Maha Energy

Annual Report • Feb 28, 2020

Report for the FOURTH QUARTER AND FULL YEAR ENDED 31 DECEMBER 2019 (org number: 559018‐9543)

Highlights

(all amounts are in US dollars unless otherwise noted)

Fourth Quarter 2019

• Daily oil & gas production for Q4 2019 averaged 3,165 BOEPD (Q4 2018: 2,454 BOEPD)
• Revenue of USD 13.7 million (Q4 2018: USD 12.6 million)
• Operating netback of USD 9.8 million or USD 35.00 per BOE (Q4 2018: USD 9.4 million or USD 43.26 per BOE)
• EBITDA of USD 8.4 million (Q4 2018: USD 8.5 million)
• Net result of USD 2.7 million (Q4 2018: USD 18.3 million, including USD 12.1 million of one‐time other gains)
• Basic Earnings per share of USD 0.03 (Q4 2018: USD 0.19)
• Diluted Earnings per share of USD 0.02 (Q4 2018: USD 0.17)

Full Year Ended 31 December 2019

• The Company grew its 2P reserves to 41.8 MMBOE, a 25% increase as compared to year end 2018
• Drilled and completed the Attic well in the Tie Field and drilled a new delineation well (maha‐1) in the Tartaruga block currently undergoing well testing.
• Daily oil & gas production for the full year 2019 3,044 BOEPD (2018: 1,804 BOEPD)
• Revenue of USD 55.6 million (2018: USD 38.1 million)
• Operating netback of USD 41.5 million or USD 38.96 per BOE (2018: 26.9 USD million or 41.57 USD per BOE)
• EBITDA of USD 35.9 million (2018: USD 22.4 million)
• Net result for the year of USD 19.7 million (2018: USD 25.6 million, including USD 12.1 million of one‐time other gains)
• Basic Earnings per share of USD 0.20 (2018: USD 0.26)
• Diluted Earnings per share of USD 0.18 (2018: USD 0.25)
• Cash and cash equivalents balance of USD 22.4 million (2018: 20.3 million).

Financial Summary

						Full	Full
	Q4					Year	Year
(TUSD, unless otherwise noted)	2019	Q3 2019	Q2 2019	Q1 2019	Q4 2018	2019	2018
Net Daily Production (BOEPD)	3,165	3,593	2,739	2,669	2,454	3,044	1,804
Revenue	13,672	16,068	14,098	11,751	12,595	55,589	38,132
Operating netback	9,825	12,017	10,668	9,029	9,436	41,539	26,917
EBITDA	8,354	10,663	9,188	7,663	8,486	35,868	22,404
Net result for the period	2,679	6,570	6,157	4,248	18,2671	19,654	25,645
Earnings per share – Basic (USD)	0.03	0.07	0.06	0.04	0.19	0.20	0.26
Earnings per share – Diluted (USD)	0.02	0.06	0.06	0.04	0.17	0.18	0.25
Cash and cash equivalents	22,450	20,421	20,504	19,768	20,255	22,450	20,255

¹ Q4 2018 Net result includes USD 11.3 million of recognized deferred tax recovery and USD 0.8 million of other gains.

Definitions

SEK	Swedish Krona	BBL or bbl	Barrel
USD	US Dollar	BOPD	Barrels of Oil Per Day
TSEK	Thousand SEK	Mbbl	Thousand barrels of Oil
TUSD	Thousand USD	MMbbl	Million barrels of Oil

Abbreviations Oil related terms and measurements

CAD	Canadian Dollar	BOE or boe	Barrels of Oil Equivalents
SEK	Swedish Krona	BBL or bbl	Barrel
BRL	Brazilian Real	BOEPD	Barrels of Oil Equivalents Per Day
USD	US Dollar	BOPD	Barrels of Oil Per Day
TSEK	Thousand SEK	Mbbl	Thousand barrels of Oil
TUSD	Thousand USD	MMbbl	Million barrels of Oil
MSEK	Million SEK	Mboe	Thousand barrels of oil equivalents
MUSD	Million USD	MMBoe	Millions of barrels of oil equivalents
		Mboepd	Thousand barrels of oil equivalents per day
		Mbopd	Thousand barrels of oil per day
		MCF	Thousand Cubic Feet
		MSCFPD	Thousand Standard Cubic Feet per day
		MMSCF	Million Standard Cubic Feet
		MMSCFPD	Million Standard Cubic Feet Per Day
		BWPD	Barrels of Water Per Day

Gas to oil conversion

6,000 cubic feet = 1 barrel of oil equivalent

Letter to shareholders

Dear Friends and Fellow Shareholders of Maha Energy AB,

The fourth quarter and the end of 2019 marked the beginning of a new era for the Company. Maha is now firmly established as a successful oil producing company with two excellent oil fields in Brazil. First, the Tie field is rapidly turning into a cash machine with two excellent and predictable oil‐producing sandstone reservoirs. Second, the Tartaruga field continues to deliver more oil from the Penedo sandstone. An example is the recently tested 107D horizontal well which flowed 990 BOEPD (939 BOPD & 303 MSCFPD) from the Penedo‐1 zone on a restricted jet pump.

The Company now have a solid foundation to build on. To that extent, Maha staff are slowly turning their attention to further growth opportunities, and in a sector that has suffered greatly since the 2014 oil price collapse, opportunities are abundant. Furthermore, 2019 saw a sharp increase in North American oil company bankruptcies (42) which was the highest since the 2015/16 downturn (114). According to Haynes and Boones Oil Patch Bankruptcy Monitor, 208 North American oil and gas companies have gone bankrupt since the 2014 oil crash. Furthermore, the International Energy Agency (IEA) identifies North America and Brazil as the top two oil and gas growth areas in the world (IEA, "Oil 2019"). It is therefore clear that Maha is not only optimally positioned geographically, but with a very strong balance sheet and ready access to capital, the Company is positioned for growth.

Staying true to color, the Company's tried and tested strategy of identifying underperforming hydrocarbon assets and then adding state of the art technology to increase value will be continued.

Year on year 2P Reserves up by 25% – now at 39.750 million barrels of oil

In September 2019, the Company announced a significant oil reserve increase in the Tie Field as a result of the recently drilled 'Attic' Well. Also, important, and something that perhaps has gone unnoticed, is that the recent high‐ pressure sand stimulation work performed on the 7TTG well at Tartaruga increased the Proven reserves there by some 30%. The Company's Proven reserves increased by 18%, year on year. And finally, the Company's (proven) reserve replacement ratio is 147% for 2019. These numbers are excellent considering they all stem from technology implementation work done on existing and producing oil fields.

Last hurdle cleared on offtake capacity at Tie field.

After nearly a year of expansion commissioning work and licensing, our biggest customer for the Tie field oil received their final clearance to start refining more oil. Together with the recently added Petrobras operated Comboata receiving station, the Company now have offtake agreements in place to accommodate 4,850 BOPD from the Tie field. This is a significant increase from July 2017 when the Tie Field was purchased and offtake was limited to 1,100 BOPD.

Tartaruga 107D Test Results

The long awaited well test on the Tartaruga 107D horizontal was finally concluded and was better than expected. Considering that the 107D well was only intermittently 'coughing' oil and gas when Maha assumed the field in 2017, it was very encouraging that the well started to flow freely again. This is the whole purpose of horizontal drilling, particularly in 'tight' formations like the Penedo. Horizontal drilling adds valuable producible surface area in the well, and it provides for access to previously untapped parts of the reservoir. It was primarily the access to new parts of the reservoir that proved so fortuitous. In tight reservoirs, most of the inflow pressure drop occurs very close to the wellbore, so by drilling a short distance away from the original wellbore it allows for higher reservoir pressure. It is this high reservoir pressure that allows the oil to flow freely to the surface.

Because the 107D horizontal initially free flowed a mixture of oil, gas and water, it took some time to clean the well up. Over time, the water and oil emulsion reduced enough so that the oil could be treated in the Tartaruga facilities. Once the well had cleaned up enough, the well could then be placed on pump in order to evaluate the full

productivity of the well. And as reported, productivity was more than what the Tartaruga facilities could currently handle. Simply put, the oil could not be trucked out fast enough.

Work is underway to increase the handling capacity of the Tartaruga facilities so that the oil from the 107D, 7TTG and predictably Maha‐1 (to be tested) wells can be produced without restrictions. It is very encouraging that the Penedo sandstone contains so many zones with so much potential and at the moment the field is only producing from the Penedo‐1 zone. No doubt, the added production from Tartaruga is welcomed, but currently, and although it is still early in the new year, the Company is producing in accordance with its' production plan for 2020.

I continue to be grateful to all Maha employees for their hard work and dedication that has made all this possible.

"Jonas Lindvall" Managing Director

Financial Report for the Fourth Quarter and Full Year ended 31 December 2019

OPERATIONAL AND FINANCIAL REVIEW

Strategy

The Company's business activities include the exploration for and development and production of hydrocarbons. The Company's core expertise is in primary, secondary and enhanced oil and gas recovery technologies and, as such, its business strategy is to target and develop underperforming hydrocarbon assets. By focusing on assets with proven hydrocarbon presence and applying modern and tailored technology solutions to recover the hydrocarbons in place, the Company's primary risk is not uncertainty in reservoir content but in the fluid extraction.

