Maha Energy

Earnings Release • Aug 26, 2019

Report for the SIX MONTHS ENDED 30 JUNE 2019 (org number: 559018-9543)

Highlights

(all amounts are in US dollars unless otherwise noted)

Second Quarter 2019

• Daily oil & gas production for Q2 2019 averaged 2,739 BOEPD (Q2 2018: 1,429 BOEPD).
• Revenue of USD 14.1 million (Q2 2018: USD 7.9 million)
• Operating netback of USD 10.7 million or USD 43.30 per BOE (Q2 2018: USD 5.1 million or USD 39.22 per BOE)
• EBITDA of USD 9.2 million (Q2 2018: USD 4.0 million)
• Net result of USD 6.2 million (Q2 2018: USD 1.9 million)
• Basic and diluted Earnings per share of USD 0.06 (Q2 2018: USD 0.02)

Six Months Ended 30 June 2019

• Daily oil & gas production for H1 2019 2,704 BOEPD (H1 2018: 1,595 BOEPD).
• Revenue of USD 25.8 million (H1 2018: USD 16.5 million)
• Operating netback of USD 19.7 million or USD 41.83 per BOE (H1 2018: 10.9 USD million or 38.01 USD per BOE)
• EBITDA of USD 16.9 million (H1 2018: USD 8.5 million)
• Net result for the period of USD 10.4 million (H1 2018: USD 4.2 million)
• Basic Earnings per share of USD 0.11 (H1 2018: USD 0.04)
• Diluted Earnings per share of USD 0.10 (H1 2018: USD 0.04)
• Cash and cash equivalents balance of USD 20.5 million.

(TUSD, unless otherwise noted)	Q2 2019	Q1 2019	Q4 2018	Q3 2018	Q2 2018	H1 2019	H1 2018	FY 2018
Net Daily Production (BOEPD)	2,739	2,669	2,454	1,565	1,429	2,704	1,595	1,804
Revenue	14,098	11,751	12,595	9,049	7,859	25,849	16,488	38,132
Operating netback	10,668	9,029	9,436	6,553	5,071	19,697	10,928	26,917
EBITDA	9,188	7,663	8,486	5,392	3,960	16,851	8,526	22,404
Net result for the period	6,157	4,248	18,2671	3,213	1,859	10,405	4,165	25,645
Earnings per share – Basic (USD)	0.06	0.04	0.19	0.03	0.02	0.11	0.04	0.26
Earnings per share - Diluted (USD)	0.06	0.04	0.17	0.03	0.02	0.10	0.04	0.25
Cash and cash equivalents	20,504	19,768	20,255	22,292	20,914	20,504	20,914	20,255

Financial Summary

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

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
TUSD	Thousand USD	Mboe	Thousand barrels of oil equivalents
MSEK	Million SEK	Mboepd	Thousand barrels of oil equivalents per day
MUSD	Million USD	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,

As usual the summer passed too quickly! Here at Maha we spent the summer months ramping up production and working toward achieving our 4,850 BOPD production goal at the Tie field. In order to reach that goal, three components must converge at the same time: (1) the combined well production capability on the field must exceed 4,850 BOPD, (2) the Tie Production Facility must be able to safely handle and separate the incoming oil, water and associated gas from the wells, and, (3) there need to be somewhere to take (sell) the finished product. To complicate matters, the Tie field is not connected to a pipeline system, the sales agreements need to cater for both oil and gas production. And since both products are co-dependent (oil and gas volumes are proportionally linked) it makes for many moving pieces that must come together, as is detailed below.

Well Productivity (Tie Field) - now at over 6,000 BOPD

During this reporting period, the Attic Well (7-Tie-1D-BA) was completed and brought on production. Both the Agua Grande and Sergi zones were completed individually allowing for independent production of each zone. The GTE-3 well was also recompleted from a co-mingled producer to a dual producer, also providing for individual zonal production. This completes the 2018/19 work program for well deliverability on the Tie field. The total combined production from the wells in the Field currently exceeds 6,000 BOPD and the field can be optimized to selectively produce the optimum mix of oil and gas.

Facility Handling Capacity (Tie Field) – now at 5,000 BOPD

By the end of 2018, temporary modifications to the Processing Facility at the Tie field were completed to allow for handling up to 5,000 BOPD of oil and associated gas. During the first half of 2019 the temporary modifications were permanently installed and commissioned. As of today, with only minor commissioning and testing items remaining, the Tie Processing Facility is capable of consistently gathering, separating, treating and storing up to 5,000 BOPD. The associated gas is separated and sent for sales.

Offtake Agreements (Tie Field) – now at 4,850 BOPD and 80,000 m3 /day of gas

Gas

When the Tie Field was purchased in July of 2017 it was producing about 1,300 BOPD from a single well. The oil rate was limited by how much gas could be sold. At that time, if more gas could have been sold then more oil could have been produced. Through a series of negotiations with two primary gas customers, Maha was quickly able to increase the gas offtake volumes. As of today, the Company has secured approximately 80,000 m3 /day of gas sales to a Compressed Natural Gas (CNG) customer and a Gas to Wire (GTW) customer. Additionally, +/- 6,000 m3 /d is consumed internally by generators at the Processing Facility to provide electric power to the Tie Field operations. The target production of 4,850 BOPD currently generates production of approximately 86,000 m3 of gas per day – so with respect to gas, there are now sufficient arrangements in place to handle the target production rate.

