Maha Energy

Earnings Release • Nov 25, 2019

Report for the THREE AND NINE MONTHS ENDED 30 SEPTEMBER 2019 (org number: 559018‐9543)

Highlights

(all amounts are in US dollars unless otherwise noted)

Third Quarter 2019

• Daily oil & gas production for Q3 2019 averaged 3,593 BOEPD (Q3 2018: 1,565 BOEPD).
• Effective August 1, 2019, the Company grew its Proven (1P) and Proven plus Probable (2P) reserves, by 14% and 62% respectively, at the Tie Field in Brazil.
• During the quarter, the Maha‐1 well on the Tartaruga Field was successfully drilled with production testing operations to follow.
• Revenue of USD 16.1 million (Q3 2018: USD 9.0 million)
• Operating netback of USD 12.0 million or USD 38.22 per BOE (Q3 2018: USD 6.6 million or USD 46.17 per BOE)
• EBITDA of USD 10.7 million (Q3 2018: USD 5.4 million)
• Net result of USD 6.6 million (Q3 2018: USD 3.2 million)
• Basic Earnings per share of USD 0.07 (Q3 2018: USD 0.03)
• Diluted Earnings per share of USD 0.06 (Q3 2018: USD 0.03)

Nine Months Ended 30 September 2019

• Daily oil & gas production for the nine months 2019 3,004 BOEPD (2018: 1,585 BOEPD).
• Revenue of USD 41.9 million (2018: USD 25.5 million)
• Operating netback of USD 31.7 million or USD 40.38 per BOE (2018: 17.5 USD million or 40.70 USD per BOE)
• EBITDA of USD 27.5 million (2018: USD 13.9 million)
• Net result for the period of USD 17.0 million (2018: USD 7.4 million)
• Basic Earnings per share of USD 0.17 (2018: USD 0.08)
• Diluted Earnings per share of USD 0.16 (2018: USD 0.07)
• Cash and cash equivalents balance of USD 20.4 million (2018: 22.3 million).

Financial Summary

						Nine	Nine
	Q3	Q2	Q1	Q4	Q3	Months	Months	FY
(TUSD, unless otherwise noted)	2019	2019	2019	2018	2018	2019	2018	2018
Net Daily Production (BOEPD)	3,593	2,739	2,669	2,454	1,565	3,004	1,585	1,804
Revenue	16,068	14,098	11,751	12,595	9,049	41,917	25,537	38,132
Operating netback	12,017	10,668	9,029	9,436	6,553	31,714	17,481	26,917
EBITDA	10,663	9,188	7,663	8,486	5,392	27,514	13,918	22,404
Net result for the period	6,570	6,157	4,248	18,2671	3,213	16,975	7,378	25,645
Earnings per share – Basic (USD)	0.07	0.06	0.04	0.19	0.03	0.17	0.08	0.26
Earnings per share – Diluted (USD)	0.06	0.06	0.04	0.17	0.03	0.16	0.07	0.25
Cash and cash equivalents	20,421	20,504	19,768	20,255	22,292	20,421	22,292	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	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,

Notwithstanding the recently announced reduction in the estimated 2019 annual production volumes, the third quarter was very positive for Maha with many significant "bright spots".

Of particular note:

‐ the drilling and completing of the Attic well at the Tie Field resulted in a 62% increase in Proven and Probable (2P) reserves from 10.734 MMbbl of oil to 17.365 MMbbl of oil which nearly doubled the predicted plateau production rate at the Tie field from 3 to almost 6 years;

‐ the successful drilling of the Maha ‐1 well with better than expected indications of 72 m of net pay, that will be tested using a smaller and 'fit for purpose' workover rig; and,

‐ final approval and commissioning of Petrobras' second receiving terminal at Comboata that now takes delivery of 750 BOPD of Tie Field oil.

2019 Annual Average Production Rates were reduced to 2750 BOPD – 2,900 BOPD

Subsequent to this reporting period, Maha's 2019 estimated annual average production rate was unfortunately revised for a second time this year due to delays in start‐up and commissioning of gas handling and disposal equipment at the Tie Field. A string of simultaneous events culminated in requiring to reduce oil production to prevent exceeding Government imposed flaring restrictions during the last 2 months of the year. This revision is in no way indicative of the Tie Field's current or future oil producing capacity and we are working very hard to "get back on track" to earlier expectations.

