	16.4%	(75,681)	21.7%
Taxes other than income tax	(19,967)	4.9%	(20,175)	5.8%
Finance costs	(59,752)	14.7%	(41,709)	12.0%
Employee share options - fair value adjustment	2,099	0.5%	99	0.0%
Foreign exchange loss, net	(688)	0.2%	(390)	0.1%
Loss on derivative financial instruments	(6,658)	1.6%	(63,244)	18.2%
Interest income	374	0.1%	461	0.1%
Other income	4,071	1.0%	2,191	0.6%
Other expenses	(22,055)	5.4%	1,864	0.5%
Profit/(loss) before income tax	25,967	6.4%	(65,539)	18.8%
Income tax expense	(49,849)	12.3%	(17,481)	5.0%
Loss for the year	(23,882)	5.9%	(83,020)	23.9%
Other comprehensive income/(loss)	825	0.2%	(70)	0.0%
Total comprehensive loss for the year	(23,057)	5.7%	(83,090)	23.9%

General note

For the year ended 31 December 2017 (the "reporting period") total comprehensive loss decreased by US$60.0 million to US$23.1 million (FY 2016: US$83.1 million). The loss is mainly driven by higher income tax as well as transaction costs on refinancing and one-off items in other expenses, as explained in more detail below.

Revenue

The Group's revenue increased by 16.5% to US$405.5 million for the reporting period (FY 2016: US$348.0 million). This is mainly explained by the increase in the average Brent crude oil price from 45.1 US$/bbl during 2016 to 54.2 US$/bbl during the reporting period. The pricing for all the Group's crude oil, condensate and LPG is, directly or indirectly, related to the price of Brent crude oil.

Revenues from sales to the Group's largest three customers amounted to US$200.4 million, US$102.8 million and US$30.1 million respectively (FY 2016: US$109.5 million, US$92.9 million and US$38.1 million).

The Group's revenue breakdown by products and sales volumes for the reporting period and FY 2016 is presented below:

	For the year ended 31 December
In thousands of US dollars	2017	2016	Variance	Variance, %
Oil and gas condensate	261,069	226,357	34,712	15.3%
Gas and LPG	144,464	121,626	22,838	18.8%
Total revenue	405,533	347,983	57,550	16.5%
Sales volumes (boe)	13,813,060	14,250,695	(437,635)	(3.1)%
Average Brent crude oil price (US$/bbl)	54.7	45.1

The following table shows the Group's revenue breakdown by export/domestic sales for the reporting period and FY 2016:

	For the year ended 31 December
In thousands of US dollars	2017	2016	Variance	Variance, %
Revenue from export sales	262,767	244,586	18,181	7.4%
Revenue from domestic sales	142,766	103,397	39,369	38.1%
Total	405,533	347,983	57,550	16.5%

Cost of sales

	For the year ended 31 December
In thousands of US dollars	2017	2016	Variance	Variance, %
Depreciation, depletion and amortisation	120,692	129,425	(8,733)	(6.7)%
Repair, maintenance and other services	18,960	18,932	28	0.1%
Payroll and related taxes	17,652	13,290	4,362	32.8%
Other transportation services	8,335	6,843	1,492	21.8%
Materials and supplies	6,333	4,649	1,684	36.2%
Well workover costs	4,159	3,928	231	5.9%
Environmental levies	375	1,071	(696)	(65.0)%
Change in stock	297	2,047	(1,750)	(85.5)%
Other	443	1,995	(1,552)	(77.8)%
Total	177,246	182,180	(4,934)	(2.7)%

Cost of sales decreased by 2.7% to US$177.2 million for the reporting period (FY 2016: US$182.2 million). The decrease is primarily explained by the decrease in depreciation referred to below, partially offset by increases in payroll and related taxes, other transportation services and materials and supplies. On a boe basis, cost of sales did not change materially and amounted to US$12.83 for the reporting period (FY 2016: US$12.78) and cost of sales net of depreciation per boe increased marginally by US$0.39, or 10.5%, to US$4.09 (FY 2016: US$3.70).