Oil

With respect to oil, Maha has managed a very complicated picture. Tie oil will be trucked to two customers at three different terminals. The largest customer is a private refinery located very close to the Tie field. This refinery has progressively increased their demand for Tie oil; starting in late 2017 at 900 BOPD and now up to 2,200 BOPD. At the end of 2018, and in conjunction with refinery's decision to double its' processing capacity, Maha agreed with the refinery to increase deliveries to 3,000 BOPD by the middle of 2019. The refinery undertook a series of upgrades during the first half of 2019, with the last upgrade being completed in July 2019. The refinery is now awaiting final regulatory approvals to commence processing the expansion volumes which are expected by mid-September. Thereafter, Maha should be able to consistently deliver 3,000 BOPD to the refinery.

Petrobras, the State Oil Company of Brazil, which owns most of the oil and gas infrastructure in Bahia is the Company's second customer. From first production of Tie field, Petrobras has been receiving 500 - 1,100 BOPD at a nearby pipeline pumping terminal and since 2017, Maha has been in discussions with Petrobras about increasing the deliveries into the regional pipeline system. In early 2019, and as a result of these discussions, Petrobras proposed an alternative plan to accept an additional 750 BOPD through a second pumping terminal it would upgrade. There is a new agreement in place with Petrobras for that volume. In June, a test delivery of Tie crude oil to the new Pumping terminal was undertaken with no issues. Petrobras now awaits regulatory approval to commence receiving oil from Maha there.

So long as the planned gas customer facilities are commissioned on time, the Company should regularly be able to deliver 3,300 BOPD from the Tie field from now on. Once the refinery and Petrobras receive final regulatory approvals, the Company will commence trucking the additional 1,550 BOPD (800 + 750). It is estimated that by the end of September, the Company should regularly deliver 4,850 BOPD of Tie crude oil for sale.

Tartaruga

The Tartaruga field, is producing at the current maximum plant capacity of about 500 - 800 BOPD (gross). The 7- TTG-3D-SES well was spudded on 12 July, 2019. As at 1 August, the 13-3/8" casing had been set and cemented at 886 m. The objective of this well is to delineate and test certain untested intervals of the Penedo sand reservoir. Upon completion of the 7-TTG-3D-SES well, the 107D well will be re-entered, recompleted, cleaned out and brought on production. Whilst currently the Tartaruga facility is operating at capacity handling production from the 7TTG well, when certain facility upgrades are completed it is expected that the 107D well will immediately increase production at Tartaruga; following which the 7-TTG-3D-SES well will be tied in and the permanent upgrade of the processing facility completed.

Production and Current Production Guidance

In our August 23rd 2019 Press Release I expressed my frustration that delays in normal course regulatory approvals/commissioning at our customers facilities caused the Company to revise downward its annual average production forecast. The frustration is that in all other respects we have made remarkable progress; we can produce more oil than we can sell, and as outlined above all the physical construction and upgrades are completed at the various required facilities. Our current production capacity in Brazil exceeds 6,500 BOPD while our current sales capabilities limits us to 3,900 BOPD of daily sales and production. Upon the above final approvals/commissioning the Company will be in a position to produce, deliver and sell 5,400 BOPD almost immediately. This is an outstanding accomplishment that the revised forecast should not detract from.

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 Second Quarter ended June 30, 2019

OPERATIONAL AND FINANCIAL REVIEW

Maha Energy AB (org number: 559018-9543) ("Maha" or the "Company") is an independent, Swedish-based, international oil and gas exploration and enhanced oil recovery production company with operations focused on Brazil and USA.

The head office is located at Strandvägen 5A, SE-114 51 Stockholm, Sweden. The Company maintains a technical support office at Suite 1140, 10201 Southport Road SW, Calgary, Alberta, Canada, has an office in Rio de Janeiro, Brazil and in Newcastle, Wyoming, USA.

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	24	SEC (1%)
Brazil	Tartaruga	75%	Producing	13,201	83	Petrobras (25%)
Brazil	Tie (REC-T 155)	100%	Producing	1,511	2,632
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.

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-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. By recompleting both zones into individual strings, further production capacity is now available from GTE-3.

GTE-4 (oil producer)

GTE-4 continues to free flow and is enjoying the effects of water injection. A jet pump has been installed and tested at the GTE-4 site. The pump will be hooked up and commissioned to increase flow once one of the two zones stop free-flowing.

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.

Production Facilities

During 2018, the production facilities at the Tie Field were upgraded from its original 2,000 BOPD handling capacity to 5,000 BOPD. A new heater treater, a new group separator and a test separator along with additional tankage and loading bays were installed and commissioned during the year. Minor work is still ongoing to complete the permanent upgrade along with minor commissioning and documentation work still outstanding. As the Tie Field is not connected to a pipeline system, all oil is exported by oil trucks. The associated gas is separated and sold locally.

Average production from the Tie Field during the current quarter was 2,632 BOEPD (2,447 BOPD and 1,111 MSCFPD of gas).

Tartaruga Field

Maha has a 75% working interest in the Tartaruga development block, located in the Sergipe Alagoas Basin onshore Brazil. The Tartaruga oil field is located in the northern half of the 13,201 acre (53.4 km2 ) Tartaruga Block and produces light (41° API) oil from two deviated wells drilled into s Penedo sandstone reservoir.

During 2018 & 2019, the Company commenced a significant work program which included the re-entry, new perforating, 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 likely 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 very productive Penedo 1 sandstone layer was targeted. In the 7TTG well, the Penedo 1 sandstone had never been produced and was considered 'pay-behind-pipe'.

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. Finalization of cleaning out and restoring 107D to production is planned for the end of 2019 when the drilling and testing of 7-TTG-3D-SES is completed.