2P Reserves up by 62% at the Tie Field – now at 17.365 Million Barrels of Oil

By far the biggest news of the third quarter were the results of the re‐mapping of the Tie structures following the results of the recently drilled 'Attic Well'. Remapping of the structure resulted in a substantially larger structure and more "in situ" oil volumes. With these increased reserves the Field Development Plan will be revised to include more wells, and a longer plateau production rate. To this end, the Company is commencing a new field modelling project for this expansion. Notably it appears clear the Tie Field production plateau of 4,850 BOPD will extend by up to 3 years resulting in a significant corresponding positive effect on the Tie Field's, and therefore the Company's, Net Present Value.

Petrobras Comboata Terminal Commissioned

After nearly a year of 'to and from' ‐the Comboata Oil Terminal commenced taking oil deliveries from the Tie Field. Following 2 weeks of "teething" issues, the Terminal now takes its daily allotment of 750 BOPD and Petrobras is now therefore able to receive a total of 1,850 BOPD from the Tie Field at two terminals. With the local refinery currently taking up to 2,200 BOPD – the Company has off‐take capacity for up to 4,050 BOPD for Tie Field oil right now. This is a significant increase from July 2017 when the Tie Field was purchased and offtake was limited to 1,100 BOPD.

The local refinery still awaits a final Government permit to utilize its new expansion upon which the Company can increase its deliveries from the Tie field by a further 800 BOPD. At that point ‐ Maha will be able to sell and deliver 4,850 BOPD from the Tie field.

Tartaruga

Maha‐1 (7‐TTG‐3D‐SES) well was spudded on 12 July, 2019 and total depth was reached on 3 October, 2019. After an extensive coring and electric logging program, initial results show that all the Penedo sandstone stringers are continuous and a total of 72 m. of net pay has been calculated. The Drilling rig was demobilized allowing for a smaller workover rig ("test rig") to be mobilized. This test rig is expected at the Tartaruga site towards the end of November, after which the Maha‐1 well will be extensively tested over a period of up to 90 days. While the test rig is at the Tartaruga site, the 107D horizontal well will finally be cleaned out and tested properly. At the moment, the plan is to test 107D before commencing testing of the Maha‐1 well.

As is apparent, there is a lot going on and much to be excited about. The increase in 2P reserves at the Tie field is significant to the fundamental value of the Company. The facility improvement investments already made and the newly extended Tie Field production plateau secures long term positive cash flow for the Company. The testing of new Penedo sands at Tartaruga are, if positive, a gateway to continued solid organic growth!

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 Third Quarter and Nine months ended September 30, 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	391	Petrobras (25%)
Brazil	Tie (REC‐T 155)	100%	Producing	1,511	3,171
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 be produced individually from both the AG and Sergi zones.

² As per the current quarter reported net production volumes. 1BBL = 6000SCF of gas. Approximately 93% of Maha's oil equivalent production is crude oil.

GTE‐4 (oil producer)

GTE‐4 continued to free flow during the quarter. 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.

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 and is currently producing from both zones.

Production Facilities

The production facilities at the Tie Field were upgraded from its original 2,000 BOPD handling capacity to about 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.

Average production from the Tie Field during the current quarter was 3,171 BOEPD (2,889 BOPD and 1,693 MSCFPD of gas).

As disclosed on November 11, production at the Tie Field is currently being restricted due to delays in the group separator commissioning, delays in commissioning of Gas‐to‐Wire generators, higher associated gas from lower water injection volumes and expiring flaring dispensations. Production volumes are expected to increase as: i) more Gas‐to‐Wire generators are connected to the grid; ii) water injection volumes increases; and iii) the group separator is fully functioning.

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.

107D Sidetrack

In early 2019, drilling of the 107D horizontal sidetrack was completed with a 500 m long horizontal hole in the Penedo‐1 sandstone penetrating 312 m. 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. Subsequent well clean up and testing operations resulted in a continuous free flow of approximately 80 BOPD, 50 BWPD and 33 MSCFPD over a test period of seven days. Due to excessive emulsion problems (of the produced fluid) and surface handling constraints (insufficient tank volumes and heater treater limitations) the well test was stopped before the well was completely cleaned up. The fact that the well flowed unassisted to surface whilst still unloading large volumes of completion brine and drilling fluids is very encouraging. The well will be re‐entered, completed and flow‐tested, towards the end of 2019.

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

On July 12, 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 will be brought in to assist in well testing operations. Maha‐1 will undergo extensive well tests to evaluate previously untested Penedos sandstone stringers. Following testing operations, the Maha‐1 well will be completed and placed on production.