Depreciation, depletion and amortisation decreased marginally by 6.7% to US$120.7 million for the reporting period (FY 2016: US$129.4 million). Depreciation is calculated applying units of production method. Decrease of depreciation in 2017 in comparison with prior period is a consequence of the ratio change between the volumes produced and the proven developed reserves as well as addition to O&G assets in the amount of US$219.7 million during reporting period.

Payroll and related taxes increased by 32.8% to 17.7million for the reporting period (FY 2016: US$13.3 million). This mainly resulted from increase in the headcount across operations.

Other transportation services increased by 21.8% to US$8.3 million for the reporting period (FY 2016: US$6.8 million). Such an increase is explained by the fact that in 2017 the Group completed next stage of transfer of services previously provided within the Group to outsourcing and the service costs now include, for example, vehicle rental fare.

Materials and supplies increased by 36.2% to US$6.3 million for the reporting period (FY 2016: US$4.6 million). These expenses include spare parts and other materials for repairs and maintenance of the facilities, specifically for the gas treatment facility and wells. These costs fluctuate depending on the timing of the periodic scheduled maintenance works.

Taxes other than income tax

	For the year ended 31 December
In thousands of US dollars	2017	2016	Variance	Variance, %
Royalties	15,724	11,910	3,814	32.0%
Export customs duty	3,864	5,533	(1,669)	(30.2)%
Government profit share	248	2,582	(2,334)	(90.4)%
Other taxes	131	150	(19)	(12.7)%
Total	19,967	20,175	(208)	(1.0)%

Royalties, which are calculated based on production and market prices for the different products, increased by 32.0% to US$15.8 million for the reporting period (FY 2016: US$11.9 million), which is largely due to the increase in the hydrocarbon prices.

Export customs duty on crude oil decreased by 30.2% to US$3.8 million for the reporting period (FY 2016: US$5.5 million), mainly due to the decrease of export sales and the increase of domestic sales which are not subject to export duties.

Government profit share decreased by 90.4% to US$0.2 million for the reporting period (FY 2016: US$2.6 million).

General and administrative expenses

	For the year ended 31 December
In thousands of US dollars	2017	2016	Variance	Variance, %
Payroll and related taxes	13,578	13,313	265	2.0%
Professional services	11,095	11,868	(773)	(6.5)%
Depreciation and amortisation	2,294	2,160	134	6.2%
Business travel	1,487	3,695	(2,208)	(59.8)%
Insurance fees	1,640	1,129	511	45.3%
Lease payments	797	694	103	14.8%
Communication	411	484	(73)	(15.1)%
Materials and supplies	363	353	10	2.8%
Bank charges	221	346	(125)	(36.1)%
Transportation services	242	153	89	58.2%
Other	1,175	563	612	108.7%
Total	33,303	34,758	(1,455)	(4.2)%

General and administrative expenses decreased by 4.2% to US$33.3 million for the reporting period (FY 2016: US$34.8 million). This was mainly driven by US$2.2 million or 59.8% decrease in business travel expenses from US$3.7 million in 2016 to US$1.5 million in 2017.

Selling and transportation expenses

	For the year ended 31 December
In thousands of US dollars	2017	2016	Variance	Variance, %
Loading and storage costs	26,940	33,219	(6,279)	(18.9)%
Transportation costs	20,160	24,861	(4,701)	(18.9)%
Marketing services	14,363	14,138	225	1.6%
Payroll and related taxes	2,033	1,234	799	64.7%
Other	2,945	2,229	716	32.1%
Total	66,441	75,681	(9,240)	(12.2)%

Selling and transportation expenses decreased by 12.2% to US$66.4 million for the reporting period (FY 2016: US$75.7 million), due primarily to decrease in oil transportation costs resulting from successful connection to the KTO pipeline.

