Maha Energy

Quarterly Report • Aug 15, 2022

Q2 Report for the SIX MONTHS ENDED 30 June 2022 (org number: 559018-9543)

Highlights

(all amounts are in US dollars unless otherwise noted)

Second Quarter 2022

• The Tie-5 well was completed free-flowing 766 BOEPD (590 BOPD and 1,054 MSCFPD) and is now producing through the Tie field's permanent facilities.
• The Tie-6 well was spudded in June and can potentially be hooked up for production during Q3.
• Daily oil & gas production for Q2 2022 averaged 3,292 BOEPD (Q2 2021: 3,104 BOEPD)
• Revenue of USD 24.0 million (Q2 2021: USD 15.2 million)
• Operating netback of USD 17.4 million or USD 64.72 per BOE (Q2 2021: USD 9.5 million or USD 35.46 per BOE)
• EBITDA of USD 14.6 million (Q2 2021: USD 9.0 million)
• Net result of USD 8.2 million (Q2 2021: USD 2.6 million)
• Basic and Diluted Earnings per share of USD 0.07 (Q2 2021: USD 0.02)
• Cash and cash equivalents balance of USD 23.9 million (Q2 2021: 34.1 million)

Six Months Ended 30 June 2022

• Daily oil & gas production for H1 2022 averaged 3,933 BOEPD (H1 2021: 3,421 BOEPD)
• Revenue of USD 54.8 million (H1 2021: USD 31.0 million)
• Operating netback of USD 39.9 million or USD 60.69 per BOE (H1 2021: USD 20.6 million or USD 34.56 per BOE)
• EBITDA of USD 36.7 million (H1 2021: USD 19.2 million)
• Net result for the period of USD 20.2 million (H1 2021: USD 8.1 million)
• Basic and Diluted Earnings per share of USD 0.17 (H1 2021: USD 0.08)
• Cash and cash equivalents balance of USD 23.9 million (31 December 2021: USD 25.5 million)

(TUSD, unless otherwise noted)	Q2 2022	Q1 2022	Q4 2021	Q3 2021	Q2 2021	H1 2022	H1 2021	FY 2021
Net Daily Production (BOEPD)	3,292	4,580	3,098	3,610	3,104	3,933	3,421	3,387
Revenue	24,018	30,831	17,818	19,496	15,178	54,849	30,992	68,306
Operating netback	17,408	22,528	11,913	13,568	9,548	39,936	20,579	46,060
EBITDA	14,621	22,069	15,615	12,909	8,988	36,690	19,201	47,725
Net result for the period	8,219	12,030	7,363	6,083	2,603	20,249	8,141	21,587
Earnings per share – Basic (USD)	0.07	0.10	0.06	0.05	0.02	0.17	0.08	0.19
Earnings per share – Diluted (USD)	0.07	0.10	0.06	0.05	0.02	0.17	0.08	0.19
Cash and cash equivalents	23,863	29,416	25,535	31,778	34,139	23,863	34,139	25,535

Financial Summary

Definitions

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

Abbreviations Oil related terms and measurements

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

Gas to oil conversion

6,000 cubic feet = 1 barrel of oil equivalent

Letter to shareholders

Dear Friends and Fellow Shareholders of Maha Energy AB,

Near record high oil prices helped our bottom line this quarter as our quarterly production volumes were lower than planned, and at the moment we are tracking around the bottom end of our 2022 production guidance of 4,000 BOEPD. Maha delivered a record first half of the year (H1) on all fronts, including production, revenues and net results. H1 average daily production landed at 3,933 BOEPD and H1 EBITDA was USD 36.7 million, almost double compared to last year's record. Our result for H1 was twice that of our previous highest H1 result recorded. But even though we experienced unwanted and frustrating temporary production setbacks in Brazil during the quarter, we are making real progress in securing long-term production stability at the Tie field. Despite higher than normal operating expenses during the quarter, our Netback per barrel is at an all time high at USD 65 per BOE. Of course, we are not happy with the temporary reduction in production volumes from the Tie field, but we are working hard on getting all of our producing wells back on production again as soon as possible. Only two out of six wells contributed to our oil production at the Tie field this quarter.

Brazil

At our core asset in Brazil, the Tie field, production was lower during the second quarter due to; natural production decline, converting the Tie-3 well from an oil producer to a water injector, oil production from Tie-5 horizontal coming on late, and losing production from three key production wells (Tie-1, GTE-3, and GTE-4). These three wells are scheduled for repair using the contracted Braserv rig during the third and fourth quarters to restore production levels.

Operationally at the Tie field, the Tie-5 well was completed as a horizontal producer in July and flowed naturally 770 BOEPD on a 24 hour test. The Tie-5 continues to produce steadily with negligible water and will contribute to offset other temporary setbacks on the Tie-field. Further, unexpected positive news was encountered on Tie-6, where the Agua Grande (AG) reservoir was penetrated 12 meters higher than predicted. This is very good news, since the reservoir is higher structurally than anticipated, the seismic mapping of the structure will have to be redefined. Furthermore, and because most of the AG is now above the oil water contact, we are currently evaluating the possibility of initially producing the oil in the AG before converting the well to a water injector, as was originally planned.