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. The production test results from the 107D Sidetrack and the Maha‐1 well will dictate upgrade requirements for the production handling facilities at the Tartaruga Field. During the second half of 2019, facilities upgrade work began to handle up to 2,500 BOPD and 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. The Tartaruga facilities have not been shut in during the drilling activities of the Maha‐1 (7‐TTG‐3D) well.

Average net production from the Tartaruga Field during the current quarter was 391 BOPD

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 30 September 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 was 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 by the end of this year.

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

Production

			Nine	Nine
			Months	Months	Full Year
	Q3 2019	Q3 2018	2019	2018	2018
Delivered Oil (Barrels)3	304,585	135,714	761,701	398,301	609,087
Delivered Gas (MSCF)	155,753	49,853	349,785	206,072	296,189
Delivered Oil & Gas (BOE)4	330,544	144,023	819,999	432,647	658,452
Daily Volume (BOEPD)	3,593	1,565	3,004	1,585	1,804

Production volumes shown are net working interest volumes before government, gross overriding and freehold royalties. Approximately 92% of Maha's oil equivalent production is crude oil.

Average daily production volumes increased by 130% and 90% for Q3 and the nine months ended September 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 Q3 2018, Tartaruga Field production was mostly shut in during the 107D drilling activities.

Revenue

			Nine	Nine
			Months	Months	Full Year
(TUSD, unless otherwise noted)	Q3 2019	Q3 2018	2019	2018	2018
Oil and Gas revenue	16,068	9,049	41,917	25,537	38,132
Sales volume (BOE)	314,491	141,946	785,313	429,484	647,607
Oil realized price (USD/bbl)	54.93	67.68	57.00	64.35	63.18
Gas realized price (USD/MSCF)	1.14	0.87	1.25	1.00	1.17
Oil Equivalent realized price (USD/Boe)5	50.96	63.75	53.32	59.46	58.88
Reference price – Average Brent (USD/bbl)	61.93	75.07	64.67	71.53	71.06

Revenue for Q3 and the nine months ended 30 September 2019 amounted to TUSD 16,068 (2018: TUSD 9,049) and TUSD 41,917 (2018: TUSD 25,537), respectively. Total revenue increased 78% in Q3 2019 versus the comparative period due to 122% increase in sales volumes offset by 19% lower oil realized prices. Revenue for the nine months ended September 2019 was 64% higher against the comparative period due to 83% higher sales volumes while total realized price was lower by 10%. Lower realized prices are in line with the fluctuations in the Brent oil marker during the related periods. Higher sales volume in the current quarter are a result of higher production volumes in the Tie Field and Tartaruga Field oil sales following two months of inventory built up.

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

⁵ Equivalent realized price calculation excludes other revenue

Other revenue in relation to gas sales contract take‐or‐pay obligations are excluded from realized price calculation but included in the per BOE netback. 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 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 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

			Nine	Nine
			Months	Months	Full Year
(TUSD, unless otherwise noted)	Q3 2019	Q3 2018	2019	2018	2018
Royalties	2,130	1,052	5,509	3,181	4,805
Per unit (USD/BOE)	6.77	7.41	7.01	7.41	7.42
Royalties as a % of revenue	13.3%	11.6%	13.1%	12.5%	12.6%

Royalties are settled in cash and based on realized prices before discounts. Royalty expense increased for Q3 and the nine months of 2019, respectively, as compared to the comparative periods being consistent with the higher revenue for the same periods. Royalty expense as a percentage of revenues was slightly higher in Q3 2019 than the comparative period due to higher royalty‐rate Tartaruga Field oil sales during 2019. During Q3 2018, Tartaruga Field production was shut in for the majority of the period.

Production expenses

			Nine	Nine
			Months	Months	Full Year
(TUSD, unless otherwise noted)	Q3 2019	Q3 2018	2019	2018	2018
Production costs	1,436	1,261	3,542	4,236	5,468
Transportation costs	485	183	1,152	639	942
Total Production expenses	1,921	1,444	4,694	4,875	6,410
Per unit (USD/BOE)	6.10	10.17	5.98	11.35	9.89

Production expenses increased by 33% for Q3 2019 and amounted to TUSD 1,921 as compared to TUSD 1,444 for Q3 2018 as a result of higher sales volumes of 122% over the same period. On a per BOE (or unit) basis, production expense decreased by 40% for Q3 2019 and was USD 6.10 per BOE as compared to USD 10.17 per BOE for Q3 2018. Excluding transportation, the majority of production costs are fixed explaining the lower production costs on a per BOE basis as production volumes increases.