7TTG Workover

The workover to recomplete the 7TTG well with larger tubing and a dedicated jet pump was originally planned for mid-2018, but a stuck 3-1/2" tubing prevented the work to be completed due to workover rig limitations. Following the completion of drilling operations at 107D the larger rig used on 107D was mobilized and the fishing of the stuck tubing was successfully completed. The 7TTG workover is now complete with the P1 and P4 zones perforated and 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.

7-TTG-3D-SES Delineation Well (New well)

On July 12, 2019 the Company spudded this well ("7-TTG-3D") and drilling operations are currently underway. The primary objective of the well is to further test the productivity of the multiple stacked sandstone zones in the Penedo reservoir. The secondary objective is to place the well on production upon completion of a comprehensive testing program.

The Tartaruga Facility will not be shut in during the drilling activities of the 7-TTG-3D well. The Company expects 7TTG to produce continuously through 2019 subject to facilities handling capacity and shutdowns required during the Facility expansion work, if any.

Production Facilities

Current handling facilities at Tartaruga field allow for approximately 500 – 700 BOPD of processing and handling with storage limited at 1,350 barrels of oil. Current oil production is limited by associated gas flare limitations. 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 7TTG Workover will dictate upgrade requirements for the production handling facilities at the Tartaruga field. It is anticipated that facilities will be initially upgraded during the second half of 2019 with a view 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. This facility work is expected to be completed during the second half of 2019. Further associated gas handling is currently being designed for implementation in 2020.

Average net production from the Tartaruga Field during the current quarter was 83 BOPD. The Tartaruga Field was shut in for a total of 22 days in April, 31 days in May and 18 days in June due to the perforation work on 107D as well as drilling rig up operations.

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 June 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.

During the second quarter of 2019, the Company generated incidental revenue from LAK Ranch of TUSD 100, on average sales volumes of 24 bopd.

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 November this year.

Production

					Full Year
	Q2 2019	Q2 2018	H1 2019	H1 2018	2018
Delivered Oil (Barrels)3	232,439	120,077	457,116	262,587	609,087
Delivered Gas (MSCF)	101,079	59,937	194,032	156,219	296,189
Delivered Oil & Gas (BOE)4	249,286	130,067	489,455	288,624	658,452
Daily Volume (BOEPD)	2,739	1,429	2,704	1,595	1,804

Production volumes shown are net working interest volumes before government, gross overriding and freehold royalties. Approximately 93% of Maha's oil equivalent production is crude oil.

Average daily production volumes increased by 92% and 70% for Q2 and H1 2019 respectively versus the comparative 2018 periods with Tartaruga production being partially shut-in during Q2 2019. 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. During Q2 2018, Tartaruga production was shut in for the majority of the period.

					Full Year
(TUSD, unless otherwise noted)	Q2 2019	Q2 2018	H1 2019	H1 2018	2018
Oil and Gas revenue	14,098	7,859	25,849	16,488	38,132
Sales volume (BOE)	246,393	129,308	470,821	287,538	647,607
Oil realized price (USD/bbl)	60.83	65.60	58.35	62.65	63.18
Gas realized price (USD/MSCF)	1.35	0.99	1.33	1.04	1.17
Equivalent oil realized price (USD/Boe)	57.22	60.78	54.90	57.34	58.88
Reference price – Brent (USD/bbl)	68.92	74.95	66.05	70.99	71.06

Revenue

Revenue is presented as net working interest oil and gas sales before government, gross overriding and freehold royalties, as detailed in Note 4. Revenue increased 79% in Q2 2019 versus the comparative period due to 90% higher sales volumes despite slightly lower total realized price by 6%. Revenue for the H1 2019 was 57% higher against the comparative period with 64% higher sales volumes while total realized price was slightly lower by 4%. LAK Ranch production volumes are excluded from sold volumes as this field is still in pre-production stage.

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

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

Petrobras 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.

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

					Full Year
(TUSD, unless otherwise noted)	Q2 2019	Q2 2018	H1 2019	H1 2018	2018
Royalties	1,869	939	3,379	2,129	4,805
Per unit (USD/BOE)	7.59	7.26	7.18	7.40	7.42
Royalties as a % of revenue	13.3%	11.9%	13.1%	12.9%	12.6%

Royalties are settled in cash and based on realized prices before discounts. Royalty expense increased 99% and 59% for Q2 and H2 2019 respectively, versus the comparative periods, which is consistent with the higher revenue during the current quarter and the H1 2019 period. Royalty expense as a percentage of revenues was slightly higher in Q2 2019 than the comparative period due to higher royalty-rate Tartaruga production. During Q2 2018, Tartaruga production was shut in for the majority of the period.

Production expenses

					Full Year
(TUSD, unless otherwise noted)	Q2 2019	Q2 2018	H1 2019	H1 2018	2018
Production costs	1,196	1,654	2,106	2,975	5,468
Transportation costs	365	195	667	456	942
Total Production expenses	1,561	1,849	2,773	3,431	6,410
Per unit (USD/BOE)	6.33	14.30	5.89	11.93	9.89

Production expenses for Q2 and H1 2019 were 16% and 19% lower respectively, versus the comparative periods despite significantly higher production volumes due to increased operating efficiencies following facilities upgrades. On a per BOE basis, costs were lower 56% and 51% respectively, as a result of higher sales volumes in the current quarter and the H1 2019. Excluding transportation, the majority of production costs are fixed resulting in lower production costs on a per BOE basis as production volumes increase.