Unfortunately, delays in the drilling of the Tie-4 and Tie-5 wells have adversely impacted the schedule for Tie-1, GTE-3 and GTE-4 workovers. The Brasserv workover rig was contracted in June to commence the well intervention work to restore production on the Tie field. To date, work on completing the Tie-5 oil producer and converting the ALV-2 well to a gas injector has been completed. Next, GTE-3, GTE-4 and Tie-1 will be restored to full production during the second half of the year. Importantly, Electric Submersible Pumps (ESP) will be installed in GTE-3 and then later in Tie-2 to further boost production at Tie.

Oman

After the contracted GBS-1 drilling rig was withdrawn by the drilling contractor, the Maha team in Oman acted swiftly to secure the Gulf Drilling Company Rig-109 and drilling is now expected to commence in October. The Company also decided to strategically farm down 35% of the Block 70 Exploration and Production Sharing Agreement to Mafraq Energy LLC. Not only does the farm down manage the Company's asset risk exposure, but it also reduce cost and increase confidence in the project. Mafraq Energy brings important technical expertise as well as a strategic partnership in Oman to aid in future growth. It is probably the best proof yet of the robustness of the Mafraq field.

The Mafraq field is a delineated and tested heavy oil field onshore Oman. A previous operator tested 15,700 barrels of heavy oil from a single well over a 23 day well test period in 1991. Maha's plan is to start drilling the first six appraisal and production pilot test wells on the field starting in October.

USA

Production from the Illinois Basin was steady during the quarter and the Company continues to evaluate the results from the 2021 drilling campaign along with potential growth opportunities in the USA. At LAK Ranch in Wyoming, the Company commenced a series of regulatory well tests and well reactivations. A strategic process was initiated during the quarter to evaluate the best future options for the LAK Ranch property.

It was a 'mixed' bag of events this quarter - some good and some not so good. As previously mentioned at the Tie field, we produced from only two wells, Tie-4 and Tie-2, for most of the quarter. This affected production significantly. Delays in the drilling of Tie-5 and the tubing leaks in GTE-3, GTE-4 and Tie-1 resulted in lower production volumes during the quarter. These three wells will be returned to production now that the drilling rig is moved out of the field and the workover rig has finished the work on the ALV-2 gas injection well. The fact that the AG was penetrated higher than prognoses in the Tie-6 well is very encouraging.

The future looks bright and busy for the second half of the year. With the workovers on the Tie field, we will add important barrels to our production and with the unexpected results of Tie-6, we may have a total of seven producing wells there, providing important production redundancy. Finally, in Oman, we will start the drilling of the large Mafraq structure and commence well test production at a commercial level. It is going to be a very busy second half of the year.

Finally, I wish to thank my fellow Maha colleagues who work so tirelessly for all of us, and to all loyal shareholders who support us. Thank you!

Yours truly,

"Jonas Lindvall"

Managing Director

Financial Report for the Second Quarter Ended 30 June 2022

OPERATIONAL AND FINANCIAL REVIEW

Strategy

The Company's business activities include the exploration for and the 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	Net Area (acres)	BOEPD (1 )	Partner
Brazil	Tie (REC-T 155)	100%	Producing	1,511	2,537
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	Tartaruga	75%	Producing	5,944	213	Petrobras (25%)
USA	Il Basin (various)	97%	Producing	3,597	540
USA	LAK Ranch	99%	Pre-Production	6,475	2	SEC (1%)
Oman	Block 70	100%	Pre-Production	157,900	-	-

BRAZIL

Tie Field (Reconcavo Basin)

Maha owns and operates, through a wholly-owned subsidiary, 100% working interests in 6 onshore concession agreements located in the Reconcavo Basin of Brazil, including the oil producing Tie field. The Tie field and the 6 concessions are located in the state of Bahia, onshore Brazil. The 6 concessions are in varying stages of exploration and development. A total of 10 wells have been drilled and 212 km² of 3D seismic had been acquired by the previous Operator over the 41,606 total acres when Maha acquired the six concessions.

The Tie field, originally discovered in 2008, was acquired by Maha Energy in the summer of 2017. At the time of acquisition, the field was producing from two free flowing wells, GTE-3 and GTE-4. Production was constrained by well productivity, gas handling capacity and 1,300 BOEPD oil and gas offtake (sales) limitations. The field produce from two separate sandstone reservoirs, the Agua Grande (AG) and Sergi (SG). Since the field is not attached to a pipeline system, all oil and gas production is treated and marketed locally.

¹ As per the current quarter reported net production volumes to Maha before royalties. 1 BBL = 6,000 SCF of gas. Approximately 87% of Maha's oil equivalent production is crude oil.