For the nine months ended September 2019 production expense was slightly lower the comparative period despite significantly higher sales volumes by 83%, as a result of operating efficiencies following facilities upgrades. On a per BOE basis, costs were lower by 47%, as a result of higher sales volumes for the nine months of 2019 as compared to nine months of 2018.

Operating netback

			Nine	Nine
			Months	Months	Full Year
(TUSD, unless otherwise noted)	Q3 2019	Q3 2018	2019	2018	2018
Operating Netback	12,017	6,553	31,714	17,481	26,917
Netback (USD/BOE)	38.22	46.17	40.38	40.70	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 peers. Operating netback on a dollar basis for Q3 2019 and the nine months of 2019 was 83% and 81% 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 17% versus comparable quarter but remained practically even for the 9 month period, reflecting improving per unit costs.

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")

			Nine	Nine
			Months	Months	Full Year
(TUSD, unless otherwise noted)	Q3 2019	Q3 2018	2019	2018	2018
G&A	1,268	1,108	4,052	3,323	4,222
G&A (USD/BOE)	4.03	7.80	5.16	7.74	6.52

G&A expenses amounted to TUSD 1,268 for Q3 2019 which is 14% higher than the comparative period due to severance costs of a former member of management and additional fees incurred during the quarter for the corporate reorganization of entities within the Maha group. On a per BOE basis, G&A expenses decreased by 48% due to higher sales volumes in the current quarter as compared to Q3 2018.

G&A expense amount to TUSD 4,052 for the nine months 2019 and is higher by 22% as compared to the same period in 2018. Higher year‐to‐date G&A expenses other than for the above‐mentioned, relate to a one‐time bonus payment to staff during the second quarter. On a per BOE basis, G&A expenses are lower by 33% than the comparative period. 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")

		Nine		Nine
			Months	Months	Full Year
(TUSD, unless otherwise noted)	Q3 2019	Q3 2018	2019	2018	2018
DD&A	1,534	743	4,289	2,331	3,762
DD&A (USD/boe)	4.88	5.23	5.46	5.43	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.

The higher depletion expense for the current quarter is consistent with the higher sales volumes. On a per BOE basis, depletion per boe has decreased as compared to the comparative period due to the added reserves in the Tie Field during the Q3 2019. For the nine months of 2019 depletion expense on a per BOE basis is consistent with the comparative 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 the DD&A expense and therefore the comparative periods have not been restated to include the impact of the implementation of IFRS 16.

Foreign currency exchange gain or loss

The net foreign currency exchange gain for the current quarter amounted to TUSD 176 (Q3 2018: TUSD 79 loss) and for the nine months of 2019 amounted to gain of TUSD 82 (2019: TUSD 18 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 1,264 (Q3 2018: TUSD 1,079) and for the nine months of 2019 amounted to TUSD 3,380 (2019: TUSD 3,536) and are detailed in Note 5. The implementation of IFRS 16 did not have a material impact on the net finance costs.

Income Taxes

Current tax expense in the quarter was TUSD 850 as compared to TUSD 278 in the comparative period due to the increased taxable income for the current quarter. Current tax expense for the nine months of 2019 was TUSD 1,766 as compared to TUSD 691 for the same period last year.

Deferred tax expense in the quarter was TUSD 334 as compared to nil in the comparative period and for the nine months of 2019 was TUSD 899 as compared to nil for the same period prior year. 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.

Liquidity and capital resources

As at 30 September 2019, the Company had current assets of \$30.6 million comprised primarily of cash and cash equivalents, restricted cash, accounts receivable and prepaid expenses and inventory. The Company had current liabilities of \$12.5 million resulting in net working capital of \$18.1 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 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 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 Q3 2019 amounted to TSEK ‐3,658 (Q3 2018: TSEK ‐13,316). The result includes general and administrative expenses of TSEK 1,319 (Q3 2018: TSEK 866) and net finance costs of TSEK 5,866 (Q3 2018: TSEK 11,313). Net finance cost decreased in the current quarter as compared to the comparative period due to net impact of interest income on an intercompany loan by the Parent Company to its subsidiary.

