London, 26 March 2019

Full Year Results for the Year Ending 31 December 2018

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 2018, together with the publication of the 2018 Annual Report for Nostrum and its subsidiaries taken as a whole (“the Group”).

2018 Financial and Operational highlights of the Group:

Operational

• 2019 average daily production above 32,500 boepd
• 2018 average daily production of 31,254 boepd (2017: 39,199 boepd) corresponding to average daily sales volumes of 29,516 boepd (2017: 37,844 boepd)
• Mechanical completion of the third Gas Treatment Unit (“GTU3”) in December 2018, with full commissioning expected before the end of Q3 2019
• Completed drilling of Well 40 with stable test production over 1,500 boepd
• 45 wells producing at the Chinarevskoye field as at 31 December 2018 – 20 oil wells and 25 gas condensate wells
• Total Group 2P reserves of 410mmboe as at 1 January 2019 following Ryder Scott independent reserve report and total Group contingent resources of 249 mmboe

Financial

• Revenue of US$389.9 million (2017: US$405.5 million)
• EBITDA1 of US$231.2 million (2017: US$232.0 million)
• EBITDA margin of 59.3% (2017: 57.2%)
• Net operating cash flows2 of US$214.0 million (2017: US$182.6 million)
• 12% reduction in operating costs3 to US$49.9 million (2017: US$56.6 million)
• Over 30% reduction in general & administrative costs4 to US$20.3 million (2017: US$31.0 million)
• Transport costs reduced to US$4.6/boe (2017: US$4.8/boe)
• Closing cash5 for the period of US$121.8 million (2017: US$127.0 million)
• Net debt of US$1,007.8 million (2017: US$960.9 million)
• Total debt6 of US$1,129.6 million (2017: US$1,087.9 million)
• Net debt / LTM EBITDA ratio of 4.4x (2017: 4.1x)
• US$150 million impairment from 78mmboe reduction in Group 2P reserves

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 Cost of sales net of depreciation
4 General & administrative expenses net of depreciation
5 Defined as cash and cash equivalents including restricted cash, current and non-current investments
6 Defined as total debt minus cash and cash equivalents

2019 Drilling and sales volume guidance

• With two drilling rigs we will be able to drill up to six wells during 2019
• The first two wells are in the Northern area of the field around well 40 (wells 41 and 42)
• The location of additional wells will be finalised once we have completed the evaluation of wells drilled during 2018 and those currently being drilled

2019 production guidance remains unchanged at 30,000 boepd, corresponding to sales volumes of 28,000 boepd. Given that we are not drilling in proven areas of the field there is a range of possible outcomes from the Northern wells and therefore, the above production guidance does not include any additional production from new wells planned this year

Other
Binding agreements with Ural Oil & Gas LLP

On 2 August 2018 Nostrum announced that through its subsidiary Zhaikmunai LLP it entered into binding agreements to purchase and process third party hydrocarbons delivered by Ural Oil & Gas LLP (“UOG”).

UOG is a company that is owned by KazMunaiGas (“KMG”) (50%), Sinopec (27.5%) and MOL Group (“MOL”) (22.5%). According to the 2017 KMG Annual Report, the Rozhkovskoye field has 196 million boe 2P reserves. Research by Wood Mackenzie states that the field has eight wells drilled and completed. The Rozhkovskoye field is within 20km of Nostrum’s Chinarevskoye field.

Once UOG has obtained all necessary internal approvals they will fund the infrastructure required to deliver the hydrocarbons to the boundary of the Chinarevskoye field. The high-level commercial terms comprise of two parts:

• a tolling fee for the stabilisation of liquid condensate at US$8 per barrel; and
• the purchase of raw gas from UOG.

Strategic focus for 2019:

• Maintain stable production levels at Chinarevskoye while operational issues are addressed
• Optimise Group cost profile with a focus on operating costs, G&A, and drilling capex
• Appraise the Northern area discovery
• Access resources in the region to maximise the value of our infrastructure
• Focus on expanding QHSE policies and developing GHG reduction strategies
• Foster diversity at all levels of the Group

Kai-Uwe Kessel, CEO of Nostrum Oil & Gas commented:

“Looking forward to 2019 I want to ensure we continue the positive trend we set in Q4 of stabilizing production combined with some of the lowest drilling costs we have ever achieved. I am optimistic that we can grow production based on the lessons we have learnt and the results of the Schlumberger study due in the third quarter of 2019. We currently have two rigs drilling in the North and have access to more rigs when the time comes to accelerate drilling.”