Assets

Country	Concession name	Maha Working Interest (%)	Status	Area (acres)	BOEPD (2 )	Partner
USA	LAK Ranch	99%	Pre‐Production	6,475	31	SEC (1%)
Brazil	Tartaruga	75%	Producing	13,201	320	Petrobras (25%)
Brazil	Tie (REC‐T 155)	100%	Producing	1,511	2,814
Brazil	REC‐T 155	100%	Exploration	4,276	‐
Brazil	REC‐T 129	100%	Exploration	7,241	‐
Brazil	REC‐T 142	100%	Exploration	6,856	‐
Brazil	REC‐T 224	100%	Exploration	7,192	‐
Brazil	REC‐T 117	100%	Exploration	6,795	‐
Brazil	REC‐T 118	100%	Exploration	7,734	‐

BRAZIL

Tie Field (Reconcavo Basin)

Maha owns and operate, through a wholly‐owned subsidiary, 100% working interests in six onshore concession agreements located in the Reconcavo Basin of Brazil, including the oil producing Tie field. The Tie field and the six concessions are located in the state of Bahia, onshore Brazil. The six concessions are in varying stages of exploration and development. A total of 8 wells had been drilled and 212 km² of 3D seismic had been acquired by the previous Operator over the 41,606 total acres.

GTE‐3 (oil producer)

During the third quarter of 2018, the GTE‐3 well was recompleted with a newly acquired jet pump immediately adding about 900 BOPD to the Tie Field production. Due to a stuck pressure plug in the short string, GTE‐3 was comingled from both the Agua Grande (AG) and Sergi zones. Work to convert the GTE‐3 well from a single comingled well to a separate dual completion was completed in July 2019 and during the quarter work continued to clean up and restore production on GTE‐3. GTE‐3 can now can produce individually from both the AG and Sergi zones.

² As per the current quarter reported net production volumes to Maha before royalties. 1BBL = 6000SCF of gas. Approximately 92% of Maha's oil equivalent production is crude oil.

GTE‐4 (oil producer)

During the month of October, and as expected, the GTE‐4 Sergi formation (long string) temporarily stopped free‐ flowing which led the Company to commence far gone plans to reconfigure GTE‐4 to install a downhole jet pump artificial lift system, as and when operations permit. This was not unexpected, for which in anticipation of this, the Company had already installed the surface jet pumping equipment at the well site. Planning operations have now commenced to workover GTE‐4 and install the downhole pump at the Sergi formation. In the meantime, GTE‐4 short string (Agua Grande formation) continues to free flow to surface.

7‐Tie‐1DP‐BA (Attic Well)

On February 18, 2019 Maha spudded its first development well to boost production at the Tie Field. The primary objective of this well was to dually complete the AG and Sergi zones at a structurally higher position to the already free flowing GTE‐4 well. A secondary objective was to penetrate and evaluate the slightly deeper Boipeba sandstone reservoir. However, poor reservoir development of the Boipeba formation resulted in no hydrocarbon presence at this location. Following the initial single completion, the well was recompleted using a dual 2‐3/8" tubing completion with initial free flowing tests from the Sergi and AG formations of 985 BOPD (1,088 BOEPD) and 1,726 BOPD (1,844 BOEPD) respectively with neither zone producing any noticeable water amount. During these tests the AG production had to be choked back (restricted) due to surface equipment limitations, suggesting potential higher production rates. The well was hooked up in June 2019 and is currently producing from both zones.

Production Facilities

During 2019, the production facilities at the Tie Field were upgraded from its original 2,000 BOPD handling capacity to 5,000 BOPD. As the Tie Field is not connected to a pipeline system, all oil is exported by trucks. The associated gas is separated and sold locally to two customers.

In November, the full year 2019 production guidance was revised downwards due to extended delays in commissioning of primarily gas handling and gas sales equipment. Additionally, delays in improvements to the water injection system during the year negatively impacted oil production due to a six month shut down of water injection. Water injection capacity from the water source well has now been doubled, but delays continues due to a late arriving water transfer pipeline. Once the upgrade to the water injection system is complete, water injection capacity will be doubled from its' current 3500 BWPD.

During the fourth quarter, a fire at one of the end customers for compressed gas temporarily affected gas deliveries which in turn affected oil production. Furthermore, commissioning problems with the Gas‐to‐Wire (GTW) generators continued to plague the operations. At the end of fourth quarter, GTW was operating at approximately 75% capacity. Additional generators are being mobilised to the Tie Field as they become available. A total of 17 Units are now installed at the Tie Field.

Average production from the Tie Field during the current quarter was 2,814 BOEPD (2,446 BOPD of oil and 2,207 MSCFPD of gas). Oil production at the Tie field is expected to increase as and when: (a) the GTW generators become fully operational; (b) the water injection volumes are increased thereby reducing the gas oil ratio; and (c) zonal optimization is implemented as and when GTE‐4 is recompleted as a pumper and additional production wells are drilled.

During January 2020, final regulatory approval was obtained by the local refinery to increase its refined oil products volume which will allow Maha to increase Tie Field oil deliveries to that refinery by an additional 800 BOPD. Overall delivery availability to the refinery is now 3 000 BOPD to Maha. Together with existing sales contracts to Petrobras, Maha can now sell up to 4,850 BOPD from the Tie Field.

Tartaruga Field

Maha has a 75% working interest in the Tartaruga development block, located in the Sergipe Alagoas Basin onshore Brazil. The Tartaruga Field is located in the northern half of the 13,201 acre (53.4 km2 ) Tartaruga Block and produces light (41° API) oil from the Penedo sandstone reservoir. The Penedo sandstone consists of 27 separate stacked sandstone stringers, having all been electrically logged and are believed to contain oil, and of which only 2 of the 27 have been produced (Penedo 1 and Penedo 6).

Starting in 2018, the Company commenced a significant work program which included the re‐entry, perforation, stimulation and recompletion of the 7TTG producing well along with the re‐entry and horizontal sidetrack drilling of the 107D well. As stated in prior reports, the multiple stacked Penedo sandstone are believed to respond well to horizontal drilling and hydraulic stimulation. To that end, work planned for Tartaruga included both hydraulic stimulation of the existing 7TTG well and the horizontal side‐tracking of the 107D well. In both cases, the highly productive Penedo 1 sandstone was targeted. In the 7TTG well, Penedo 1 sandstone had never been produced and was considered 'pay‐behind‐pipe'.

7TTG Well

The workover to recomplete the 7TTG well with larger tubing and a dedicated jet pump was completed in 2019 perforating the P1 and P4 sandstones, with the P1 zone stimulated. Subsequent clean‐up operations have yielded a stabilized production rate of 750 BOPD (gross) from the P1 zone only. The well is currently on production and may temporarily be shut in for safety reasons during drilling and workover operations.

107D Sidetrack

In early 2019, drilling of the 107D horizontal sidetrack was completed with a 500 meters long horizontal hole in the Penedo‐1 sandstone penetrating 312 meters of very good to excellent oil and gas shows. These results are important because they prove up horizontal continuity of the Penedo sandstone stringers and the applicability of horizontal drilling technology in the Tartaruga Field. The liner has now been perforated using a coiled tubing unit with immediate indications of hydrocarbons observed. A workover operation was planned for the end of 2019 to repair a hole in the 7" casing and to properly test the horizontal; production capacity. Delays in workover rig mobilization pushed this work out to the beginning of 2020. The 7" casing repair operations were completed during January 2020 and the well placed on production tests. After a 20 day test, the 107D well flowed 937 BOPD with the assistance of a jet pump. Flow was restricted due to surface handling limitations. It is expected that the well can and will produce at higher rates once the Tartaruga Facility has been upgraded to handle larger volumes.

Maha has demonstrated the applicability of horizontal drilling as a very beneficial extraction technology for the Penedo sandstone reservoirs. This is the first horizontal wellbore to have been drilled in the Penedo sandstone reservoir.

Maha‐1 (7‐TTG‐3D‐SES) Delineation (new) Well

On 12 July 2019, the Company spudded Maha‐1 and Total Depth (TD) was reached on 3 October 2019. The well was cased and cemented and the rig released in mid‐October. Because of space limitations at the Tartaruga location, a smaller rig had to be brought in to assist in well testing operations. Maha‐1 will undergo extensive well tests to evaluate previously untested Penedos sandstone stringers. On 23 January 2020, a workover rig was positioned over the Maha‐1 well and well testing operations commenced.

Maha‐1 is primarily an appraisal well to provide much needed well information for the Tartaruga Field Development Plan. Well testing on Maha‐1 is expected to take between 60 – 90 days, and will target up to five different intervals in the Penedo sandstone. Results of the first testing interval(s) will dictate the final number of testing intervals.