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 Third quarter ended 30 September 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

				Nine Months	Nine Months
(TUSD)	Note	Q3 2019	Q3 2018	2019	2018
Revenue
Oil and gas sales	3,4	16,068	9,049	41,917	25,537
Royalties		(2,130)	(1,052)	(5,509)	(3,181)
		13,938	7,997	36,408	22,356
Expenses
Production and transportation		(1,921)	(1,444)	(4,694)	(4,875)
General and administration		(1,268)	(1,108)	(4,052)	(3,323)
Depletion, depreciation and amortization	6	(1,534)	(743)	(4,289)	(2,331)
Stock‐based compensation	10	(86)	(53)	(148)	(166)
Financial derivative instruments	11	‐	‐	‐	(74)
Foreign currency exchange gain (loss)		176	(79)	82	18
		(4,633)	(3,427)	(13,101)	(10,751)
Operating result		9,305	4,570	23,307	11,605
Net finance costs	5	(1,264)	(1,079)	(3,380)	(3,536)
Other Loss	12	(287)	‐	(287)	‐
Result before tax		7,754	3,491	19,640	8,069
Income tax – current		(850)	(278)	(1,766)	(691)
Income tax – deferred		(334)	‐	(899)	‐
Net result for the period		6,570	3,213	16,975	7,378
Earnings per share basic – USD		0.07	0.03	0.17	0.08
Earnings per share fully diluted – USD		0.06	0.03	0.16	0.07
Weighted average number of shares:
Before dilution		99,429,829	97,998,835	99,006,993	97,452,903
After dilution		109,173,814	105,012,944	108,061,849	100,912,059

Condensed Consolidated Statement of Comprehensive Earnings

				Nine Months	Nine Months
(TUSD)	Note	Q3 2019	Q3 2018	2019	2018
Net Result for the period		6,570	3,213	16,975	7,378
Items that may be reclassified to profit or loss:
Exchange differences on translation of
foreign operations		(5,715)	(3,117)	(4,626)	(9,011)
Comprehensive result for the period		855	96	12,349	(1,633)
Attributable to: Shareholders of the Parent Company		855	96	12,349	(1,633)

Condensed Consolidated Statement of Financial Position

(TUSD)	Note	September 30, 2019	December 31, 2018
ASSETS
Non‐current assets
Property, plant and equipment	6	72,427	58,834
Exploration and evaluation assets	7	21,445	20,685
Deferred tax assets		9,524	11,259
Performance bonds and others		178	177
Total non‐current assets		103,574	90,955
Current assets
Crude oil inventory		392	57
Prepaid expenses and deposits		958	686
Accounts receivable	12	6,093	4,368
Restricted cash	16	2,709	2,804
Cash and cash equivalents		20,421	20,255
Total current assets		30,573	28,170
TOTAL ASSETS		134,147	119,125
EQUITY AND LIABILITIES Equity Shareholder's equity	10	82,993	69,274
Liabilities
Non‐current liabilities
Bonds payable	8	28,855	31,180
Decommissioning provision	9	1,910	1,720
Lease liabilities		414	‐
Other long‐term liabilities and provisions		7,478	8,093
Total non‐current liabilities		38,657	40,993
Current liabilities
Accounts payable		7,786	4,029
Accrued liabilities and other		4,473	4,829
Current portion of lease liabilities		238	‐
Total current liabilities		12,497	8,858
TOTAL LIABILITIES		51,154	49,851
TOTAL EQUITY AND LIABILITIES		134,147	119,125

Condensed Consolidated Statement of Cash Flows

				Nine Months	Nine Months
(TUSD)	Note	Q3 2019	Q3 2018	2019	2018
Operating Activities
Net result		6,570	3,213	16,975	7,378
Depletion, depreciation and amortization	6	1,534	743	4,289	2,331
Stock based compensation	10	86	53	148	166
Accretion of decommissioning provision	9	29	26	85	77
Accretion of bond payable	8	248	255	752	796
Interest expense		940	1,001	2,877	3,146
Income tax expense		850		1,766
Deferred tax expense		334	‐	899	‐
Financial derivative instruments	11	‐	2	‐	139
Unrealized foreign exchange amounts		30	(1,118)	(592)	474
Interest received		‐	237	162	567
Interest paid		‐	‐	(1,892)	(2,057)
Tax paid		(423)	(278)	(1,385)	(691)
Changes in working capital	14	(230)	2,538	(533)	869
Cash from operating activities		9,968	6,672	23,551	13,195
Investing activities Capital expenditures ‐ property, plant and equipment Capital expenditures ‐ exploration and	6	(8,988)	(4,359)	(21,877)	(7,393)
evaluation assets	7	(113)	(740)	(760)	(748)
Restricted cash		(24)	‐	(108)	‐
Cash used in investment activities		(9,125)	(5,099)	(22,745)	(8,141)
Financing activities
Lease payments		4	‐	(92)	‐
Issue of shares, net of share issue costs		‐	(29)	‐	1,496
Exercise of stock options and warrants	10	426	150	1,223	252
Cash from financing activities		430	121	1,131	1,748
Change in cash and cash equivalents Cash and cash equivalents at the		1,273	(1,378)	1,937	3,563
beginning of the period		20,504	20,914	20,255	18,729
Currency exchange differences in cash
and cash equivalents		(1,356)	(316)	(1,771)	(3,239)
Cash and cash equivalents at the end of
the period		20,421	22,292	20,421	22,292