Conference call

Nostrum’s management team will present the FY 2018 Results and will be available for a Q&A session with analysts and investors today at 2:00 pm UK time, 26 March 2019. If you would like to participate in this call, please register by clicking on the following link and following instructions: Results Call

Download: Results PRESENTATION
Download: Consolidated Group Financials
Download: 2018 Annual Report
Download: Ryder Scott 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
+44 203 740 7433
ir@nog.co.uk

Instinctif Partners – UK
David Simonson
Dinara Shikhametova
Sarah Hourahane
nostrum@instinctif.com
+ 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:

Appointment of Robert Tinkhof

Mr. Robert Tinkhof joined the Company as its new Chief Operating Officer on 12 February 2019, replacing Mr. Heinz Wendel who is retiring. Prior to this he held several senior management positions, most recently as Managing Director at the Scientific Research Institute of KMG for Production & Technology in Kazakhstan. Mr. Tinkhof has more than 30 years of experience in the oil and gas industry, mainly with Royal Dutch Shell with assignments in the Netherlands, UK, Syria, Iran, Egypt, Iraq and Russia.

Board changes
On 21 March 2019 the Company’s Board of Directors established a Health, Safety, Environment and Communities Committee of the Board as part of the Company’s initiatives to further develop its sustainability practices across the Company and its operations and take further steps in its commitment to improve overall health, safety, environmental and social performance and better address important issues such as climate change and gender diversity.

The new committee will be chaired by independent non-executive director Kaat Van Hecke, and also includes CEO and director Kai-Uwe Kessel and independent non-executive director Martin Cocker. The HSEC Committee will work closely with Company management and will report on its activities to the full Board.

In addition, the Board decided on 21 March that with effect immediately following the Company’s annual general meeting of shareholders, Martin Cocker will replace Sir Christopher Codrington as chairman of the Audit Committee of the Board. Sir Christopher will remain a member of the Committee.

The Board has designated Sir Christopher as the non-executive director who will lead the Board’s engagement with Nostrum’s workforce as foreseen in Provision 5 of the 2018 UK Corporate Governance Code.

Operational Overview:

Sales volumes
The sales volumes split for FY 2018 was as follows:

The difference between production and sales volumes is primarily due to internal consumption of gas

Q4 2018 Drilling

• As at 31 December 2018, the Company had 45 wells in production (20 oil wells and 25 gas condensate wells)
• Completed drilling of Biyski North-east wells 228 and 231 with combined production from these wells exceeding 2,500 boepd
• One of the three drilling rigs has been demobilised and the remaining two units moved to the Northern part of the field to drill step-out wells from Well 40

2019 Drilling and sales volume guidance

• With two drilling rigs we will be able to drill up to six wells during 2019
• The first two wells will be in the Northern area of the field around Well 40 (wells 41 and 42)
• The location of additional wells will be finalised once we have completed the evaluation of wells drilled during 2018 and those currently being drilled
• 2019 production guidance remains unchanged at 30,000 boepd, corresponding to sales volumes of 28,000 boepd. Given that we are not drilling in proven areas of the field there is a range of possible outcomes from the Northern wells and therefore, the above production guidance does not include any additional production from new wells planned this year

Progress on the development of GTU3

Mechanical completion of GTU3 was achieved in December 2018. Cold commissioning has now started with first gas targeted for Q2 2019 and full commissioning of the plant before the end of Q3 2019.

The below figures reflect all future cash payments expected to be made (excluding VAT) on GTU3.

Hedging

Nostrum’s hedge came to its conclusion in December 2018. Given the recent weakness in the oil prices combined with high volatility the company has not entered into a new hedge. It continues to monitor the market in regard to hedging a portion of its liquid production.

Reserves and resources

As at 1 January 2019, the Company’s independent reserve reviewer, Ryder Scott, confirmed the Group’s 2P reserves of 410 mmboe. 1P reserves at the Chinarevskoye license were 98 mmboe. The Ryder Scott Reserves Report also confirmed Nostrum has 2P reserves of 116 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 127 mmboe and 731 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.