Production Facilities

Current handling facilities at Tartaruga Field allow for approximately 500 – 800 BOPD of processing and handling with storage limited at 1,350 barrels of oil. Current oil production is limited by associated gas flare limitations, and plant handling capacity. Currently, crude export is via oil trucks as the facility is not linked to a pipeline system. During the second half of 2019, facilities upgrade work began to handle up to 2,500 BOPD and 2,500 MSCFPD of associated gas. Environmental licenses have already been obtained for the implementation of a Gas‐to‐Wire project that will handle the excess gas for this upgrade. The facilities upgrades are expected to be completed during the second quarter of 2020; however, the plan is to incrementally increase production as capacity is brought on line. It is not anticipated that there will be any significant production stoppages during the upgrade work.

Average net production from the Tartaruga Field during the current quarter was 320 BOPD of oil.

USA

The Company owns and operates a 99% working interest in the LAK Ranch oil field, located on the eastern edge of the multi‐billion barrel Powder River Basin in Wyoming, USA.

The crude oil density produced from the LAK area is 19 API. Since the purchase of this field in 2013, the Company has been evaluating different oil recovery mechanisms and is currently working towards a staged full field development using a hot water injection scheme. Multiple attempts have been made on the field since its discovery in the 1960's, including cyclic steam, steam assisted gravity drainage and solvent injection. Maha has determined through drilling results, core analysis, and computer aided modelling, core tests and field pilot tests that a simple water flood using hot water produces the best economic results. As at 31 December 2019, the LAK Ranch asset is still considered to be in the pre‐production stage and is currently undergoing delineation and pre‐development work. As such royalties and operating costs, net of revenues, since the commencement of operations have been capitalized as part of exploration and evaluation costs.

Phase 3 of Development Plan

The Phase 3 production and injection wells were completed during the latter part of 2018. Tie‐ins and commissioning work were completed during the first half of 2019 and since then the Company is monitoring the effect of the combined injection and production operations of Phase 3. No further work will be undertaken at LAK until the results of the Phase 3 development program have been analyzed, which is expected to be completed during the first half of 2020.

During the fourth quarter of 2019, the Company generated incidental revenue from LAK Ranch of TUSD 121, on average sales volumes of 31 bopd.

	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
Delivered Oil (Barrels)3	257,346	210,786	1,019,047	609,087
Delivered Gas (MSCF)	203,077	90,117	552,862	296,189
Delivered Oil & Gas (BOE)4	291,192	225,806	1,111,191	658,452
Daily Volume (BOEPD)	3,165	2,454	3,044	1,804

Production

Production volumes shown are net working interest volumes before government, gross overriding and freehold royalties. Approximately 92% of total oil equivalent production was crude oil for the full year 2019.

During the current quarter, Tie Field production was restricted due to continued commissioning work on Gas to Wire equipment and delays in water injections system. Despite these restrictions, average daily production volumes increased by 29% and 69% for the fourth quarter and the full year ended 31 December 2019, respectively, versus the comparative 2018 periods. This increase is mainly attributed to the production from the new Attic well in the Tie field and the workovers of the GTE‐3 and 7TTG wells. Production volumes also increased as Maha managed to secure additional deliveries to both the gas and oil customers for the Tie Field production. During the comparative fourth quarter 2018, Tartaruga field production was mostly shut in during the 107D drilling activities which added to the lower production in the comparative period.

³ Includes LAK Ranch Oil delivered during the period

⁴ BOE is Barrels of Oil Equivalent and takes into account gas delivered and sold. 1 bbl = 6,000 SCF of gas

Revenue

			Full Year	Full Year
(TUSD, unless otherwise noted)	Q4 2019	Q4 2018	2019	2018
Oil and Gas revenue	13,672	12,595	55,589	38,132
Sales volume (BOE)	280,772	218,123	1,066,084	647,607
Oil realized price (USD/bbl)	54.33	60.92	56.32	63.18
Gas realized price (USD/MSCF)	0.86	1.61	1.11	1.17
Oil Equivalent realized price (USD/Boe)5	48.70	57.74	52.14	58.88
Reference price – Average Brent (USD/bbl)	63.41	67.71	64.36	71.06

Revenue for the current quarter and the full year ended 31 December 2019 amounted to TUSD 13,672 (2018: TUSD 12,595) and TUSD 55,589 (2018: TUSD 38,132), respectively. Total revenue increased 9% in the fourth quarter 2019 versus the comparative period due to 29% increase in sales volumes; however, it was offset by 11% lower oil realized prices. Revenue for the full year ended 31 December 2019 was 46% higher against the comparative period due to 65% higher sales volumes while oil realized price was lower by 11%. Lower realized prices are in line with the fluctuations in the Brent oil marker during the related periods. Other revenue in relation to gas sales contract take‐ or‐pay obligations are included in the total oil equivalent realized price calculation.

LAK Ranch production volumes are excluded from sold volumes as this field is still in pre‐production stage. More revenue information can be found in Note 4 to the Condensed Consolidated Financial Statements.

Crude oil realized prices are based on Brent price less/plus current contractual discounts/premiums as follows:

Tie Field crude oil

Crude oil from the Tie Field is sold to Petrobras and a nearby refinery. For crude oil sold to the refinery, the current discount is USD 8/BBL. Effective April 1, 2019 and for the following twelve months, crude oil from the Tie Field to Petrobras' Carmo station is sold at a discount to Brent oil price of USD 6.09/Bbl plus an additional 3.52% discount on the resulting net price. During the quarter, additional oil delivery capacity was obtained through Petrobras' Camboata station which is sold at a discount to Brent oil price of \$10.49/Bbl for the first 22,680 monthly delivered barrels, and \$6.09 thereafter.

Tartaruga Field crude oil

Crude oil from the Tartaruga Field is entirely sold to Petrobras. During the first half of 2019, crude oil from the Tartaruga Field was sold at a premium to Brent of USD 0.41/BBL. Effective July 1, 2019 and for the following twelve months, it will be sold at a premium of USD 0.16/BBL

Royalties

(TUSD, unless otherwise noted)	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
Royalties	1,940	1,624	7,449	4,805
Per unit (USD/BOE)	6.91	7.44	6.99	7.42
Royalties as a % of revenue	14.2%	12.9%	13.4%	12.6%

Royalties are settled in cash and based on realized prices before discounts. Royalty expense increased for the fourth quarter and the full year of 2019, respectively as compared to the comparative periods, consistent with the higher revenue for the same periods. Royalty expense as a percentage of revenues was slightly higher in the fourth quarter and the full year 2019 than the comparative periods due to higher royalty‐rate Tartaruga oil sales during 2019.

⁵ Equivalent realized price calculation includes other revenue

Production expenses

			Full Year	Full Year
(TUSD, unless otherwise noted)	Q4 2019	Q4 2018	2019	2018
Production costs	1,480	1,232	5,022	5,468
Transportation costs	427	303	1,579	942
Total Production expenses	1,907	1,535	6,601	6,410
Per unit (USD/BOE)	6.79	7.04	6.19	9.89

Production expenses is higher by 24% for the current quarter 2019 and amounted to TUSD 1,907 as compared to TUSD 1,535 for Q4 2018 which is in line with higher sales by 29% over the same period. On a per BOE (or unit) basis, production expense decreased by 4% for Q4 2019 and was USD 6.79 per BOE as compared to USD 7.04 per BOE for Q4 2018.

For the full year ended 31 December 2019 total production expense including transportation was only slightly higher than the comparative period despite significantly higher sales volumes by 65%. Maha's production is mainly trucked to the delivery points therefore transportation costs are directly correlated to the sales volumes. Higher sales during the year resulted in higher transportation costs. Excluding transportation, the majority of production expenses are fixed which explains the lower production costs on a per BOE basis as production volumes increases. Also lower on an amount basis by 8% as a result of operating efficiencies gained following facilities upgrades. On a per BOE basis, costs were lower by 37%, as a result of higher sales volumes for the full year of 2019 as compared to 2018.

Operating netback

(TUSD, unless otherwise noted)	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
Operating Netback	9,825	9,436	41,539	26,917
Netback (USD/BOE)	35.00	43.26	38.96	41.57

Operating netback is calculated as revenue less royalties and production expenses and is a metric used in the oil and gas industry to compare performance internally and with industry peers. Operating netback for the current quarter and the full year of 2019 was 4% and 54% higher, respectively against the comparative periods as a result of overall increase in sales volumes despite lower realized prices in the 2019 periods. This is observed on a per BOE basis, where operating netback decreased 19% and 6% for current quarter and the full year reflecting effect of lower realized prices.

LAK Ranch is still in pre‐production stage therefore royalties and operating costs, net of revenues, are being capitalized as part of exploration and evaluation costs and is not included in the Company's netback.

General and Administration ("G&A")

(TUSD, unless otherwise noted)	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
G&A	1,412	899	5,464	4,222
G&A (USD/BOE)	5.03	4.12	5.13	6.52

G&A expenses were higher by 57% and amounted to TUSD 1,412 for the current quarter as compared to the same quarter in 2018 due to additional yearend accruals related to legal fees and other associated costs for internal projects as well as lower capitalized G&A as compared to the amount capitalized for Q4 2018 due to the timing of certain capital projects. On a per BOE basis, G&A expenses increased by 22%.