Operating netback

(TUSD, unless otherwise noted)	Q2 2019	Q2 2018	H1 2019	H1 2018	Full Year 2018
Operating Netback	10,668	5,071	19,697	10,928	26,917
Netback (USD/BOE)	43.30	39.22	41.83	38.01	41.57

Operating netback is calculated as revenue less royalties and production expenses. Operating netbacks for Q2 and H1 2019 were 110% and 80% higher respectively against the comparative periods as a result of higher revenues and lower production expenses. Operating netback, on a per BOE basis, was also higher versus the comparative periods despite lower realized oil prices during the current quarter and the H1 2019.

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")

					Full Year
(TUSD, unless otherwise noted)	Q2 2019	Q2 2018	H1 2019	H1 2018	2018
G&A	1,460	1,017	2,784	2,215	4,222
G&A (USD/BOE)	5.93	7.87	5.91	7.70	6.52

G&A expenses were higher from the comparative periods as Q2 and H1 2019 amounts include the accrual of a onetime bonus payment to staff. On a per-boe basis, G&A expenses are lower by 25% and 23% respectively 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")

					Full Year
(TUSD, unless otherwise noted)	Q2 2019	Q2 2018	H1 2019	H1 2018	2018
DD&A	1,317	724	2,755	1,588	3,762
DD&A (USD/boe)	5.34	5.60	5.85	5.52	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 is consistent with the comparative periods. DD&A expense for the current quarter and H1 2019 includes depreciation expense relating to the 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 loss for the current quarter amounted to TUSD 99 (Q2 2018: TUSD 1 gain) and for the H1 2019 amounted to loss of TUSD 94 (H1 2019: TUSD 97 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 945 (Q2 2018: TUSD 1,158) and for the H1 2019 amounted to TUSD 1,158 (H1 2019: TUSD 2,457) 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 396 as compared to TUSD 220 in the comparative period due to the increased taxable income for the current quarter. Current tax expense for the H1 2019 was TUSD 916 as compared to TUSD 413 for the same period last year.

Deferred tax expense in the quarter was TUSD 274 as compared to nil in the comparative period and for the H1 2019 was TUSD 565 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.

Share data

	Number of Shares by Class
Shares outstanding	A	B	C2	Total
30 June 2019	91,412,784	7,960,318	50,000	99,423,102

Liquidity and capital resources

As at 30 June 2019, the Company had current assets of \$28.9 million comprised primarily of cash and cash equivalents, restricted cash, accounts receivable and prepaid expenses and deposits. The Company had current liabilities of \$9.7 million resulting in net working capital of \$19.1 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. Additional information on financial risks identified by the Company are presented in Note 13 to the Consolidated Financial Statements.

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.

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. The Parent Company has no employees. 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 the second quarter 2019 amounted to TSEK -6,968 (Q2 2018: TSEK - 18,038). The result includes general and administrative expenses of TSEK 1,809 (Q2 2018: TSEK 1,219) and net finance costs of TSEK 5,160 (Q2 2018: TSEK 20,232). Net finance cost decreased in the current quarter as compared to the comparative period due to interest income on an intercompany loan by the Parent Company.

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 second quarter ended 30 June 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

Consolidated Statement of Operations

(TUSD)	Note	Q2 2019	Q2 2018	H1 2019	H1 2018
Revenue
Oil and gas sales	3,4	14,098	7,859	25,849	16,488
Royalties		(1,869)	(939)	(3,379)	(2,129)
		12,229	6,920	22,470	14,359
Expenses
Production and transportation		(1,561)	(1,849)	(2,773)	(3,431)
General and administration		(1,460)	(1,017)	(2,784)	(2,215)
Depletion, depreciation and amortization	6	(1,317)	(724)	(2,755)	(1,588)
Stock-based compensation	11	(20)	(82)	(62)	(113)
Financial derivative instruments	12	-	(12)	-	(74)
Foreign currency exchange gain (loss)		(99)	1	(94)	97
		(4,457)	(3,683)	(8,468)	(7,324)
Operating result		7,772	3,237	14,002	7,035
Net finance costs	5	(945)	(1,158)	(2,116)	(2,457)
Result before tax		6,827	2,079	11,886	4,578
Income tax – current		(396)	(220)	(916)	(413)
Income tax – deferred		(274)	-	(565)	-
Net result for the period		6,157	1,859	10,405	4,165
Earnings per share basic – USD		0.06	0.02	0.11	0.04
Earnings per share fully diluted – USD		0.06	0.02	0.10	0.04
Weighted average number of shares:
Before dilution		99,208,126	97,650,057	98,792,071	97,175,412
After dilution		108,659,352	97,834,378	107,685,196	97,296,552

Consolidated Statement of Comprehensive Earnings

(TUSD)	Note	Q2 2019	Q2 2018	H1 2019	H1 2018
Net Result for the period		6,157	1,859	10,405	4,165
Items that may be reclassified to profit or loss:
Exchange differences on translation of
foreign operations	2	1,053	(7,094)	1,089	(5,894)
Comprehensive result for the period		7,210	(5,235)	11,494	(1,729)
Attributable to: Shareholders of the Parent Company		7,210	(5,235)	11,494	(1,729)