The Ryder Scott Reserves Report is available on our website: http://www.nog.co.uk

Executive Chairman’s Statement – Atul Gupta
Ensuring stability and Delivery
What has been the biggest challenge for Nostrum during 2018?
The single biggest challenge we faced in 2018 was the disappointing operational performance of the Biyski North-east reservoir and western area of Chinarevskoye. Therefore, while our long-term vision and growth expectations remain unchanged, we have not made the progress we wanted to make in 2018 owing to these unforeseen operational difficulties within our licence area. The impact of subsurface challenges is a reduction in our 2P reserves by 78 million boe. We are focused on reversing both production decline and reserve decline during 2019.

How has the Board sought to address these challenges?
The Board has assumed greater oversight of operational decision making. We now hold technical workshops each quarter where those Board members with a technical background act as a further sounding board for management on our decisions related to drilling and reservoir plans. Given improving production is our priority, this is where the Board has specifically sought to support management in its decision making.

In addition to the Board bringing its own technical knowledge, it has requested that we seek leading external advice. Accordingly, we have contracted Schlumberger to conduct a technical study of our main reservoirs to better understand their behavior. We have also requested Schlumberger to evaluate the best way forward to complete our multi-frac appraisal well 234 in the west of the field. The technical work required to be able to move forward with further drilling activities in both areas is expected to be complete in Q3 2019.

We are also cognisant the cash position of the Company needs to be carefully monitored to avoid any stress on our short-term liquidity position. As a result, the Board requested that we reduce the number of rigs from three to two, which will be focused in the Northern area, whilst we are working on both Schlumberger studies. In addition, the Board also now approves each well that is drilled to ensure we are all taking responsibility for maximizing the best possible chance of success on the investments we make.

From a financial perspective, the Board decided to err on the side of caution and take an impairment against the reduction in our 2P reserves. Whilst we have a significant volume of 2P reserves, we are cognisant of the challenges we faced with 2018 production and therefore have looked to stress the 2P production profile with higher sensitivities, resulting in an impairment being taken.

How has the Board responded to shareholders in 2018?
We have always listened and responded to concerns raised by our shareholders. For example, we made improvements to our Remuneration Committee structure and remuneration packages during the year.

Michael Calvey, who continues to serve as a Director of Board, stepped down as a member of the Remuneration Committee in August this year. Following this change the committee is comprised solely of independent non-executive directors, thereby ensuring that the Company is in full compliance with Provision D.2.1 of the UK Corporate Governance Code.

Following consultation with our shareholders over the course of the year regarding independent non-executive director participation in our LTIP scheme, we have since amended the terms of the LTIP to make non-executive directors ineligible to participate and will modify the remuneration policy to prohibit non-executive directors from participating gin the LTIP in the future.

We have provided additional information and clarity regarding KPIs for bonuses for executive directors in the future in the remuneration report within this Annual Report, which can be found on page 86.

What will you bring as Executive Chairman?
At the end of last year, the Board took the decision to appoint me as Executive Chairman. Whilst the Board is mindful of best practice corporate governance regarding the Chairman role, ensuring operational delivery and meeting our stated targets is the Company’s and my number one priority in order to deliver value for our shareholders, and I will endeavor to do this to the best of my abilities.

I will be working closely with the management team to ensure this happens. My experience is firmly grounded in petroleum engineering with over thirty years working in the upstream sector, which I’m confident will prove useful for the Company at present.

As a result, I have stepped down from the Board’s Nomination and Governance Committee in line with best practice. More information on our Nomination and Governance, Audit, and Remuneration Committees can be found in the corporate governance section of this Annual Report and on our website.

I am now working closely with our CEO, Kai-Uwe Kessel, on how best to turn around the operational issues we have been confronted with and, most importantly, how we can increase production.

Where do you see the biggest risks to Nostrum in 2019?
While the commodity price environment is an ever-present risk in the industry, the key risks to Nostrum in 2019 are encountering poor drilling results in the Northern Area.

We understand that the Company needs to deliver on the guidance it gives to the market and 2019 is about hitting the targets that we set and can control. In 2018, we rebased our production guidance for this year based on current producing wells, which we believe is appropriately conservative given the drilling programme is focusing on the unproved Northern Area.

We are awaiting the results from the technical studies undertaken on Biyski North-east and the western area which will help us define our drilling strategy going forward and therefore present an inherent risk.