Finance costs

	For the year ended 31 December
In thousands of US dollars	2017	2016	Variance	Variance, %
Interest expense on borrowings	42,756	39,446	3,310	8.4%
Transaction costs	15,709	-	15,709	-
Unwinding of discount on amounts due to Government of Kazakhstan	866	885	(19)	(2.1)%
Unwinding of discount on abandonment and site restoration provision	225	327	(102)	(31.2)%
Unwinding of discount on social obligations liability	40	850	(810)	(95.3)%
Finance charges under finance leases	156	201	(45)	(22.4)%
Total	59,752	41,709	18,043	43.3%

Finance costs decreased by 22.4% to US$59.8 million for the reporting period (FY 2016: US$41.7 million) mainly due to transactions costs on bonds refinancing.

Other

Loss on derivative financial instruments amounted to US$6.7 million in the reporting period and relates to fair value of the hedging contract covering oil sales. Based on the contract the Group has bought a put, which protects it against any fall in the price of oil below US$49.16/bbl. Movement in fair value of financial derivative instruments is disclosed in Note 29 of the Consolidated financial statements included in this report.

Other expenses increased to US$22.1 million for the reporting period (FY 2016: US$1.9 million). Such a significant increase in other expenses is explained by non-recurring business development expenses incurred in 2017 in relation to potential acquisitions of oil and gas exploration and appraisal assets in Kazakhstan, as well as reversal in 2016 of the accruals under subsoil use agreements based on the changes in the supplements to the subsoil use agreements and the adjusted work programs.

Income tax expense increased by US$32.3 million to US$49.8 million for the reporting period (FY 2016: US$17.5 million). The increase in income tax expense was primarily driven by higher deferred tax expenses in the current period, because of accelerated tax depreciation of oil & gas assets for tax purposes.

Liquidity and capital resources

During the period under review, Nostrum's principal sources of funds were cash from operations and amounts raised under the 2017 Notes. Its liquidity requirements primarily relate to meeting ongoing debt service obligations (under the 2012 Notes, 2014 Notes and the 2017 Notes) and to funding capital expenditures and working capital requirements.

Cash Flows

The following table sets forth the Group's consolidated cash flow statement data for the reporting period and FY 2016:

	For the year ended 31 December
In thousands of US dollars	2017	2016
Cash and cash equivalents at the beginning of the year	101,134	165,560
Net cash flows from operating activities	182,788	202,106
Net cash used in investing activities	(192,391)	(200,336)
Net cash from/(used in) financing activities	34,589	(66,323)
Effects of exchange rate changes on cash and cash equivalents	831	127
Cash and cash equivalents at the end of the year	126,951	101,134

Net cash flows from operating activities

Net cash flow from operating activities was US$182.8 million for the reporting period (FY 2016: US$202.1 million) and was primarily attributable to:

•       profit before income tax for the reporting period of US$26.0 million (FY 2016: loss before income tax of US$65.5 million), adjusted by a non-cash charge for depreciation, depletion and amortisation of US$123.0 million (FY 2016: US$131.6 million), finance costs of US$59.8 million (FY 2016: US$40.9 million), and loss on derivatives of US$6.7 million (FY 2016: US$63.2million).

•       a US$18.8 million decrease in working capital (FY 2016: US$15.8 million increase) primarily attributable to an increase in prepayments and other current assets of US$5.7 million (FY 2016: a decrease of US$22.2 million), a decrease in trade payables of US$4.6 (FY 2016: an increase of US$2.0 million) and a decrease in other current liabilities of US$1.6 million (FY 2016: a decrease of US$12.3 million).

•       income tax paid of US$15.9 million (FY 2016: US$9.5 million).

Net cash used in investing activities

The substantial portion of cash used in investing activities is related to the drilling programme and the construction of a third unit for the gas treatment facility.

Net cash used in investing activities for the reporting period was US$192.4 million (FY 2016: US$200.3 million) due primarily to costs associated with the drilling of new wells of US$57.5 million for the reporting period FY 2016: US$47.9 million), costs associated with the third gas treatment unit of US$157.5 million (FY 2016: US$123.3 million), and costs associated with Rostoshinskoye, Darjinskoye and Yuzhno-Gremyachinskoye fields of US$3.6 million (FY 2016: US$5 million).