Consolidated Statement of Financial Position

(TUSD)	Note	June 30, 2019	December 31, 2018
ASSETS
Non-current assets
Property, plant and equipment	6	70,940	58,834
Exploration and evaluation assets	7	21,332	20,685
Deferred tax assets		10,829	11,259
Performance bonds and others		178	177
Total non-current assets		103,279	90,955
Current assets
Crude oil inventory		426	57
Prepaid expenses and deposits		748	686
Accounts receivable	13	4,270	4,368
Restricted cash	16	2,918	2,804
Cash and cash equivalents		20,504	20,255
Total current assets		28,866	28,170
TOTAL ASSETS		132,145	119,125
EQUITY AND LIABILITIES Equity
Shareholder's equity	11	81,628	69,274
Liabilities
Non-current liabilities
Bonds payable	8	30,286	31,180
Decommissioning provision	9	1,841	1,720
Other long-term liabilities and provisions		8,127	8,093
Lease liabilities	10	509	-
Total non-current liabilities		40,763	40,993
Current liabilities
Accounts payable		4,830	4,029
Accrued liabilities and other		4,671	4,829
Current portion of lease liabilities	10	253	-
Total current liabilities		9,754	8,858
TOTAL LIABILITIES		50,517	49,851
TOTAL EQUITY AND LIABILITIES		132,145	119,125

Consolidated Statement of Cash Flows

(TUSD)	Note	Q2 2019	Q2 2018	H1 2019	H1 2018
Operating Activities
Net result from continuing operations		6,157	1,859	10,405	4,165
Depletion, depreciation and amortization	6	1,317	724	2,755	1,588
Stock based compensation	11	20	82	62	113
Accretion of decommissioning provision	9	29	27	56	51
Accretion of bond payable	8	249	263	504	541
Interest expense		956		1,937
Income tax expense		396	1,036	916	2,145
Deferred tax expense		274	-	565	-
Financial derivative instruments	12	-	39	-	137
Unrealized foreign exchange amounts		(834)	776	(622)	1,592
Interest received		143	186	234	330
Interest paid		(1,892)	(2,057)	(1,892)	(2,057)
Tax paid		(430)	(220)	(962)	(413)
Changes in working capital	15	(279)	461	(375)	(1,669)
Cash from operating activities		6,106	3,176	13,583	6,523
Investing activities Capital expenditures - property, plant and equipment Capital expenditures - exploration and evaluation assets	6 7	(6,313) (205)	(2,516) 30	(12,889) (647)	(3,034) (8)
Restricted cash		(42)	-	(84)	-
Cash used in investment activities		(6,560)	(2,486)	(13,620)	(3,042)
Financing activities
Lease payments	10	(96)		(96)
Issue of shares, net of share issue costs		-	(71)	-	1,525
Exercise of stock options and warrants	11	798	102	797	102
Cash from financing activities		702	31	701	1,627
Foreign exchange on cash and cash equivalents		488	(2,586)	(415)	(2,923)
Change in cash and cash equivalents Cash and cash equivalents, beginning of		736	(1,865)	249	2,185
period		19,768	22,779	20,255	18,729
Cash and cash equivalents, end of period		20,504	20,914	20,504	20,914

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	-	-	-	4,165	4,165
Currency translation difference	-	-	(5,894)	-	(5,894)
Total comprehensive result	-	-	(5,894)	4,165	(1,729)
Transactions with owners
Share issue cost		(60)			(60)
Stock based compensation		113			113
Exercise of warrants and options	3	1,684			1,687
Total transactions with owners	3	1,737	(7,253)	(7,465)	1,740
Balance at 30 June 2018	120	62,810	(7,253)	(7,465)	48,212
Balance at 1 January 2019	120	63,009	(7,870)	14,015	69,274
Result for the period	-	-	-	10,405	10,405
Currency translation difference	-	-	1,089	-	1,089
Total comprehensive result	120	63,009	(6,781)	24,420	80,768
Transactions with owners
Stock based compensation	-	62	-	-	62
Exercise of warrants and options (net of
costs)	1	797	-	-	798
Total transactions with owners	1	859	-	-	860
Balance at 30 June 2019	121	63,868	(6,781)	24,420	81,628

Parent Company Statement of Operations

-
(1,787)
(944)
(618)
5,445
2,096
(22,627)
(20,531)
-
(20,531)

Parent Company Balance Sheet

(Expressed in thousands of Swedish Krona)	Note	30 June 2019	31 December 2018
Assets
Non-current assets
Investment in subsidiaries		184,219	184,219
Loans to subsidiaries		389,646	410,764
		573,865	594,983
Current assets
Accounts receivable and other		403	170
Restricted cash		50	50
Cash and cash equivalents		160,055	138,598
		160,508	138,818
Total Assets		734,373	733,801
Equity and Liabilities
Restricted equity
Share capital		1,102	1,091
Unrestricted equity
Contributed surplus		495,360	487,374
Retained earnings		(47,736)	(35,139)
Total unrestricted equity		447,624	452,235
Total equity		448,726	453,326
Non-current liabilities
Bonds Payable	8	281,265	276,573
Current liabilities
Accounts payable and accrued liabilities		4,382	3,902
Total liabilities		285,647	280,475
Total Equity and Liabilities		734,373	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	-	(504)	-	(504)
Stock based compensation	-	944	-	944
Exercise of warrants and stock
options	23	14,137	-	14,160
Result for the period	-	-	(20,531)	(20,531)
30 June 2018	1,091	485,122	(45,582)	440,631
1 January 2019	1,091	487,374	(35,139)	453,326
Stock based compensation	-	576	-	576
Exercise of warrants and stock
options (net of issuance costs)	11	7,410	-	7,421
Result for the period	-	-	(12,597)	(12,597)
30 June 2019	1,102	495,360	(47,736)	448,726

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.