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
Result for the period	‐	‐	‐	7,378	7,378
Currency translation difference	‐	‐	(9,011)	‐	(9,011)
Total comprehensive result	‐	‐	(9,011)	7,378	(1,633)
Transactions with owners
Share issue cost	‐	(61)	‐	‐	(61)
Stock based compensation	‐	166	‐	‐	166
Exercise of warrants and options	3	1,807	‐	‐	1,810
Total transactions with owners	3	1,912	‐	‐	1,915
Balance at 30 September 2018	120	62,985	(10,370)	(4,252)	48,483
Comprehensive result
Result for the period	‐	‐	‐	18,267	18,267
Currency translation difference	‐	‐	2,500	‐	2,500
Total comprehensive result	‐	‐	2,500	18,267	20,767
Transactions with owners
Stock based compensation	‐	51	‐	‐	51
Exercise of warrants and options (net of
costs)	‐	(27)	‐	‐	(27)
Total transactions with owners	‐	24	‐	‐	24
Balance at 31 December 2018	120	63,009	(7,870)	14,015	69,274
Comprehensive result
Result for the period	‐	‐	‐	16,975	16,975
Currency translation difference	‐	‐	(4,628)	‐	(4,628)
Total comprehensive result	‐	‐	(4,628)	16,975	12,347
Transactions with owners
Stock based compensation	‐	148	‐	‐	148
Exercise of warrants and options (net of
costs)	2	1,222	‐	‐	1,224
Total transactions with owners	2	1,370	‐	‐	1,372
Balance at 30 September 2019	122	64,379	(12,498)	30,990	82,993

Parent Company Statement of Operations

				Nine months	Nine Months
(Expressed in thousands of Swedish Krona)	Note	Q3 2019	Q3 2018	2019	2018
Revenue		‐	‐	‐	‐
Expenses
General and administrative		(1,319)	(866)	(4,526)	(2,653)
Stock‐based compensation	10	(814)	(477)	(1,390)	(1,421)
Foreign currency exchange gain(loss)		4,341	(660)	5,124	4,785
Operating result		2,208	2,003	(792)	711
Net finance costs		(5,866)	(11,313)	(15,463)	(33,940)
Financial instruments	11	‐	‐	‐	(618)
Result before tax		(3,658)	(13,316)	(16,255)	(33,847)
Income tax		‐	‐	‐	‐
Net Result for the period		(3,658)	(13,316)	(16,255)	(33,847)

Parent Company Balance Sheet

(Expressed in thousands of Swedish Krona)	Note	30 September 2019	31 December 2018
Assets
Non‐current assets
Investment in subsidiaries		184,219	184,219
Loans to subsidiaries		388,019	410,764
		572,238	594,983
Current assets
Accounts receivable and other		838	170
Restricted cash		50	50
Cash and cash equivalents		173,771	138,598
		174,659	138,818
Total Assets		746,897	733,801
Equity and Liabilities
Restricted equity Share capital		1,107	1,091
Unrestricted equity
Contributed surplus		500,249	487,374
Retained earnings		(51,394)	(35,139)
Total unrestricted equity		448,855	452,235
Total equity		449,962	453,326
Non‐current liabilities
Bonds Payable	8	283,641	276,573
Current liabilities
Accounts payable and accrued liabilities		13,294	3,902
Total liabilities		296,935	280,475
Total Equity and Liabilities		746,897	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	‐	(541)	‐	(541)
Stock based compensation	‐	1,421	‐	1421
Exercise of warrants and stock options	23	15,511	‐	15,534
Result for the period	‐	‐	(33,847)	(33,847)
30 September 2018	1,091	486,937	(58,898)	429,129
1 January 2019	1,091	487,374	(35,139)	453,326
Stock based compensation	‐	1,390	‐	1,390
Exercise of warrants and stock options
(net of issuance costs)	16	11,485	‐	11,485
Result for the period	‐	‐	(16,255)	(16,255)
30 September 2019	1,107	500,249	(51,394)	449,962

Notes to the 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 interim 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 interim consolidated financial statements are stated in thousands of US dollars (USD), 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 interim 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 Consolidated Statement of Financial position, Consolidated Statements of Operations and Statement of Comprehensive Earnings and Consolidated Statements of Cash flows have not been restated. No other standards, amendments or interpretations that have come into force in 2019 are expected to have any material impact on the Company.