Net cash from/(used) in financing activities

Net cash from financing activities during the reporting period made up US$34.6 million, and was mainly represented by proceeds from issue of 2017 Notes in the amount of US$725 million, offset by the early redemption of 2012 Notes and 2014 Notes totalling US$606.8 million, the fees and premium paid for the arrangement of these transactions in the amount of US$27.0 million, and the payment of US$57.0 million of the finance costs on the Group's 2012 Notes and 2014 Notes. Net cash used in financing activities during FY 2016 made up US$66.3 million, which was primarily attributable to the US$65.4 million of the finance costs paid on the Group's 2012 Notes and 2014 Notes.

Commitments

Liquidity risk is the risk that the Group will encounter difficulty raising funds to meet commitments associated with its financial liabilities. Liquidity requirements are monitored on a regular basis and management seeks to ensure that sufficient funds are available to meet any commitments as they arise. The table below summarises the maturity profile of the Group's financial liabilities as at 31 December 2017 based on contractual undiscounted payments:

As at 31 December 2017	On demand	Less than 3 months	3-12 months	1-5 years	More than 5 years	Total
Borrowings	-	20,482	61,445	1,297,688	1,900	1,381,515
Trade payables	43,593	-	13,262	-	-	56,855
Other current liabilities	17,274	-	-	-	-	17,274
Due to Government of Kazakhstan	-	258	773	4,124	8,505	13,660
	60,867	20,740	75,480	1,301,812	10,405	1,469,304

Capital commitments

During the reporting period, Nostrum's cash used in capital expenditures for purchase of property, plant and equipment (excluding VAT) was approximately US$188.1 million (FY 2016: US$192.8 million). This mainly reflects costs associated with the construction of the third gas treatment unit, drilling costs and other field infrastructure development projects.

Gas Treatment Facility

Following the successful completion of the first phase of the gas treatment facility, consisting of two units, the Group is constructing a third unit for it. The construction of GTU3 is important for implementing the Group's strategy to increase operating capacity and as a result increase production and processing of liquid hydrocarbons. Management estimates, based on the production profile of both proved and probable reserves reported in the 2017 Ryder Scott Report and assuming the successful completion of the second phase of the gas treatment facility in 2018, that the Company's annual production will gradually increase from 2017 onwards. The remaining costs for the completion of GTU3 are estimated at US$64 million.

Drilling

Drilling expenditures amounted to US$57.5million for the reporting period (FY 2016 US$47.9 million). After the completion of GTU3, is expected that the drilling expenditure will become the primary driver of the Company's investing activities.

Dividend Policy

The Group currently pays no dividend. This will be reviewed annually by the Board.