G&A expense amount to TUSD 5,464 for the full year ended 31 December 2019 and is higher by 29% as compared to the same period in 2018. Higher full year G&A expenses other than the above‐mentioned reasons, relate to a one‐ time bonus payment to staff during 2019, severance costs of a former member of the management and additional fees incurred for the corporate reorganization of entities within Maha Group. On a per BOE basis, G&A expenses are lower by 21% than the comparative period due to higher sales volumes.

G&A amounts are presented net, following allocation of certain costs into production expense and property, plant and equipment based on capital activity levels.

Depletion, depreciation, and amortization ("DD&A")

(TUSD, unless otherwise noted)	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
DD&A	1,382	1,431	5,671	3,762
DD&A (USD/boe)	4.92	6.56	5.32	5.81

The depletion rate is calculated on proved and probable oil and natural gas reserves, taking into account the future development costs to produce the reserves. Depletion expense is computed on a unit‐of‐production basis. The depletion rate will fluctuate on each re‐measurement period based on the capital spending and reserves additions for the period.

DD&A expense decreased for the fourth quarter amounted to TUSD 1,382 (at an average rate of USD \$4.92 per boe) as compared to TUSD 1,431 (at an average rate of USD \$6.56 per boe), despite higher sales volumes in the current quarter. Decrease in the depletion rate is a result of added reserves in the Tie field and the Tartaruga block at the end of the year.

For the full year of 2019 depletion expense on a per BOE basis is also lower than the comparative period due to higher 2P reserves at year end as compared to prior period.

DD&A expense also includes depreciation expense for other equipment and right‐of‐use assets; however, implementation of IFRS 16 did not have a material impact on DD&A expense.

Exploration and business development costs

Exploration and business development costs amounted to TUSD 802 for the fourth quarter and full year 2019 as compared to nil for the comparative period. Exploration and business development costs are related to costs incurred for the maintenance of the exploration blocks in Brazil and Maha's pre‐exploration study of the new areas.

Foreign currency exchange gain or loss

The net foreign currency exchange gain for the current quarter amounted to TUSD 77 (Q4 2018: TUSD 329 gain) and for the full year 2019 amounted to gain of TUSD 159 (2019: TUSD 347 gain). Foreign exchange movements occur on settlement of transactions denominated in foreign currencies and the revaluation of working capital to the prevailing exchange rate at the balance sheet date where those monetary assets and liabilities are held in currencies other than the functional currencies of the Company's reporting entities.

Net finance costs

Net finance items for the current quarter amounted to TUSD 1,096 (Q4 2018: TUSD 1,179) and for the full year of 2019 amounted to TUSD 4,476 (2019: TUSD 4,715) and are detailed in Note 5. The implementation of IFRS 16 did not have a material impact on net finance costs.

Other loss and gain

Other loss amounted to TUSD 83 and TUSD 370 for the current quarter and the full year 2019, respectively as compared to gain of TUSD 822 for the comparative periods. Other loss in the current quarter and full year represents net changes in other long‐term liabilities and provisions. Full year 2019 amount includes impaired full value of a receivable amount for the sale of the Canadian Assets. Prior period gain of TUSD 822 represents reversal of provisions recorded during the acquisition of the Brazilian business unit of Gran Tierra Energy Inc. in July 2017 as the Company was able to negotiate and terminate a contingency payment in relation to meeting certain operational milestones as per the original agreement with prior block owner.

Income Taxes

Current tax expense for the quarter was TUSD 870 as compared to TUSD 19 in the comparative period due to the increased taxable income in Brazil for the current quarter. Current tax expense for the full year of 2019 was TUSD 2,636 as compared to TUSD 710 for the same period last year. Maha has taxes payable in Brazil due to positive taxable income for the quarter and the full year. Taxation of corporate profits in Brazil is a combined 34% rate (25% corporate income tax and 9% Social contribution); however, Maha Energy Brazil has tax incentives (SUDENE) in both of its fields allowing for the reduction of 75% of the corporate income tax of 25% to 6.25%, bringing the combined tax rate to 15.25%.

Deferred tax expense amounted to TUSD 1,519 and TUSD 2,418 for the fourth quarter and the full year, respectively, as compared to tax recovery of TUSD 11,259 for the same comparative periods. The deferred tax expense in the quarter is a result of the unwinding of the deferred tax asset related to estimated tax deductible temporary differences and tax loss carry‐forwards. In 2018, during the fourth quarter the Company determined that there was a reasonable certainty that it will be able to recover previously unrecorded tax assets associated with Tie Field therefore recorded a deferred tax recovery of TUSD 11,259.

Liquidity and capital resources

As at 31 December 2019, the Company had current assets of \$30.4 million comprised primarily of cash and cash equivalents, restricted cash, accounts receivable and prepaid expenses and inventory. The Company had current liabilities of \$7.2 million resulting in net working capital of \$23.2 million (31 December 2018: \$19.3 million).

Financial Risks

The Company is in the oil exploration and development business and is exposed to a number of risks and uncertainties inherent to the oil industry. This activity is capital intensive at all stages and subject to fluctuations in oil prices, market sentiment, currencies, inflation and other risks. The Company has cash in hand and expects to generate cash flow from operations to fund its development, operating and financing activities. Material increases or decreases in the Company's liquidity may be substantially determined by the success or failure of its development activities, as well as its continued ability to raise capital or debt.

A detailed analysis of the Company's strategic, operational, financial and external risks and mitigation of those risks through risk management is described in Maha Energy's 2018 Annual Report and updated in Note 12.

Legal matters

Following the Tie Field Acquisition effective July 1, 2017, the Company inherited, through the acquisition of Gran Tierra Energy Brazil Ltda., a number of disclosed pre‐existing legal matters concerning labor, regulatory and operations. Since taking over operations a number of new similar ordinary course legal matters have arisen. All of these are considered routine, non‐material and consistent with doing business in Brazil. Provisions for lawsuits and changes thereto have, in consultation with the Company's Brazilian legal counsel, been recorded under accrued liabilities and provisions.

Health, Safety and the Environmental ("HSE")

At Maha, HSE is a key component of its management systems. Maha Energy strives to provide a safe and healthy work environment for all employees, contractors and suppliers. This means the safety of life, limb, environment and property always comes first. The Company actively monitors all operational sites and proactively encourages everyone to be mindful of all the Company's HSE Values. This is achieved through education, enforcement and reporting. Everyone working or visiting our sites have the right to stop work at any time to prevent potential HSE incidents occurring. Maha's HSE Values set the tone for how we approach each other and the environment.

Additional information on environmental, decommissioning and abandonment obligations in relation to oil and gas assets is presented in Note 9 to the Condensed Consolidated Financial Statements.

Corporate Governance and Sustainability

Part of contributing to society and being a good global citizen must entail doing 'what is right', in addition to adhering to laws and regulations. One of the ways we ensure sustainability is to maximize recovery from existing energy sources and in order to do so effectively it is important to minimize scope changes. If we can prevent costly and impactful changes in development plans, we contribute to sustainability. Another way to contribute to a sustainable planet, is to ensure all resources are used. We therefore recycle produced water at our LAK Ranch facility which not only reduces having to find water from another source, but also reduces waste water treatment requirements. In Brazil, we are reducing the release of natural gas by using the waste gas from oil production to generate electricity.

Maha does not tolerate any form of corrupt practices and has in place Corporate Governance Policies that clearly define how we must conduct business. The best way to prevent corruption is through transparency ‐ one of our core values. The Company has established a Code of Business Conduct and Anti‐Corruption policies for all its employees, contractors and workers. More information on Corporate Governance can be found in Maha's Corporate Governance Report in the 2018 Annual Report (page 31 – 34).

Seasonal Effects

Maha Energy has no significant seasonal variations.

Parent Company

Business activities for Maha Energy AB focuses on: a) management and stewardship of all Group affiliates, subsidiaries and foreign operations; b) management of publicly listed Swedish entity; c) fundraising as required for acquisitions and Group business growth; and d) business development. Last year's activities focused on organic growth of the existing assets of the Group through a combination of new or enhanced facilities, new offtake arrangements, and drilling and workover operations on existing wells.

The net result for the Parent Company for Q4 2019 amounted to TSEK ‐9,609 (Q4 2018: TSEK 23,759). The result includes general and administrative expenses of TSEK 1,494 (Q4 2018: TSEK 1,002) and net finance costs of TSEK 5,895 (Q4 2018: Finance Income of TSEK 24,918). Net finance cost in the current quarter includes interest expense on Maha's Bond offset by interest income on certain subsidiary interest bearing loans whereas TSEK 24,918 finance income in the comparative period resulted from the recognition of the full year 2018 interest income on certain subsidiary interest bearing loan at the end of the fourth quarter.