Maha (Sweden) was incorporated on June 16, 2015 under the Swedish Companies Act and was registered by the Swedish Companies Registration Office on July 1, 2015. Maha Energy Inc. ("Maha (Canada)"), was incorporated on January 23, 2013 pursuant to the Alberta Business Corporations Act. Maha (Canada) began its operations on February 1, 2013.

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.

As Lessee - 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.

Presentation and Functional Currency

The consolidated financial statements are presented in USD which is the currency the Company has elected to use as the presentation currency.

The Company's subsidiaries and their functional currencies are as follows:

Subsidiary	Functional Currency
Maha Energy Inc.	USD
Maha Energy (USA) Inc.	USD
Maha Energy Services LLC	USD
Maha Energy 1 (Brazil) AB	SEK
Maha Energy 2 (Brazil) AB	SEK
Maha Energy Brasil Ltda	BRL
Maha Energy Finance (Luxembourg) S.A.R.L	BRL

In presenting operating results, transactions in currencies other than the entity's functional currencies are recorded at the rates of exchange prevailing at the date of the transactions. At the end of each reporting period, monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate in effect at the reporting period date. Non-monetary assets, liabilities, revenues and expenses are translated at transaction date exchange rates. Any exchange gains or losses from the above are included in the determination of net result as foreign exchange gains or losses. These are included in Net Result as part of the Company's Consolidated Statement of Operations.

Since the Company's presentation currency is USD, the assets and liabilities of all foreign operations with non-USD functional currencies are translated to USD at exchange rates at the reporting date. The income and expenses of foreign operations are translated to USD at the average exchange rate for the period. Resultant foreign currency exchange differences from the effect of the above are included separately in the Company's Consolidated Statement of Comprehensive Earnings and the cumulative result of the exchange differences is reflected in Shareholders' Equity.

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	Other5	Consolidated
30 June 2019
Revenue	-	-	25,849	-	-	25,849
Royalties	-	-	(3,379)	-	-	(3,379)
Production and operating	-	-	(2,773)	-	-	(2,773)
General and administration	(1,514)	(124)	(749)	(354)	(43)	(2,784)
Stock-based compensation	-	-	-	(62)	-	(62)
Depletion, depreciation and
amortization	(6)	(44)	(2,705)	-	-	(2,755)
Foreign currency exchange
gain (loss)	248	-	6	1	(349)	(94)
Operating results	(1,272)	(168)	16,249	(415)	(392)	14,002
Net finance costs	-	(8)	327	(1,031)	(1,404)	(2,116)
Current income tax	-	-	(916)	-	-	(916)
Deferred income tax	-	-	(565)	-	-	(565)
Net results	(1,272)	(176)	15,095	(1,446)	(1,796)	10,405
(TUSD)	Canada	US	Brazil	Sweden	Other5	Total
30 June 2018
Revenue	-	-	16,488	-		16,488
Royalties	-	-	(2,129)	-		(2,129)
Production and operating	-	-	(3,431)	-		(3,431)
General and administration	(1,172)	(84)	(716)	(213)	(30)	(2,215)
Stock-based compensation	-	-	-	(113)	-	(113)
Depletion, depreciation and
amortization	(5)	(22)	(1,561)	-	-	(1,588)
Financial derivative
instruments	-	-	-	(74)	-	(74)
Foreign currency exchange
gain (loss)	72	-	(2)	(2)	29	97
Operating results	(1,105)	(106)	8,649	(402)	(1)	7,035
Net finance costs	24	(7)	286	(2,696)	(64)	(2,457)
Current income tax	-	-	(413)	-	-	(413)
Net results	(1,081)	(113)	8,522	(3,098)	(65)	4,165

All oil and gas revenue, operating expenses and depletion are from the Brazilian operations. The Company had two large customers during Q2 2019 (Q2 2018: two) that individually accounted for more than 10 percent of the Company's consolidated gross sales. Total sales to these customers for the first half of 2019 were approximately USD \$25.4 million (H1 2018: \$14.7 million), which are included in the Company's Brazil operating segment. Approximately, 65 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.

⁵ Other represents Luxembourg subsidiary and intercompany eliminations and consolidation adjustments.

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 second quarter 2019, 100% (Q2 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	Q2 2019	Q2 2018	H1 2019	H1 2018
Crude oil	13,961	7,797	25,591	16,318
Natural gas	137	62	258	170
Total revenue from contracts with 14,098		7,859	25,849	16,488
customers

The Company had no contract asset or liability balances during the period presented. As at 30 June 2019, accounts receivable included \$2.2 million of accrued sales revenue which related to June 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.

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	Q2 2019	Q2 2018	H1 2019	H1 2018
Interest on bond payable	952	1,035	1,934	2,145
Accretion of bond payable (note 11)	249	263	504	541
Accretion of decommissioning provision	29	27	56	51
Foreign currency exchange losses	-	(1)		-
Risk management contracts	-	27		64
Interest income and other	(285)	(193)	(378)	(344)
	945	1,158	2,116	2,457

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	13,392	74	413	13,879
Currency translation adjustment	670	6	14	690
30 June 2019	76,187	2,141	854	79,182
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	(2,626)	(98)	(97)	(2,821)
Currency translation adjustment	(63)	(2)	(4)	(69)
30 June 2019	(7,608)	(533)	(101)	(8,242)
Carrying amount
31 December 2018 (Note 2)	57,206	1,628	427	59,261
30 June 2019	68,579	1,608	753	70,940

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	773
Incidental result from sale of crude oil	(126)
30 June 2019	21,332

As at 30 June 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	504	4,692
Effect of currency translation	(1,398)	-
30 June 2019	30,286	281,265

For the second quarter of 2019 Maha recognized TUSD 952 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 as at 30 June 2019. As at the last reference date of 31 March 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.