Five-year summary

In millions of US$ (unless mentioned otherwise)	2017	2016	2015	2014	2013
EBITDA Reconilliation
Profit/(loss) before income tax	26.0	(65.5)	72.3	311.7	362.0
Add Back:
Finance costs	59.8	41.7	46.0	61.9	43.6
Finance costs - reorganisation1	-	-	1.1	29.6	-
Employee share options - fair value adjustment	(2.1)	(0.1)	(2.2)	(3.1)	4.4
Foreign exchange loss, net	0.7	0.4	21.2	4.2	0.6
(Gain) /loss on derivative financial instruments	6.7	63.2	(37.1)	(60.3)	-
Interest income	(0.4)	(0.5)	(0.5)	(1.0)	(0.8)
Other expenses	22.1	(1.9)	30.6	49.8	25.6
Export customs duty2	-	-	(14.7)	(19.7)	(12.3)
Other income	(4.1)	(2.2)	(11.3)	(10.1)	(4.4)
Depreciation, depletion and amortisation	123.0	131.6	109.4	111.9	120.4
Proceeds from derivative financial instruments3	-	27.2	92.3	-	-
Purchase of derivative financial instruments3	-	-	(92.0)	-	-
EBITDA	231.6	194.0	215.0	475.0	539.2
Operating costs reconciliation
Cost of sales	177.2	182.2	186.6	221.9	286.2
Less:
Depreciation, depletion and amortisation4	(120.7)	(129.4)	(107.7)	(110.5)	(119.0)
Royalties5	-	-	(14.4)	(24.3)	(39.4)
Government profit share5	-	-	(1.9)	(4.6)	(30.7)
Operating costs	56.6	52.8	62.6	82.5	97.2
Net Debt Reconciliation
Long-term borrowings	1,056.5	943.5	936.5	930.1	621.2
Current portion of long-term borrowings	31.3	15.5	15.0	15.0	7.3
Less:
Non-current investments	-	-	-	-	30.0
Current investments	-	-	-	25.0	25.0
Cash and cash equivalents	127.0	101.1	165.6	375.4	184.9
Net Debt	960.9	857.9	785.9	544.7	389.1
Net cash flows from operating activities6	182.8	202.1	153.3	349.1	358.6
Net cash used in investing activities	(192.4)	(200.3)	(245.3)	(304.5)	(239.0)
Net cash from/(used in) financing activities	34.6	(66.3)	(115.9)	147.5	(132.4)
EBITDA margin %	57.1%	55.7%	47.9%	60.7%	60.2%
Equity/assets ratio %	29.6%	32.8%	35.4%	41.6%	47.3%
Share price at end of period (US$)7	4.41	4.75	5.97	6.56	13.00
Shares outstanding ('000s)	188,183	188,183	188,183	188,183	188,183
Options outstanding ('000s)	2,199	2,536	2,611	2,611	2,912
Dividend per share (US$)	-	-	0.27	0.35	0.34

¹ The reorganisation costs are represented by the costs associated with the introduction of Nostrum as the new holding company of the Group and the respective reorganisation that took place in June 2014.

² In 2016 and 2017, Export customs duty is included within Profit / (loss) before income tax (presented within 'taxes other than income tax'). In 2013, 2014 and 2015, Export customs duty is included within 'other expenses', therefore an adjustment is made to re-include Export customs duty within respective EBITDA.

³ Cash received from hedge contract represents the cash proceeds from the long-term hedging contract which in accordance with IAS7 Statement of Cash Flows is included within operating cash flows. While this item is not required to be presented in the Consolidated Income Statement, we have included this in our definition of EBIT and EBITDA in order to better align these non-GAAP measures with our operating cash flows.

⁴ Depreciation as it applies to operating assets only.

⁵ Prior to 2016, royalties and government profit share were reported within the cost of sales line.

⁶ IFRS term based on indirect cash flow methodology

⁷ Prior to 20 June 2014 the equity of the Group was represented by GDRs, the share price as at 31 December 2017 was 3.26 GBP/share x 1,3513 US$/GBP = 4.41 US$/share

Alternative performance measures

In the discussion of the Group's reported operating results, alternative performance measures (APMs) are presented to provide readers with additional financial information that is regularly reviewed by management to assess the financial performance or financial health of the Group, or is useful to investors and stakeholders to assess the Group's performance and position. However, this additional information presented is not uniformly defined by all companies including those in the Group's industry. Accordingly, it may not be comparable with similarly titled measures and disclosures by other companies. Certain information presented is derived from amounts calculated in accordance with IFRS but is not itself an expressly permitted IFRS measure. Such measures should not be viewed in isolation or as an alternative to the equivalent IFRS measure.

EBITDA

EBITDA is defined as the results of operating activities before depreciation and amortisation, share-based compensation, fair value gains and losses on derivative instruments, foreign exchange losses, finance costs, finance income, non-core income or expenses and taxes, and includes any cash proceeds received or paid out from hedging activity.

This metric is relevant as it allows management to assess the operating performance of the Group in absence of exceptional and non-cash items.

Operating costs

Operating costs are the cost of sales less depreciation, royalties and government profit share⁵.

This metric is relevant as it allows management to see the cost base of the company on a cash basis.

Effect of realised loss on the structure of assets, capital, liquidity and liability

The loss realised is appropriated to equity. The loss does not impair the Group's ability to finance its ongoing investment in oil and gas assets. The Group at all times maintains an adequate level of liquidity and net debt is kept at defined levels.

 

END

 

 

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