The net result for the Parent Company for the full year 2019 amounted to TSEK ‐25,864 (Full Year 2018: TSEK ‐ 10,088). The result includes general and administrative expenses of TSEK 6,020 (Full Year 2018: TSEK 3,655) which is much higher than the comparative period due to additional non‐recurring costs relating to internal projects incurred during the year. Net finance costs of TSEK 21,358 (Full Year 2018: TSEK 9,022) is higher than the comparative period due to lower interest income on Maha's subsidiary loan to offset the interest expense of Maha's Bond. Interest income on Maha's subsidiary loan was lower due to repayment of the loan during the year.

Related Party Transactions

The Company did not enter into any transactions with related parties during the quarter.

Subsequent Events

There are no subsequent events to report.

The financial information relating to the Fourth quarter and Full Year ended 31 December 2019 has not been subject to review by the auditors of the Company.

Approved by the Board

_Jonas Lindvall____________________ Jonas Lindvall, Director

_Anders Ehrenblad____________________ Anders Ehrenblad, Chairman

Financial Statements

Condensed Consolidated Statement of Operations

				Full Year	Full Year
(TUSD)	Note	Q4 2019	Q4 2018	2019	2018
Revenue
Oil and gas sales	3,4	13,672	12,595	55,589	38,132
Royalties		(1,940)	(1,624)	(7,449)	(4,805)
		11,732	10,971	48,140	33,327
Expenses
Production and transportation		(1,907)	(1,535)	(6,601)	(6,410)
General and administration		(1,412)	(899)	(5,464)	(4,222)
Depletion, depreciation, and amortization	6	(1,382)	(1,431)	(5,671)	(3,762)
Exploration and business development costs		(802)	‐	(802)	‐
Stock‐based compensation	10	(59)	(51)	(207)	(217)
Financial derivative instruments	11	‐	‐	‐	(74)
Foreign currency exchange gain (loss)		77	329	159	347
		(5,485)	(3,587)	(18,586)	(14,338)
Operating result		6,247	7,384	29,554	18,989
Net finance costs	5	(1,096)	(1,179)	(4,476)	(4,715)
Other gain / (loss)	12	(83)	822	(370)	822
Result before tax		5,068	7,027	24,708	15,096
Income tax – current		(870)	(19)	(2,636)	(710)
Income tax – deferred		(1,519)	11,259	(2,418)	11,259
Net result for the period		2,679	18,267	19,654	25,645
Earnings per share basic – USD		0.03	0.19	0.20	0.26
Earnings per share fully diluted – USD		0.02	0.17	0.18	0.25
Weighted average number of shares:
Before dilution		100,118,569	98,154,135	99,287,171	97,630,200
After dilution		108,637,250	105,202,009	107,943,095	102,199,428

Condensed Consolidated Statement of Comprehensive Earnings

				Full Year	Full Year
(TUSD)	Note	Q4 2019	Q4 2018	2019	2018
Net Result for the period		2,679	18,267	19,654	25,645
Items that may be reclassified to profit or loss:
Exchange differences on translation of
foreign operations		1,724	2,500	(2,902)	(6,511)
Comprehensive result for the period		4,403	20,767	16,752	19,134
Attributable to:
Shareholders of the Parent Company		4,403	20,767	16,752	19,134

Condensed Consolidated Statement of Financial Position

(TUSD)	Note	December 31, 2019	December 31, 2018
ASSETS
Non‐current assets
Property, plant and equipment	6	76,243	58,834
Exploration and evaluation assets	7	21,216	20,685
Deferred tax assets		7,955	11,259
Performance bonds and others		178	177
Total non‐current assets		105,592	90,955
Current assets
Crude oil inventory		414	57
Prepaid expenses and deposits		1,255	686
Accounts receivable	12	4,739	4,368
Restricted cash	16	1,567	2,804
Cash and cash equivalents		22,450	20,255
Total current assets		30,425	28,170
TOTAL ASSETS		136,017	119,125
EQUITY AND LIABILITIES
Equity
Shareholder's equity	10	87,859	69,274
Liabilities
Non‐current liabilities
Bonds payable	8	30,621	31,180
Decommissioning provision	9	2,175	1,720
Lease liabilities		380	‐
Other long‐term liabilities and provisions		7,812	8,093
Total non‐current liabilities		40,988	40,993
Current liabilities
Accounts payable		4,533	4,029
Accrued liabilities and other		2,406	4,829
Current portion of lease liabilities		231	‐
Total current liabilities		7,170	8,858
TOTAL LIABILITIES		48,158	49,851
TOTAL EQUITY AND LIABILITIES		136,017	119,125

Condensed Consolidated Statement of Cash Flows

				Full Year	Full Year
(TUSD)	Note	Q4 2019	Q4 2018	2019	2018
Operating Activities
Net result		2,679	18,267	19,654	25,645
Depletion, depreciation and amortization	6	1,382	1,431	5,671	3,762
Stock based compensation	10	59	51	207	217
Accretion of decommissioning provision	9	31	25	116	102
Accretion of bond payable	8	249	256	1,001	1,052
Interest expense		939	992	3,816	4,138
Income tax expense		870	‐	2,636	‐
Deferred tax expense		1,519	(11,259)	2,418	(11,259)
Financial derivative instruments	11	‐	‐	‐	139
Unrealized foreign exchange amounts		159	1,323	(433)	1,797
Interest received		14	‐	248	‐
Interest paid		(1,880)	(1,894)	(3,772)	(3,384)
Tax paid		(637)	244	(2,022)	(447)
Changes in working capital	14	(111)	(4,288)	(716)	(3,419)
Cash from operating activities		5,273	5,148	28,824	18,343
Investing activities Capital expenditures ‐ property, plant and
equipment	6	(5,870)	(5,374)	(27,747)	(12,767)
Capital expenditures ‐ exploration and
evaluation assets	7	173	(2,026)	(587)	(2,774)
Restricted cash		1,232	(215)	1,124	(215)
Cash used in investment activities		(4,465)	(7,615)	(27,210)	(15,756)
Financing activities
Lease payments		(122)	‐	(214)	‐
Issue of shares, net of share issue costs		‐	(27)	‐	1,469
Exercise of stock options and warrants (net of
issue costs)	10	403	‐	1,626	252
Cash from financing activities		281	(27)	1,412	1,721
Change in cash and cash equivalents		1,089	(2,494)	3,026	4,308
Cash and cash equivalents at the beginning of
the period		20,421	22,292	20,255	18,729
Currency exchange differences in cash and cash
equivalents		940	457	(831)	(2,782)
Cash and cash equivalents at the end of
the period		22,450	20,255	22,450	20,255

Condensed Consolidated Statement of Changes in Equity

				Retained	Total
		Contributed	Other	(Deficit)	Shareholders'
(TUSD)	Share Capital	Surplus	Reserves	Earnings	Equity
Balance at 1 January 2018	117	61,073	(1,359)	(11,630)	48,201
Comprehensive result
Result for the period	‐	‐	‐	25,645	25,645
Currency translation difference	‐	‐	(6,511)	‐	(6,511)
Total comprehensive result	‐	‐	(6,511)	25,645	19,134
Transactions with owners
Share issue cost	‐	(64)	‐	‐	(64)
Stock based compensation	‐	217	‐	‐	217
Exercise of warrants and options	3	1,783	‐	‐	1,786
Total transactions with owners	3	1,936	‐	‐	1,939
Balance at 31 December 2018	120	63,009	(7,870)	14,015	69,274
Comprehensive result
Result for the period	‐	‐	‐	19,654	19,654
Currency translation difference	‐	‐	(2,902)	‐	(2,902)
Total comprehensive result	‐	‐	(2,902)	19,654	16,752
Transactions with owners
Stock based compensation	‐	207	‐	‐	207
Exercise of warrants and options (net of
issue costs)	2	1,624	‐	‐	1,626
Total transactions with owners	2	1,831	‐	‐	1,833
Balance at 31 December 2019	122	64,840	(10,772)	33,669	87,859

Parent Company Statement of Operations

				Full Year	Full Year
(Expressed in thousands of Swedish Krona)	Note	Q4 2019	Q4 2018	2019	2018
Revenue			‐ ‐	‐	‐
Expenses
General and administrative		(1,494)	(1,002)	(6,020)	(3,655)
Stock‐based compensation	10	1,390	(468)	‐	(1,889)
Foreign currency exchange gain(loss)		(3,610)	311	1,514	5,096
Operating result		(3,714)	(1,159)	(4,506)	(448)
Net finance costs		(5,895)	24,918	(21,358)	(9,022)
Financial instruments	11		‐ ‐	‐	(618)
Result before tax		(9,609)	23,759	(25,864)	(10,088)
Income tax			‐ ‐	‐	‐
Net Result for the period		(9,609)	23,759	(25,864)	(10,088)
Parent Company Balance Sheet
(Expressed in thousands of Swedish Krona)		Note	31 December 2019		31 December 2018
Assets
Non‐current assets
Investment in subsidiaries		210,520			184,219
Loans to subsidiaries			372,531 583,051		410,764 594,983
Current assets
Accounts receivable and other			226		170
Restricted cash		50			50
Cash and cash equivalents			152,115		138,598
			152,391		138,818
Total Assets			735,442		733,801
Equity and Liabilities
Restricted equity
Share capital			1,113		1,091
Unrestricted equity
Contributed surplus			504,682		487,374
Retained earnings			(61,003)		(35,139)
Total unrestricted equity			443,679		452,235
Total equity			444,792		453,326
Non‐current liabilities
Bonds Payable		8	286,037		276,573
Current liabilities
Accounts payable and accrued liabilities			4,613		3,902
Total liabilities			290,650		280,475
Total Equity and Liabilities			735,442		733,801