However, we believe our tight cost control, focused drilling campaign, third-party contractor and buyer relationships leave us well placed from a balance sheet perspective to maintain a healthy cash position and mitigate financial risk.

How are you positioning the business for a sustainable future?
An environmental, social and governance focus.
ESG performance has and will always be central to how Nostrum operates as a business. This includes maintaining high standards of QHSE, with the health and safety of our employees being paramount.

Our 2018 Health, Safety and Environment Compliance Audit, conducted independently by AMEC, found our HSE systems conform to all applicable standard and best practice, and have consistently shown improvement year-on-year.

To demonstrate that we take our responsibility with regard to the environment and climate change seriously, we plan to begin reporting to the CDP initiative this year.

We are proposing a new committee of the Board be established to deal with Health, Safety, Environment and Communities, and attention to climate change issues will be among the duties of this committee.

The Audit Committee and the Board have recognised that climate change should be included among the risks and uncertainties faced by Nostrum and we will seek to quantify climate change related risks.

Developing our people and culture
I am proud of our people and the culture at Nostrum. That culture must be harnessed to focus on operational excellence in 2019 and on delivery against our targets, whilst ensuring Nostrum is an attractive place to work with an inclusive environment that celebrates diversity.

We will continue to focus on diversity, and in particular gender diversity, across all levels throughout the Group. We are setting up a mechanism for regular reporting by our Human Resources team to the Board on this issue and we are grateful fo the quality and commitment of our employees.

What is the company strategy to create shareholder value in the medium to long-term?
Our fundamental mission is to maximise the value of our reservoirs and the associated infrastructure we have built. In a region rich in hydrocarbon resources and in particular gas, we not only have both our own hydrocarbons to process but can also seek to enter into agreements with surrounding licences to ensure we fill our gas plants as quickly as possible. We successfully signed a deal with Ural Oil & Gas in 2018 that will result in gas and condensate from their licence area being processed in Nostrum’s facilities, and this is anticipated towards the end of next year. This will provide an immediate source of free cash flow for Nostrum. The infrastructure we have built will last for many years and the quicker we can fill it, the higher the value will be for nostrum stakeholders. As such, we will continue to seek business development opportunities during 2019.

We recognise that our future growth must be achieved sustainably, with a focus on our social and environmental impact in the region in which we operate. We continue to invest in social development locally as well as education and training. We are constantly improving our independent environmental impact auditing and mitigation to ensure our future growth and long-term value creation is measured with a sustainable approach for all stakeholders.

I look forward to sharing our story with you over the coming months and thank you for your ongoing support.

Atul Gupta
Executive Chairman

Chief Executive Officer’s review – Kai-Uwe Kessel
Establishing a solid foundation for operational success

2018 was a tough year in terms of production and missed guidance. What were the main issues and how can this be turned around?
During 2017 we saw three wells water out in our main producing reservoir, the Biyski North-east. The plan for 2018 was to stabilize our production decline by drilling four production wells in this reservoir. Unfortunately, our first well encountered water leading to a longer than anticipated period without new production coming online, and further questions being raised regarding the source of the water. We had a further delay on the second well due to technical drilling issues. Overall, these issues set back our production guidance by roughly six months.

In the second half of the year we successfully brought three producing wells in the Biyski online and stabilized production about 30,000 boepd. However, as a result of the water inflow we have seen, before we invest further money in to the Biyski North-east we will conduct a thorough review of the reservoir with Schlumberger. This will allow us to more accurately estimate what additional wells we can drill or recover to further stabilize and continue to grow production in 2019 and beyond.

We had planned to bring the western area of the field into production during 2018 with a mulit-frac planned for well 234. Unfortunately, before we were able to test the reservoir qualities, we suffered a wellbore collapse, meaning we could not continue with the planned multi-frac. Given the importance of this area, with 81m barrels of probable reserves attributed to it, we have decided to halt all further drilling investment in the Biyski West until we receive a full analysis from Schlumberger. Due to the well bore collapse of 234, we did not have any production from the western part of the field which, again, impacted our production guidance. We remain optimistic that we can prove the technology works and bring the reserves to production in 2020 and into the future.