9. Decommissioning Provision

The decommissioning provision is estimated based on the net ownership interest of wells and facilities, management's estimate of costs to abandon and reclaim those wells and facilities, and the potential future timing of the costs to be incurred.

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	56
Additions	150
Foreign exchange movement	(85)
30 June 2019	1,841

10. Lease Liability

427
421
3
(96)
7
762
253
509

11. 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	1,004,052	-	-	1,004,052
Conversion of convertible B shares	149,564	(149,564)	-	-
30 June 2019	91,412,784	7,960,318	50,000	99,423,102

Maha AB share purchase warrants (Maha-A TO2) outstanding as at 30 June 2019:

	Number of Warrants	Exercise Price
	#	USD
1 January 2018	19,550,963	0.87
Exercised	2,074,717	0.72
Expired	(4,126,246)	0.72
31 December 2018	13,350,000	0.91
Exercised	(1,004,052)	0.80
30 June 2019	12,345,948	0.80

During the first half of 2019, a total of 1,004,052 of Maha-A TO2 warrants were exercised at the pre-determined strike price of SEK 7.45 per share. Accordingly, 1,004,052 A Warrants were cancelled and the same number of new shares of class A were issued.

Warrant Incentive Program

The Company has an incentive program as part of the remuneration package for management and employees. Warrants were issued in the second quarter of 2017 and 2018 respectively, following a decision and approval at the respective Annual General Meeting. During the current quarter, additional 500,000 warrants were issued following approval at the 2019 Annual General Meeting. No incentive warrants were expired or exercised during the first half of 2019.

		Number of warrants
Warrants
incentive	Exercise	Exercise		Issued	Expired	Exercised	Cancelled	30 June
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

Each warrant shall entitle the warrant holder to subscribe for one new Share in the Company at the subscription price per share.

Maha Energy Inc. stock options

Maha (Canada) has a stock option plan which allows for the grant of stock options, at exercise prices equal to or close to market price, in a total amount of up to 10% of the number of common shares issued.

The following stock options are outstanding at 30 June 2019:

	Number of		Exercise	Remaining
Expiration date	Options	Vested	Price	Life
			\$ USD	Years
December 31, 2020	50,000	50,000	1.25	1.50

Total share-based compensation expense for the second quarter was TUSD 20 (Q2 2018: TUSD 82).

12. Financial assets and liabilities

The accounting policies for financial instruments have been applied to the line items below:

30 June 2019		Financial assets at	Fair value recognized
(TUSD)	Total	amortized cost	in profit or loss
Performance Bonds	178	178	-
Accounts receivable	4,270	4,270	-
Restricted cash	2,918	2,918	-
Cash and cash equivalents	20,504	20,504	-
Financial assets	27,870	27,870	-
30 June 2019		Financial liabilities at	Fair value recognized
(TUSD)	Total	amortized cost	in profit or loss
Bonds payable	30,286	30,286	-
Other non-current liabilities	8,127	8,127	-
Accounts payable	4,830	4,830	-
Accrued liabilities	4,671	4,671	-

Lease liability	762	762	-
Financial liabilities	48,676	48,676	-

31 December 2018		Financial assets at	Fair value recognized
(TUSD)	Total	amortized cost	in profit or loss
Performance Bonds	177	177	-
Accounts receivable	4,368	4,368	-
Restricted cash	2,804	2,804	-
Cash and cash equivalents	20,255	20,255	-
Financial assets	27,604	27,604	-

31 December 2018		Financial liabilities at	Fair value recognized
(TUSD)	Total	amortized cost	in profit or loss
Bonds payable	31,180	31,180	-
Other non-current liabilities	8,093	8,093	-
Accounts payable	4,703	4,703	-
Accrued liabilities	4,829	4,829	-
Financial liabilities	48,805	48,805	-

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 bonds are carried at amortized cost. The estimated fair values of the bonds have been determined based on period-end trading prices of the bonds on the secondary market (Level 2). As at 30 June 2019, the carrying value of the Bonds was TUSD 30,286 and the fair value was TUSD 34,501 (31 December 2018: carrying value – TUSD 31,180; fair value – TUSD 35,850).

13. 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. The Board of Directors has overall responsibility for establishment and oversight of the Company's risk management.

The types of risk exposures and the objectives and policies for managing these risks exposures is described below:

a) Currency risk

Foreign currency risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate as a result of changes in foreign currency exchange rates. All of the Company's oil sales are denominated in Brazilian Reals (BRL) based on a USD oil price and all operational, administrative and capital activities related to the Brazil properties are transacted primarily in BRL. In Sweden the Company's expenditures and bond liability are in Swedish Krona (SEK). To minimize foreign currency risk, the Company's cash balances are held primarily in SEK within Sweden and USD within Canada. In Canada, USD funds are converted to CAD on an as-needed basis. Management funds Brazil projects with the cash generated in Brazil to minimize the foreign currency risk.

b) Credit risk

Credit risk is the risk of an unexpected loss if a customer or fourth party to a financial instrument fails to meet its contractual obligations. The Company's cash and cash equivalents are primarily held at large Canadian, Brazilian and Swedish financial institutions in non-interest-bearing accounts.