Parent Company Statement of Changes in Equity

	Restricted
	equity	Unrestricted equity
		Contributed	Retained
(Thousands of Swedish Krona)	Share capital	surplus	Earnings	Total Equity
1 January 2018	1,068	470,545	(25,051)	446,562
Share issue costs	‐	(571)	‐	(571)
Stock based compensation	‐	1,889	‐	1,889
Exercise of warrants and stock options	23	15,511	‐	15,534
Result for the period	‐	‐	(10,088)	(10,088)
31 December 2018	1,091	487,374	(35,139)	453,326
Stock based compensation Exercise of warrants and stock options	‐	1,955	‐	1,955
(net of issue costs)	22	15,353	‐	15,375
Result for the period	‐	‐	(25,864)	(25,864)
31 December 2019	1,113	504,682	(61,003)	444,792

Notes to the Condensed Consolidated Financial Statements

1. Corporate information

Maha Energy AB ("Maha (Sweden)" or "the Company") Organization Number 559018‐9543 and its subsidiaries (together "Maha" or "the Group") are engaged in the acquisition, exploration and development of oil and gas properties.

The Company has operations in Brazil and the United States. The head office is located at Strandvägen 5A, SE‐114 51 Stockholm, Sweden. The Company's subsidiary, Maha Energy Inc., maintains its technical office at Suite 1140, 10201 Southport Road SW, Calgary, Alberta, Canada. The Company has an office in Rio de Janeiro, Brazil and operations offices in Newcastle, Wyoming, USA.

2. Basis of presentation

The condensed consolidated financial statements have been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting, the IFRS adopted by the EU and the Swedish Annual Accounts Act. The financial reporting of the Parent Company (Maha Energy AB) has been prepared in accordance with accounting principles generally accepted in Sweden, with the Swedish Financial Reporting Board recommendation, RFR2, reporting for legal entities and the Swedish Annual Accounts Act.

These condensed consolidated financial statements are stated in thousands of US dollars (TUSD), unless otherwise noted, and have been prepared on a historical cost basis, except for certain financial instruments which are stated at fair value.

The accounting principles as described in the Annual Report 2018 have been used in the preparation of this report, except as identified in the New and Revised Accounting Standards below. Certain information and disclosures normally included in the notes to the annual Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, these condensed consolidated financial statements should be read in conjunction with the annual Consolidated Financial Statements for the year ended 31 December 2018, which have been prepared in accordance with IFRS as adopted by the European Union (EU).

New and Revised Accounting Standards

The Group has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective in the EU.

Adoption of IFRS 16, "Leases"

Effective January 1, 2019, the Company adopted IFRS 16, "Leases" ("IFRS 16"). The Company has applied the new standard using the modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard prospectively. Therefore, the comparative information in the Company's Condensed Consolidated Statement of Financial position, Condensed Consolidated Statements of Operations and Statement of Comprehensive Earnings and Condensed Consolidated Statements of Cash flows have not been restated.

On adoption, Management elected to use the following practical expedients permitted under the standard:

• Right of use (ROU) assets will be measured at an amount equal to the lease liability;
• Leases with a less than 12 months remaining lease term at year end 2018 will not be reflected as leases;
• Apply a single discount rate to a portfolio of leases with similar characteristics;
• The use of hindsight in determining the lease tern where the contract contains terms to extend or terminate the lease;
• The Company has made the following application policy choice: short‐term leases (less than 12 months) and leases of low value assets will not be reflected in the balance sheet, but will be expensed as incurred.

No other standards, amendments or interpretations that have come into force in 2019 are expected to have any material impact on the Company.

Update to Significant Accounting Policies

Leases

The following accounting policy is applicable from 1 January 2019:

The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration in the contract to each lease component on the basis of their relative stand‐alone prices.

Leases are recognized as a ROU asset as part of the property, plant and equipment and a corresponding lease liability at the date on which the leased asset is available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of fixed payments, variable lease payments that are based on an index or a rate, amounts expected to be paid by the lessee under residual value guarantees, the exercise price of purchase options if the lessee is reasonably certain to exercise that option, and payments of penalties for terminating the lease, less any lease incentives receivable. These payments are discounted using the Company's incremental borrowing rate when the rate implicit in the lease is not readily available.

Lease payments are allocated between the liability and finance costs. The finance cost is charged to net earnings over the lease term.

The lease liability is measured at amortized cost using the effective interest rate method. It is remeasured when there is a change in the future lease payments arising from a change in an index or rate, if there is a change in the amount expected to be payable under a residual value guarantee or if there is a change in the assessment of whether the Company will exercise a purchase, extension or termination option that is within the control of the Company. When the lease liability is remeasured, a corresponding adjustment is made to the carrying amount of the ROU asset or is recorded in the consolidated statement of earnings if the carrying amount of the ROU asset has been reduced to zero.

The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on which it is located less any lease payments made at or before the commencement date. The ROU asset is depreciated, on a straight‐line basis, over the shorter of the estimated useful life of the asset or the lease term. The ROU asset may be adjusted for certain remeasurements of the lease liability and impairment losses. Leases that have terms of less than Full Year or leases on which the underlying asset is of low value are recognized as an expense in the consolidated statement of earnings on a straight‐line basis over the lease term.

A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and if the consideration for the lease increases by an amount commensurate with the stand‐alone price for the increase in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate, at the effective date of the lease modification, the Company will remeasure the lease liability using the Company's incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate decrease in scope.

The parent company applies to the exception rule in RFR2, which means that the legal entity does not have to apply IFRS 16. The impacts of adoption of IFRS 16 as at January 1, 2019 resulted in recognition of additional lease liability and ROU assets of TUSD 427.

Going Concern

The Company prepared these consolidated financial statements on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due.

3. Segment Information

The Company operates in Canada, Sweden, Brazil and the United States of America. Operating segments are based on a geographic perspective and reported in a manner consistent with the internal reporting provided to the executive management. The following tables present the operating result for each segment from continuing operations. Revenue and income relate to external (non‐intra group) transactions.

(TUSD)	Canada	US	Brazil	Sweden	Other6	Consolidated
For Full Year ended 31 December 2019
Revenue	‐	‐	55,589	‐	‐	55,589
Royalties	‐	‐	(7,449)	‐	‐	(7,449)
Production and operating	‐	‐	(6,601)	‐	‐	(6,601)
General and administration	(2,907)	(226)	(1,642)	(689)	‐	(5,464)
Depletion, depreciation and
amortization	(13)	(88)	(5,570)	‐	‐	(5,671)
Exploration and business
development costs	‐	(331)	(471)	‐		(802)
Stock‐based compensation	(207)	‐	‐	‐	‐	(207)
Foreign currency exchange
gain (loss)	230	‐	122	34	(227)	159
Operating results	(2,897)	(645)	33,978	(655)	(227)	29,554
Net finance costs	‐	(16)	347	(4,807)		(4,476)
Other loss	(239)	‐	(131)	‐	‐	(370)
Current income tax	‐	‐	(2,634)	(2)	‐	(2,636)
Deferred income tax	‐	‐	(562)	‐	(1,856)	(2,418)
Net results	(3,136)	(661)	30,998	(5,465)	(2,083)	19,654
(TUSD)	Canada	US	Brazil	Sweden	Other6	Total
For Full Year ended 31 December 2018
Revenue	‐	‐	38,132	‐	‐	38,132
Royalties	‐	‐	(4,805)	‐	‐	(4,805)
Production and operating	‐	‐	(6,410)	‐	‐	(6,410)
General and administration	(2,147)	(160)	(1,495)	(420)	‐	(4,222)
Stock‐based compensation	‐	‐	‐	(217)	‐	(217)
Depletion, depreciation and
amortization	(12)	(45)	(3,705)	‐	‐	(3,762)
Financial derivative
instruments	‐	‐	‐	(74)	‐	(74)
Foreign currency exchange
gain (loss)	43	‐	(29)	(361)	‐	(347)
Operating results	(2,202)	(205)	21,746	(350)	‐	18,989
Net finance costs	‐	(13)	(3,664)	(1,037)	‐	(4,715)
Gain on contractual
liabilities	‐	‐	822	‐	‐	822
Current income tax	‐	‐	(710)	‐	‐	(710)

Deferred income tax ‐ ‐ 12,603 ‐ (1,344) 11,259 Net results (2,202) (218) 30,796 (1,387) (1,344) 25,645

⁶ Other represents intercompany eliminations and consolidation adjustments.