As a result of the issues we faced in 2018, we uncovered more information about our existing reservoirs which resulted in a reduction in our 2P reserved by 78 million boe, in accordance with an independent report by Ryder Scott. This is largely down to two factors. Firstly, the water in the Biyski North-east meant that we lost reserves in the areas to this, and secondly, we have seen the commercial rates of some probable areas in the Mullinski reservoir in the North-east not being commercial to drill under current oil prices.

Looking forward, we have three key areas to focus on in order to grown production.

1. Identifying additional areas from production from the Biyski North-east;
2. Demonstrating the multi-frac can work in the west and unlocking the probable reserves there; and
3. Developing the Northern Area around wells 724 and 40.

How strong is Nostrum’s financial position?
A challenging operational year was tempered by a more positive financial performance. While this was in part due to improved prices for our sales products during 2018 as a result of higher commodity prices, our continued implementation of cost reduction initiatives across the business led to a healthy EBITDA margin in 2018. We managed to reduce our total General & Administrative expenses to US$22.3m and total operating costs to US$50.0m and we proactively managed the best possible netbacks across our sales products in the period, leading to stable operating cash flow margins.

We also successfully refinanced the remaining part of our debt. As a result, we have no debt maturities due until July 2022. This provides time to focus on turning around our operational performance and engage with the prudent research being undertaken into the issues faced.

Balancing capital preservation with investment into drilling during 2019 will remain a priority for the Company as we work through the challenges we encountered at the Chinarevskoye field, to increase our production.

Can you provide an update on the GTU3 project?
We successfully achieved mechanical completion of GTU3 in December 2018 and we are now looking forward to commissioning the plant. Cold commissioning has commenced, with first gas targeted for Q2 2019 and full commissioning of the plant during 2019.

When commissioning in completed, GTU3 – our third gas treatment unit – will double our production capacity to over 100,000.

What is the strategy to grow production outside of Chinarevskoye as you have a deal to process raw gas from Ural Oil & Gas?
Our long-term strategy is to build a portfolio of reserves and resources in North-western Kazakhstan to fill the GTU capacity for the next 25 years. We are not tied to owning the licences but the goal is ensuring that we can monetise the infrastructure we have built by processing all the raw gas in the region at economically attractive terms to Nostrum. Given our limited liquidity position, we cannot develop all our licences at once. Thus, I was pleased to announce the binding agreements we signed with Ural Oil & Gas (‘UOG’) in 2018. This is an alternative to acquiring reserves and resources whereby we are generating a return through agreements that result in Nostrum making money from hydrocarbons UOG delivers to our plant. We are not required to invest in any material capital expenditure and will simply allocate part of our GTU for processing their raw gas. This is an extremely economic and effective way to monetise our infrastructure without us having to risk money on drilling. This deal demonstrates the value our infrastructure has in North-western Kazakhstan and we are continuously assessing other opportunities in the region.

What are your development plans for Chinarevskoye?
During the year we saw encouraging results from our drilling operations at well 40 in the northern part of the Chinarevskoye exploration licence area, and we confirmed the discovery made in well 724 at the end of last year in the Upper Devonian formation.

Well 40 was tested with flow rates exceeding 1,500 boe per day. This is a very significant result as it can potentially open up a new area in the Chinarevskoye field that is rich in hydrocarbons and is of material scale. This is one of the highest yielding condensate wells in the field’s history.

Therefore, to better understand the full potential of those reserves in 2019, our two-rig drilling programme during the first half of 2019 will pursue the area around well 40 (wells 41 and 42) to define the extent of this encouraging prospect.

What is your production guidance for 2019?
Our 2019 drilling programme will be conducted with only two rigs and we are expecting to drill six wells in the year. As we prioritized capital preservation this year, we believe this programme is a sound allocation of capital that will ensure we sustain existing production wile targeting de-risked growth opportunities.

While the Northern area has shown encouraging results, it is not yet fully appraised and therefore carries some uncertainty in predicting potential production volumes. As a result, we are changing our approach to production guidance so as not to include any appraisal wells to be drilled in 2019. Ths means that the average forecast field production for 2019 will be 30,000 boepd*, corresponding to sales volumes of approximately 28,000 boepd

Kai-Uwe Kessel
Chief Executive Officer
*The difference of 2,000 boepd between the field production and sales volumes is largely the amount of produced gas that is consumed within our extensive processing facilities.