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.

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 twelve months 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 nine months ended 30
September 2019
Revenue	‐	‐	41,917	‐	‐	41,917
Royalties	‐	‐	(5,509)	‐	‐	(5,509)
Production and operating	‐	‐	(4,694)	‐	‐	(4,694)
General and administration	(2,179)	(178)	(1,160)	(491)	(44)	(4,052)
Stock‐based compensation	‐	‐	‐	(148)	‐	(148)
Depletion, depreciation and
amortization	(10)	(66)	(4,213)	‐	‐	(4,289)
Foreign currency exchange
gain (loss)	682	‐	7	13	(620)	82
Operating results	(1,507)	(244)	26,348	(626)	(664)	23,307
Net finance costs	‐	(12)	263	(1,645)	(1,986)	(3,380)
Other loss	(287)	‐	‐	‐	‐	(287)
Current income tax	‐	‐	(1,766)	‐	‐	(1,766)
Deferred income tax	‐	‐	(899)	‐	‐	(899)
Net results	(1,794)	(256)	23,946	(2,271)	(2,650)	16,975
(TUSD)	Canada	US	Brazil	Sweden	Other6	Total
For nine months ended 30
September 2018
Revenue	‐	‐	25,537	‐		25,537
Royalties	‐	‐	(3,181)	‐		(3,181)
Production and operating	‐	‐	(4,875)	‐		(4,875)
General and administration	(1,902)	(116)	(904)	(310)	(91)	(3,323)
Stock‐based compensation	‐	‐	‐	(166)	‐	(166)
Depletion, depreciation and
amortization	(8)	(34)	(2,289)	‐	‐	(2,331)
Financial derivative
instruments	‐	‐	‐	(74)	‐	(74)
Foreign currency exchange
gain (loss)	(35)	‐	29	14	10	18
Operating results	(1,945)	(150)	14,317	(536)	(81)	11,605
Net finance costs	30	(10)	467	(3,955)	(68)	(3,536)
Current income tax	‐	‐	(691)	‐	‐	(691)
Net results	(1,915)	(160)	14,093	(4,491)	(149)	7,378

⁶ Other represents Luxembourg subsidiary and 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 Q3 2019 (Q3 2018: two) that individually accounted for more than 10 percent of the Company's consolidated gross sales. Total sales to these customers for the nine months of 2019 were approximately USD \$41.2 million (Nine months 2018: \$14.7 million), which are included in the Company's Brazil operating segment. Approximately, 61 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 Q3 2019, 100% (Q3 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:

			Nine months	Nine months
TUSD	Q3 2019	Q3 2018	2019	2018
Crude oil	15,849	9,002	41,440	25,321
Natural gas	177	47	435	216
Other	42	‐	42	‐
Total revenue from contracts with
customers	16,068	9,049	41,917	25,537

The Company had no contract asset or liability balances during the period presented. As at 30 September 2019, accounts receivable included \$3.9 million of accrued sales revenue which related to September 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

			Nine months	Nine months
TUSD	Q3 2019	Q3 2018	2019	2018
Interest on bond payable	938	1,001	2,872	3,146
Accretion of bond payable (note 11)	248	256	752	796
Accretion of decommissioning provision	29	26	85	77
Risk management contracts	‐	2	‐	66
Interest income and other	49	(206)	(329)	(549)
	1,264	1,079	3,380	3,536

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	21,812	45	413	22,270
Currency translation adjustment	(5,440)	(33)	(54)	(5,527)
30 September 2019	78,497	2,073	786	81,356
Accumulated depletion, depreciation and amortization (DD&A)
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	(3,920)	(132)	(152)	(4,204)
Currency translation adjustment	605	14	8	627
30 September 2019	(8,234)	(551)	(144)	(8,929)
Carrying amount
31 December 2018 (Note 2)	57,206	1,628	427	59,261
30 September 2019	70,263	1,522	642	72,427
7. Exploration and Evaluation Assets (E&E)

TUSD
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	990
Incidental result from sale of crude oil	(230)
30 September 2019	21,445

As at 30 September 2019, 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	752	7,068
Effect of currency translation	(3,077)	‐
30 September 2019	28,855	283,641

For the Q3 2019 Maha recognized TUSD 938 of interest and TUSD 248 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 as at 30 September 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 June 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	85
Additions	338
Foreign exchange movement	(233)
30 September 2019	1,910

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	1,474,836	‐	‐	1,474,836
Conversion of convertible B shares	149,564	(149,564)	‐	‐
Exercise of Maha (Canada) options	50,000		(50,000)	‐
30 September 2019	91,933,568	7,960,318	‐	99,893,886

Total outstanding warrants as at 30 September 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	(1,474,836)	7.45	0.79
30 September 2019	11,875,164	7.45	0.76

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 the first nine months of 2019.