The Company's accounts receivable is composed of:

TUSD	30 June 2019	31 December 2018
Oil and gas sales (Brazil)	2,255	3,127
Sale of Canadian assets	195	280
Tax credits and other receivables	1,820	961
	4,270	4,368

The majority of the Company's oil and gas sales receivables are with the Brazilian national oil company and a 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. As at 30 June 2019, TUSD 932 from Dax were included in accounts receivables. The Company established an allowance that represents its estimate of impairment of receivable for the Sale of Canadian assets. The Company will continue to monitor the likelihood of collectability of this receivable.

c) Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. By operating in several countries, the Company is exposed to currency fluctuations. Income is and will also most likely be denominated in foreign currencies, BRL in particular. Furthermore, the Company has since inception been equity and debt financed through share and bond issues, and also financed by asset divestment. Additional capital could be needed to finance the Company's future operations and/or for acquisition of additional licenses and bond repayment. The main risk is that this need could occur during less favorable market conditions. The Company continuously ensures that sufficient cash balances are maintained in order to cover day to day operations. Management relies on cash forecasting to assess the Company's cash position based on expected future cash flows. Accounts payable relating to oil and gas interests, and current interest on the bonds are due within the current operating period. The Bonds have interest payable of SEK 18 million semi-annually on May 29 and November 29 until the maturity date of May 29, 2021. In addition, principal payment is also due on the maturity date of the Bonds. The Company may redeem all of the Bonds prior to maturity or repurchase any Bonds (see Note 8).

The Company has current assets of \$28.9 million as at 30 June 2019 which is considered sufficient to settle the current liabilities of \$9.7 million as at 30 June 2019.

d) Interest Rate Risk

Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market interest rates. The risk that the Company will realize a loss as a result of a decline in the fair value of the short-term investments included in cash and cash equivalents is minimal. The Company has fixed interest on bond payable (Note 8) therefore is not exposed to interest rate risk.

e) Price risk

Price of oil and gas are affected by the normal economic drivers of supply and demand as well as the financial investors and market uncertainty. Factors that influence these include operational decisions, natural disasters, economic conditions, political instability or conflicts or actions by major oil exporting countries. The Company is exposed to price risk with respect to commodity prices for which, if needed, the Company mitigates the risk by entering into the commodity contracts. As at 30 June 2019 the Company had no commodity contracts in place.

14. 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 June 2019, the Company's net working capital surplus was USD \$19.1 million (31 December 2018: USD \$19.3 million), which includes USD \$20.5 million (31 December 2018: USD \$20.2 million) of cash and USD \$2.9 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 \$81.6 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.

15. Changes in non-cash Working Capital

(TUSD)	30 June 2019	30 June 2018
Change in:
Accounts receivable	(136)	(470)
Inventory	(250)	91
Prepaid expenses and deposits	(62)	293
Accounts payable and accrued liabilities	73	(1,583)
Total	(375)	(1,669)

16. Pledged Assets

As at 30 June 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 June 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 95.7 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 17).

17. Commitments and Contingencies

The Company currently has 7 concession agreements with the National Agency of Petroleum, Natural Gas and Biofuels in Brazil (ANP). While certain of these concession agreements have outstanding work commitments of 8.6 million (BRL 33.3 million) a number of these are either suspended pending environmental licensing or under force majeure. 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 \$2.8 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 supplement information to management, investors, security 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	Q2 2019	Q2 2018	H1 2019	H1 2018
Revenue	14,098	7,859	25,849	16,488
Operating Netback	10,668	5,071	19,697	10,928
EBITDA6	9,188	3,960	16,851	8,526
Net result	6,157	1,859	10,405	4,165
Cash Flow from operations	6,106	3,176	13,583	6,523
Capital structure	Q2 2019	Q2 2018	H1 2019	H1 2018
Return on equity (%)	8	4	13	9
Equity ratio (%)	62	51	62	62
Other
	Q2 2019	Q2 2018	H1 2019	H1 2018
Weighted number of shares
(before dilution)	99,208,126	97,650,057	98,792,071	97,175,412
Weighted number of shares
(after dilution)	108,659,352	97,834,378	107,685,196	97,296,552
Earnings per share before
dilution, USD	0.06	0.02	0.11	0.04
Earnings per share after
dilution, USD	0.06	0.02	0.10	0.04

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 (excluding processing income) less royalties, transportation costs and operating expenses, as shown below:

(TUSD)	Q2 2019	Q2 2018	H1 2019	H1 2018
Revenue	14,098	7,859	25,849	16,488
Royalties	(1,869)	(939)	(3,379)	(2,129)
Operating Expenses	(1,196)	(1,654)	(2,106)	(2,975)
Transportation costs	(365)	(195)	(667)	(456)
Operating netback	10,668	5,071	19,697	10,928

EBITDA6

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:

(TUSD)	Q2 2019	Q2 2018	H1 2019	H1 2018
Operating results	7,772	3,237	14,002	7,035
Depletion, depreciation and amortization	1,317	724	2,755	1,588
Foreign currency exchange loss / (gain)	99	(1)	94	(97)
EBITDA in TUSD	9,188	3,960	16,851	8,526

Relevant reconciliation of Alternative Performance Measures for bond covenants:

Net Interest-Bearing Debt

(TUSD)	30 June 2019	31 December 2018
Bond payable	30,286	31,180
Less:
Cash and cash equivalents	20,504	(20,255)
Net Interest-Bearing Debt	9,782	10,925

Interest Coverage Ratio

Interest coverage ratio is defined as the ratio of EBITDA to Net Finance Costs.

⁶ Effective 1 January 2019, implementation of IFRS 16 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 Third Quarter Report: 25 November 2019 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 Technical Office

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