Results of operations for the years ended 31 December 2018 and 2017
The table below sets forth the line items of the Group’s consolidated statement of comprehensive income for the years ended 31 December 2018 and 2017 in US Dollars and as a percentage of revenue.

General note

For the year ended 31 December 2018 (the “reporting period”) total comprehensive loss increased by US$98.5 million to US$121.6 million
(FY 2017: US$23.1 million). The increase in loss is mainly due to the impairment charge for the year, which was partially offset by the improvement mainly driven by reductions in cost of sales, general and administrative expenses, selling and transportation expenses and finance costs, , as explained in more detail below.

Revenue

The Group’s revenue decreased by 3.8% to US$389.9 million for the reporting period (FY 2017: US$405.5 million). This is mainly explained by the decrease in production and sales volumes, which was partially offset by increase in the average Brent crude oil price from 54.2 US$/bbl during 2017 to 71.7 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$258.9 million, US$80.5 million and US$7.0 million respectively (FY 2017: US$200.6 million, US$102.8 million and US$30.9 million).

The following tables present the Group’s revenue breakdown by products and sales volumes and the breakdown by export/domestic sales for the reporting period and FY 2017:

Cost of sales

Cost of sales decreased by 6.8% to US$165.1 million for the reporting period (FY 2017: US$177.2 million). The decrease is primarily explained by the decrease in depreciation, depletion and amortization, repair, maintenance and other services, other transportation services, materials and supplies and well workover costs, further described in more detail below. On a boe basis, cost of sales increased by 19.6% to US$15.33 for the reporting period (FY 2017: US$12.83) and cost of sales net of depreciation per boe increased by US$0.54, or 13.2%, to US$4.63 (FY 2017: US$4.09).

Depreciation, depletion and amortisation decreased marginally by 4.5% to US$115.2 million for the reporting period (FY 2017: US$120.7 million). Depreciation is calculated applying units of production method. Decrease of depreciation in 2018 in comparison with prior period is a consequence of the ratio change between the volumes produced and the proved developed reserves as well as addition to O&G assets in the amount of US$131.5 million during reporting period.

Repair, maintenance services decreased by 14.9% to US$16.1 million for the reporting period (FY 2017:US$19.0 million) and materials and supplies decreased by 17.1% to US$5.3 million for the reporting period (FY 2017: US$6.3 million). These expenses include services on repairs and maintenance of the facilities, specifically for the gas treatment facility as well as related spare parts and other materials. These costs fluctuate depending on the timing of the periodic scheduled maintenance works.

Other transportation services decreased by 26.6% to US$6.1million for the reporting period (FY 2017:US$8.3 million). The decrease is explained by the successful cost optimisation implemented by the Group during the reporting period.

General and administrative expenses

General and administrative expenses decreased by 33.3% to US$22.2 million for the reporting period (FY 2017: US$33.3 million). This was mainly driven by US$6.7 million or 60.8% decrease in professional services from US$11.1 million in 2017 to US$4.3 million in 2018.

Selling and transportation expenses

Selling and transportation expenses decreased by 24.8% to US$50.0 million for the reporting period (FY 2017: US$66.4 million), owing primarily to decrease in sales volumes as well as further decrease effect in oil transportation costs resulting from successful connection to the KTO pipeline.

Taxes other than income tax

Royalties, which are calculated based on production and market prices for the different products, decreased by 3.6% to US$15.1 million for the reporting period (FY 2017: US$15.7 million), which is mainly owing to the relative decrease in the production volumes.

Export customs duty on crude oil increased by 190.7% to US$11.2 million for the reporting period (FY 2017: US$3.8 million), mainly owing to the relative decrease of export sales to CIS countries, which are not subject to export duties.

Government profit share increased by US$3.0 million to US$3.3 million for the reporting period (FY 2017: US$0.2 million).

Impairment charge

Considering the reserves downgrade the Group has stress-tested the impairment model with higher sensitivities and recognised non-cash impairment charge totalling US$150.0 million (FY 2017: nil), including impairment of goodwill in the amount of US$32.4 million and impairment of oil and gas assets of US$117.6 million.

Finance costs

Finance costs decreased by 17.4% to US$49.4 million for the reporting period (FY 2017: US$59.8 million), which is mainly owing to lower transactions costs on bonds refinancing, as well as relatively higher interest capitalisation rate.