All oil and gas revenue, operating expenses and depletion are from the Brazilian operations. The Company had two large customers during Q4 2019 (Q4 2018: two) that individually accounted for more than 10 percent of the Company's consolidated gross sales. Total sales to these customers for the full year of 2019 were approximately USD \$54.4 million (Full Year 2018: \$36.5 million), which are included in the Company's Brazil operating segment. Approximately, 56 percent of the total revenue is contracted with one customer in the Brazil segment. There were no intercompany sales or purchases of oil and gas during the period.

4. Revenue

The Company's oil and gas sales revenues are predominantly derived from two major customers, under contracts based on floating prices utilizing the Brent oil benchmark adjusted for contracted discounts or premiums. For the Q4 2019, 100% (Q4 2018: 100%) of the Company's revenue resulted from oil and gas sales in Brazil.

Disaggregated revenue information:

The Company derives revenue from the transfer of goods at a point in time in the following major commodities from oil and gas production and the only geographical region of Brazil:

TUSD	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
Crude oil	13,490	12,464	54,930	37,785
Natural gas	168	131	604	347
Other	14	‐	55	‐
Total revenue from contracts with customers	13,672	12,595	55,589	38,132

The Company had no contract asset or liability balances during the period presented. As at 31 December 2019, accounts receivable included \$3.4 million of accrued sales revenue which related to December 2019 production. Revenue is measured at the consideration specified in the contracts and represents amounts receivable net of discounts and sales taxes. Performance obligations associated with the sale of crude oil are satisfied when control of the product is transferred to the customer. This occurs when the oil is physically transferred to the delivery point agreed with the customer and the customer obtains legal title. Other revenue is related to gas sales contract take‐ or‐pay obligations.

LAK revenue, net of expenditures, is capitalized as part of the exploration and evaluation assets and will continue until commercial viability of the field is achieved as the property is still in pre‐production stage.

5. Finance Costs

TUSD	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
Interest on bond payable (note 8)	936	992	3,808	4,138
Accretion of bond payable (note 8)	249	256	1,001	1,052
Accretion of decommissioning provision	31	25	116	102
Risk management contracts	‐	‐	‐	66
Interest income and other	(120)	(94)	(449)	(643)
	1,096	1,179	4,476	4,715

6. Property, Plant and Equipment (PP&E)

	Oil and gas	Equipment and	Right‐of‐use
(TUSD)	properties	Other	assets	Total
Cost
1 January 2018	54,284	2,151	‐	56,435
Additions	16,732	18	‐	16,750
Currency translation adjustment	(8,891)	(108)	‐	(8,999)
1 January 2019 (Note 2)	62,125	2,061	427	64,613
Additions	24,615	118	413	25,146
Change in decommissioning cost	436	‐	‐	436
Currency translation adjustment	(3,259)	(16)	(27)	(3,302)
31 December 2019	83,917	2,163	813	86,893
Accumulated depletion, depreciation and amortization
1 January 2018	(1,807)	(302)	‐	(2,109)
DD&A	(3,583)	(146)	‐	(3,729)
Currency translation adjustment	471	15	‐	486
1 January 2019	(4,919)	(433)	‐	(5,352)
DD&A	(5,178)	(288)	(204)	(5,670)
Currency translation adjustment	346	24	2	372
31 December 2019	(9,751)	(697)	(202)	(10,650)
Carrying amount
31 December 2018 (Note 2)	57,206	1,628	427	59,261
31 December 2019	74,166	1,466	611	76,243
7. Exploration and Evaluation Assets (E&E)
TUSD
1 January 2018				17,789

1 January 2018	17,789
Additions in the period	3,154
Decommissioning obligation	121
Incidental result from sale of crude oil	(379)
31 December 2018	20,685
Additions in the period	165
Change in estimates	(56)
Operating costs capitalized (net of Incidental revenue
from sale of crude oil)	422
31 December 2019	21,216

As at 31 December2019, the LAK Ranch property had not established both technical feasibility and commercial viability and therefore remains classified as an E&E asset. Expenditures, net of revenues, for the LAK Ranch Project have been capitalized as E&E.

8. Bond payable

	TUSD	TSEK
1 January 2018	32,678	267,423
Accretion of bond liability	1,052	9,150
Effect of currency translation	(2,550)	‐
31 December 2018	31,180	276,573
Accretion of bond liability	1,001	9,464
Effect of currency translation	(1,560)	‐
31 December 2019	30,621	286,037

For the fourth quarter 2019 Maha recognized TUSD 936 of interest and TUSD 249 of accretion related to the Bonds.

The Bonds have the following maintenance covenants at each quarter end and on a rolling 12 months basis:

• i) Net Interest Bearing Debt to EBITDA is not greater than 3.00 (Leverage test);
• ii) Interest Coverage Ratio exceeds 2.25; and
• iii) Cash and cash equivalents exceeds USD \$5 million

The next reference test date for the maintenance covenants is 31 December 2019 which is reported following the release of this report and within two months following such reference date. As at the last reference date of 30 September 2019, the Company was compliant with all bond covenants. Based on the reported results herein, the Company expects that it will be complaint with its bond covenants for the current period.

9. Decommissioning Provision

The following table presents the reconciliation of the opening and closing decommissioning provision:

(TUSD)
1 January 2018	1,849
Accretion expense	102
Additions	121
Foreign exchange movement	(352)
31 December 2018	1,720
Accretion expense	116
Additions	185
Change in estimate	194
Foreign exchange movement	(40)
31 December 2019	2,175

10. Share Capital

	Number of Shares by Class
Shares outstanding	A	B	C2	Total
1 January 2018	85,972,025	9,183,621	1,698,000	96,853,646
Exercise of warrants	2,074,717	‐	‐	2,074,717
Conversion of convertible B shares	1,073,739	(1,073,739)	‐	‐
Exercise of Maha (Canada) options	1,138,687	‐	(1,138,687)	‐
Cancelled options	‐	‐	(509,313)	(509,313)
31 December 2018	90,259,168	8,109,882	50,000	98,419,050
Exercise of warrants	1,997,818	‐	‐	1,997,818
Conversion of convertible B shares	149,564	(149,564)	‐	‐
Exercise of Maha (Canada) options	50,000		(50,000)	‐
31 December 2019	92,456,550	7,960,318	‐	100,416,868

Total outstanding warrants as at 31 December 2019 are Maha A TO2 share purchase warrants:

	Number of Warrants	Exercise Price	Exercise Price
	#	SEK	USD
1 January 2018	19,550,963	7.12	0.87
Exercised	2,074,717	6.40	0.72
Expired	(4,126,246)	6.40	0.72
31 December 2018	13,350,000	7.45	0.84
Exercised	(1,997,818)	7.45	0.78
31 December 2019	11,352,182	7.45	0.80

Warrant Incentive Program

The Company has an incentive program as part of the remuneration package for management and employees. 2019 incentive warrants were issued during the second quarter 2019. Issued but not allocated warrants are held by the Company. No incentive warrants were expired or exercised during 2019.

Warrants			Number of warrants
incentive	Exercise	Exercise		Issued	Expired	Exercised	Cancelled	31 December
programme	period	price, SEK	1 Jan 2019	2019	2019	2019	2019	2019
2017	1 June 2020 –
incentive	31 December
programme	2020	7.00	750,000	‐	‐	‐	‐	750,000
2018	1 May 2021 –
incentive	30 November
programme	2021	9.20	750,000	‐	‐	‐	‐	750,000
2019	1 June 2022 –
incentive	28 February
programme	2023	28.10	‐	500,000	‐	‐	‐	500,000
Total			1,500,000	500,000	‐	‐	‐	2,000,000

The dilution effect of the warrants of the in‐the‐money warrants are included in the weighted average number of shares after dilution which amounted to 108,637,250 for the fourth quarter and 107,943,095 for the full year ended 31 December 2019.

11. Financial assets and liabilities

For financial instruments measured at fair value in the balance sheet, the following fair value measurement hierarchy is used:

– Level 1: based on quoted prices in active markets;

– Level 2: based on inputs other than quoted prices as within level 1, that are either directly or indirectly observable;

– Level 3: based on inputs which are not based on observable market data.

The Company's cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities are assessed on fair value hierarchy described above. The fair value of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their carrying value due to the short term to maturity of these instruments. The bonds are carried at amortized cost. For the disclosure purposes, the estimated fair values of the bonds have been determined based on the adjusted period‐end trading prices of the bonds on the secondary market (Level 2). As at 31 December 2019, the carrying value of the Bonds was TUSD 30,621 and the fair value was TUSD 34,519 (31 December 2018: carrying value – TUSD 31,180; fair value – TUSD 35,850).