Warrants			Number of warrants
incentive	Exercise	Exercise		Issued	Expired	Exercised	Cancelled
programme	period	price, SEK	1 Jan 2019	2019	2019	2019	2019	30 Sep 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 109,173,814 for the third quarter.

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 30 September 2019, the carrying value of the Bonds was TUSD 28,855 and the fair value was TUSD 32,915 (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	30 September 2019	31 December 2018
Oil and gas sales (Brazil)	3,786	3,127
Sale of Canadian assets	‐	280
Tax credits and other receivables	2,307	961
	6,093	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 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 30 September 2019, the Company's net working capital surplus was USD \$18.0 million (31 December 2018: USD \$19.3 million), which includes USD \$20.4 million (31 December 2018: USD \$20.2 million) of cash and USD \$2.7 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 \$83.0 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. 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)	30 September 2019	30 September 2018
Change in:
Accounts receivable	(1,887)	(205)
Inventory	(240)	146
Prepaid expenses and deposits	(272)	(225)
Accounts payable and accrued liabilities	1,866	1,153
Total	(533)	869

15. Pledged Assets

As at 30 September 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 30 September 2019 amounted to SEK 184.2 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 94.2 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

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 work commitments have been recorded as long‐term provisions and are guaranteed with certain credit instruments in place of approximately \$4.9 million. In addition, the Company has a \$2.7 million term deposit to guarantee certain work commitments of \$3.7 million. This term deposit has been presented as restricted cash on the Statement of Financial Position.

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			Nine months	Nine months
	Q3 2019	Q3 2018	2019	2018
Revenue	16,068	9,049	41,917	25,537
Operating netback	12,017	6,553	31,714	17,481
EBITDA6	10,663	5,392	27,514	13,918
Net result	6,570	3,213	16,975	7,378
Cash Flow from operations	9,968	6,672	23,551	13,195

Capital structure

			Nine months	Nine months
	Q3 2019	Q3 2018	2019	2018
Return on equity (%)	8	7	20	15
Equity ratio (%)	62	49	62	49

Other

			Nine months	Nine months
	Q3 2019	Q3 2018	2019	2018
Weighted number of shares
(before dilution)	99,429,829	97,998,835	99,006,993	97,452,903
Weighted number of shares
(after dilution)	109,173,814	105,012,944	108,061,849	100,912,059
Earnings per share before
dilution, USD	0.07	0.03	0.17	0.08
Earnings per share after
dilution, USD	0.06	0.03	0.16	0.07
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.

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:

			Nine Months	Nine Months
(TUSD)	Q3 2019	Q3 2018	2019	2018
Revenue	16,068	9,049	41,917	25,537
Royalties	(2,130)	(1,052)	(5,509)	(3,181)
Operating Expenses	(1,436)	(1,261)	(3,542)	(4,236)
Transportation costs	(485)	(183)	(1,152)	(639)
Operating netback	12,017	6,553	31,714	17,481

EBITDA7

Earnings before interest, taxes, depreciation and amortization and non‐recurring items (such as gain on contractual liability) is used as a measure of the financial performance of the Company and is calculated as shown below:

			Nine Months	Nine Months
(TUSD)	Q3 2019	Q3 2018	2019	2018
Operating results	9,305	4,570	23,307	11,605
Depletion, depreciation and amortization	1,534	743	4,289	2,331
Foreign currency exchange loss / (gain)	(176)	79	(82)	(18)
EBITDA	10,663	5,392	27,514	13,918

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 Fourth Quarter Report: 28 February 2020 2019 Annual Report: 30 April 2020 2020 First Quarter: 26 May 2020

Contact information

For further information please contact:

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

Ron Panchuk (CCO)

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

Andres Modarelli (CFO)

Tel: +1 403 454 7560 Email: andres@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

Suite 1140, 10201 Southport Road SW Calgary, Alberta T2W 4X9 403‐454‐7560