Other

Loss on derivative financial instruments amounted to US$12.4 million in the reporting period and relates to fair value of the hedging contract covering oil sales. Based on the contract 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/bbl, Q2:US$64.1/bbl, Q3:US$64.1/bbl, Q4:US$64.1/bbl. 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/bbl, Q2:US$69.1/bbl, Q3:US$69.6/bbl, Q4:US$69.6/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 decreased to US$13.5 million for the reporting period (FY 2017: US$22.0 million). Such a significant decrease in other expenses is mainly 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.

Income tax expense decreased by US$21.3 million to US$28.5 million for the reporting period (FY 2017: US$49.8 million). The decrease in income tax expense was primarily driven by impairment of oil and gas properties in the current period, the effect of which on the deferred tax liabilities was partially offset by the devaluation of Tenge against US Dollar during the reporting period.

Liquidity and capital resources

During the period under review, Nostrum’s principal sources of funds were cash from operations and amounts raised under the 2018 Notes. Its liquidity requirements primarily relate to meeting ongoing debt service obligations (under the 2017 Notes and the 2018 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 2017:

Net cash flows from operating activities

Net cash flow from operating activities was US$214.0 million for the reporting period (FY 2017: US$182.8 million) and was primarily attributable to:

• Loss before income tax for the reporting period of US$92.2 million (FY 2017: profit before income tax of US$26.0 million), adjusted by a non-cash charge for depreciation, depletion and amortisation of US$117.1 million (FY 2017: US$123.0 million), impairment charge of US$150.0 million (FY 2017: nil), finance costs of US$49.4 million (FY 2017: US$59.8 million), loss on derivatives of US$12.4 million (FY 2017: US$6.7million) and payments made under derivatives of US$8.6 million.
• A US$4.0 million decrease in working capital (FY 2017: US$18.8 million increase) was mainly due to a decrease in prepayments and other current assets of US$7.7 million (FY 2017: a increase of US$5.7 million), a decrease in trade payables of US$3.2 (FY 2017: US$4.6 million) and a decrease in other current liabilities of US$5.5 million (FY 2017: a decrease of US$1.6 million).
• Income tax paid of US$9.1 million (FY 2017: US$15.9 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$172.0 million (FY 2017: US$192.4 million) due primarily to costs associated with the drilling of new wells of US$87.5 million for the reporting period FY 2017: US$57.5 million), costs associated with the third gas treatment unit of US$55.8 million (FY 2017: US$157.5 million), and costs associated with Rostoshinskoye, Darjinskoye and Yuzhno-Gremyachinskoye fields of US$2.5 million (FY 2017: US$3.6 million).

Net cash from/(used) in financing activities

Net cash used in financing activities during the reporting period made up US$47.0 million, and was mainly represented by proceeds from issue
of 2018 Notes in the amount of US$397.3 million, offset by the early redemption of 2012 Notes and 2014 Notes totalling US$353.2 million, the fees and premium paid for the arrangement of these transactions in the amount of US$9.3 million, and the payment of US$81.1 million of the finance costs, primarily on the Group’s 2017 Notes and 2018 Notes. Net cash from financing activities during FY 2017 made up US$34.6 million, which 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.

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 2018 based on contractual
undiscounted payments:

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$131.4 million (FY 2017: US$188.1 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 achieved mechanical completion of a third unit in December 2018, with commissioning anticipated to be completed in 2019. 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 2018 Ryder Scott Report and assuming the full commissioning of the gas treatment facility in H2 2019, that the Company’s annual production will gradually increase from 2019 onwards. The remaining costs for the completion of GTU3 are estimated at US$34.6 million.

Drilling

Drilling expenditures amounted to US$87.5 million for the reporting period (FY 2017 US$57.5 million). After the completion of GTU3, it 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 and has not done so for the last three years, as the Board determined it was not in the Company’s best interests to do so. This will be reviewed annually by the Board.

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, 2017 and 2018, Export customs duty is included within Profit / (loss) before income tax (presented within ‘taxes other than income tax’). In 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. EBIDTA margin is calculated as EBITDA divided by total revenue.
8. Prior to 20 June 2014 the equity of the Group was represented by GDRs, the share price as at 31 December 2018 was 1.03 GBP/share x 1.28 US$/GBP = 1.32 US$/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.