12. Management of financial risk

The Company thoroughly examines the various risks to which it is exposed and assesses the impact and likelihood of those risks. The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and to monitor market conditions and the Company's activities. This approach actively addresses risk as an integral and continual part of decision making within the Company and is designed to ensure that all risk is identified, fully acknowledged, understood and communicated well in advance. Nevertheless, oil and gas exploration, development and production involve high operational and financial risks, which even a combination of experience, knowledge and careful evaluation may not be able to fully eliminate or which are beyond the Company's control. The Board of Directors has overall responsibility for establishment and oversight of the Company's risk management.

A detailed analysis of Maha's operational, financial, and external risks and mitigation of those risks through risk management is described in Maha Energy's 2018 Annual Report.

Credit risk is the risk of unexpected loss if a customer or third party to a financial instrument fails to meet its contractual obligations. The Company's cash and cash equivalents are primarily held at large financial institutions.

The Company's accounts receivable is composed of:

TUSD	31 December 2019	31 December 2018
Oil and gas sales (Brazil)	4,394	3,127
Sale of Canadian assets	‐	280
Tax credits and other receivables	345	961
	4,739	4,368

The majority of the Company's oil and gas sales receivables are with the Brazilian national oil company and an independent refinery called Dax Oil Refino SA (Dax). Under the marketing agreement with Dax, most of the oil sales are prepaid prior to delivery with occasional credit granted to maintain daily deliveries. In addition, the Company has made an arrangement with Dax to accumulate an amount up to maximum of TUSD 900 in accounts receivable which is guaranteed through a performance bond issued by a local bonding company and is expected to be fully recoverable. During the third quarter, the Company impaired the full value of its receivable from the Sale of Canadian assets and recorded other loss of TUSD 287. Maha is no longer confident that it would be able to collect this receivable.

13. Management of Capital

The Company manages its capital to support the Company's strategic growth objectives and maintain financial capacity and flexibility for the purpose of funding the Company's exploration and development activities. The Company considers its capital structure to include working capital and shareholders' equity. At 31 December 2019, the Company's net working capital surplus was USD \$23.2 million (31 December 2018: USD \$19.3 million), which includes USD \$22.5 million (31 December 2018: USD \$20.2 million) of cash and USD \$1.6 million (31 December 2018: \$2.8 million) of restricted cash. The restricted cash relates to cash posted in Brazil to guarantee letters of credit for certain work commitments and support of abandonment guarantees.

The Company may adjust its capital structure by issuing new equity or debt and adjusting its capital expenditure program, as allowed pursuant to contracted work commitments. The Company considers its capital structure at this time to include shareholders' equity of USD \$87.9 million (31 December 2018: USD \$69.3 million). The Company does not have any externally imposed material capital requirements to which it is subject except for the Bond covenants (See Note 8). In order to facilitate the management of its capital requirements, the Company prepares annual expenditure budgets that are updated as necessary depending on various factors, including successful capital deployment and general industry conditions. The annual and updated budgets are approved by the Board of Directors.

14. Changes in non‐cash Working Capital

(TUSD)	31 December 2019	31 December 2018
Change in:
Accounts receivable	(619)	(2,797)
Inventory	(340)	232
Prepaid expenses and deposits	(569)	67
Accounts payable and accrued liabilities	812	(921)
Total	(716)	(3,419)

15. Pledged Assets

As at 31 December 2019, pledged assets are mainly a continuing security for the Senior Secured Bonds where Maha has entered into a pledge agreement. The pledge relates to the shares in its subsidiaries: Maha Energy 1 (Brazil) AB, Maha Energy 2 (Brazil) AB, Maha Energy Inc. and Maha Energy Finance (Luxembourg) S.A.R.L. The pledged assets for the parent company as at 31 December 2019 amounted to SEK 186.2 million (31 December 2018: SEK 184.2 million) representing the carrying value of the pledge over the shares of subsidiaries. The combined net asset value for the Group of the subsidiaries whose shares are pledged amounted to USD 83.6 million (31 December 2018: USD 69.3 million).

The Company also granted a charge against a term deposit in Brazil to guarantee certain financial instruments in relation to its work commitments (See Note 16).

16. Commitments and Contingencies

Work commitments in relation to exploration blocks in Brazil have been recorded as long‐term provisions and are guaranteed with certain credit instruments in place of approximately BRL 19.0 million (\$4.7 million) and the remainder BRL 14.3 million (\$3.5 million) are guaranteed by a term deposit of \$1.6 million (2018: \$2.7 million). This term deposit has been presented as restricted cash on the Statement of Financial Position. During the fourth quarter, approximately \$1.3 million of this term deposit was released from restricted cash.

During Q3, Maha received the pending environmental licenses on two of its concessions resulting in a requirement to fulfill its work commitments by Q1 2021 or relinquish the blocks.

These commitments are in the normal course of the Company's exploration business and the Company's plans to fund these, if necessary, with existing cash balances, cash flow from operations and available financing sources.

Key Financial Data

Maha believes that the alternative performance measures provide useful supplemental information to management, investors, securities analysts and other stakeholders and are meant to provide an enhanced insight into the financial development of Maha's business operational.

Financial data from continuing operations

TUSD			Full Year
	Q4 2019	Q4 2018	2019	Full Year 2018
Revenue	13,672	12,595	55,589	38,132
Operating netback	9,825	9,436	41,539	26,917
EBITDA6	8,354	8,486	35,868	22,404
Net result	2,679	18,267	19,654	25,645
Cash Flow from operations	5,273	5,148	28,824	18,343

Capital structure

	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
Return on equity (%)	3	26	22	37
Equity ratio (%)	65	58	65	58
NIBD/EBITDA	0.2	0.5	0.2	0.5
TIBD/EBITDA	0.8	1.4	0.8	1.4

Other

	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
Weighted number of shares
(before dilution)	100,118,569	98,154,135	99,287,171	97,630,200
Weighted number of shares
(after dilution)	108,637,250	105,202,009	107,943,095	102,199,428
Earnings per share before
dilution, USD	0.03	0.19	0.20	0.26
Earnings per share after
dilution, USD	0.02	0.17	0.18	0.25
Dividends paid per share	n/a	n/a	n/a	n/a

Key Ratio Definition

Return on equity:

Net result divided by ending equity balance

Equity ratio:

Total equity divided by the balance sheet total.

Net debt to EBITDA ratio (NIBD/EBITDA)

Net interest bearing debt divided by trailing 4 quarters EBITDA.

Total debt to EBITDA ratio (TIBD/EBITDA)

Total interest bearing debt divided by trailing 4 quarters EBITDA

Earnings per share:

Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares for the year.

Earnings per share fully diluted:

Net result attributable to shareholders of the Parent Company divided by the weighted average number of shares after considering any dilution effect for the year.

Weighted average number of shares for the year:

The number of shares at the beginning of the year with changes in the number of shares weighted for the proportion of the year they are in issue.

Weighted average number of shares for the year fully diluted:

The number of shares at the beginning of the year with changes in the number of shares weighted for the proportion of the year they are in issue after considering any dilution effect.

Relevant reconciliation of Alternative Performance Measures:

Operating Netback

Operating netback is calculated on a per‐boe basis and is defined as revenue less royalties, transportation costs and operating expenses, as shown below:

(TUSD)	Q4 2019	Q4 2018	Full Year 2019	Full Year 2018
Revenue	13,672	12,595	55,589	38,132
Royalties	(1,940)	(1,624)	(7,449)	(4,805)
Operating Expenses	(1,480)	(1,232)	(5,022)	(5,468)
Transportation costs	(427)	(303)	(1,579)	(942)
Operating netback	9,825	9,436	41,539	26,917

EBITDA7

Earnings before interest, taxes, depreciation and amortization and non‐recurring items (such as other gain and losses and exploration and business development costs) is used as a measure of the financial performance of the Company and is calculated as shown below:

			Full Year	Full Year
(TUSD)	Q4 2019	Q4 2018	2019	2018
Operating results	6,247	7,384	29,554	18,989
Depletion, depreciation and amortization	1,382	1,431	5,671	3,762
Exploration and business development costs	802	‐	802	‐
Foreign currency exchange loss / (gain)	(77)	329	(159)	(347)
EBITDA	8,354	8,486	35,868	22,404

⁷ Effective 1 January 2019, implementation of IFRS 16 (Leases) did not have material impact on the EBITDA of the Company therefore prior period EBITDA has not been restated for presentation purposes.

Financial calendar

2019 Annual Report: 30 April 2020 2020 First Quarter: 26 May 2020 2020 Second Quarter: 24 August 2020 2020 Third Quarter: 23 November 2020

Contact information

For further information please contact:

Jonas Lindvall (CEO) Tel: +1 403 454 7560 Email: jonas@mahaenergy.ca

Andres Modarelli (CFO)

Tel: +1 403 454 7560 Email: andres@mahaenergy.ca

Victoria Berg (Investor Relations) Tel: +46 8 611 05 11

Email: victoria@mahaenergy.ca

Maha Energy AB Head Office	Strandvagen 5A SE‐114 51 Stockholm, Sweden (08) 611 05 11
Maha Energy AB	Suite 1140, 10201 Southport Road SW
Technical Office	Calgary, Alberta T2W 4X9
	403‐454‐7560
Email	info@mahaenergy.ca