In 2018 Maha embarked on an aggressive expansion project to boost production and secure further oil and gas offtake (sales) volumes. Less than two years later, the Company had secured a total of 4,850 BOPD oil offtake capacity, increased associated gas sales, drilled its' first production well on the field and installed artificial lift on GTE-4, all in an effort to increase production. Furthermore, critically needed water injection to maintain reservoir pressure was also initiated the same year. To cater for the expansion, the production facilities were upgraded from 2,000 BOPD to 5,000 BOPD by adding new and larger separation equipment, more storage tanks and a brand new 4 truck loading station. Gas offtake capacity was expanded by increasing compressed natural gas deliveries as well as introducing gas-to-wire gas generators.

By the end of 2021, a total of three more wells had been drilled on the field (Tie-2, Tie-3 and Tie-4) to increase production, artificial lift systems had been installed on all producing wells, and two 1,320 HP Ariel gas compressors were commissioned to allow for gas re-injection. The gas re-injection capability decouples oil production from the associated gas production and allows for continuous oil production irrespective of gas delivery constraints.

The oil is trucked to a refinery and two separate receiving stations, and the gas is disposed through a combination of compressed natural gas and gas-to-wire generators, and re-injection.

At the end of January 2022, the Tie-4 well was tied into the permanent production facilities and following a 24-hour test using an Electric Submersible Pump (ESP) produced 4,400 BOPD and 1,766 MSCFPD (4,695 BOEPD) with a stable tubing-head flowing pressure of 220 psi. Both the (AG) and (SG) zones were perforated with comingled production using an ESP.

Tie-5 (Horizontal well)

Maha spudded the Tie-5 AG horizontal well on 25 January 2022. It was designed as a horizontal well with an Electric Submersible Pump (ESP) and will drain the northern part of the Tie field at the AG level. Subsequent to the current quarter end, the Tie-5 well was completed and underwent a series of stimulation and clean out operations to enhance production. The Tie-5 well penetrated 240 meter of AG sand and commenced naturally flowing, without the assistance of an ESP, 766 BOEPD (590 BOPD and 1,054 MSCFPD) with a stable tubing-head flowing pressure of 220 psi and less than 1% water.

Tie-6 (Water injector well)

Maha spudded the Tie-6 water injector well on 12 June 2022. Total depth (2,282 meters) was reached on 17 July 2022 and the well has been completed. The Agua Grande reservoir was encountered 12 meters true vertical depth (TVD) higher than expected, so the well was completed as a temporary oil producer in the AG. The Sergi was encountered 5 meters (TVD) higher to prognosis and both reservoirs intersected the oil water contact (OWC).

Average production from the Tie field during the current quarter was 2,537 BOEPD (2,144 BOPD of oil and 2,356 MSCFPD of gas).

Tartaruga Field (Sergipe-Alagoas Basin)

Maha has a 75% working interest in the Tartaruga development block, located in the Sergipe-Alagoas Basin onshore Brazil. Petrobras holds the remaining 25%. The Tartaruga field is located in the northern half of the 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 commercially produced (Penedo 1 and Penedo 6).

The Tartaruga oil field, originally discovered in 1994, was acquired by Maha in 2017. At the time of acquisition, the field was producing from a single well, using a hydraulic jet pump. A second well, TTG-2, produced sporadically on free flow which Maha converted to an artificial lift system after which production doubled almost overnight. In 2019, the Company converted TTG-2 to a horizontal production sidetrack and field production almost touched 1,000 BOPD (gross). A follow up well (TTG-3) was drilled in 2020 targeting the northern fault block of the structure, primarily to appraise the structure and to obtain important reservoir data. After a series of Drill Stem Tests (DST's), in 4 separate sandstone zones of the Penedo formation, it was concluded that the northern fault compartment of the Tartaruga field was likely affected by reservoir degradation. All four (4) zones were stimulated but did not flow commercial quantities of oil. Focus thereafter has shifted towards the southern fault block where two wells are currently producing commercial quantities of oil.

The Penedo sandstone reservoir responds extremely well to hydraulic stimulation techniques and flows very little water.

The handling facilities at Tartaruga field allow for approximately 800 BOPD of oil processing and has storage capacity at 1,350 barrels of oil. Currently, crude oil export is with oil trucks as the facility is not linked to a pipeline system.

Since July 2020, the Company commenced selling associated natural gas to a third-party company Geracao E Servicos Ltda ("GTW"). The natural gas feeds six (6) generators which produce electricity for field consumption and to the local power grid.

Average production, net to the Company, from the Tartaruga field during the current quarter was 213 BOEPD (204 BOPD of oil and 54 MSCFPD of gas).

USA

Illinois Basin (IB)

On 31 March, 2020, Maha acquired certain oil producing assets in the Illinois Basin, USA, adding oil and gas leases to Maha's USA footprint. The Illinois Basin is one of the oldest oil producing basins in North America having produced over 4 billion barrels of oil to date. Oil was initially discovered in 1853 according to historical records and oil is found in multiple shallow Dolomite and Sandstone reservoirs. Most producers in the area produce oil from 3 separate reservoirs that act independently of each other. This is a low-risk conventional oil play that requires low-cost drilling and stimulation operations.

On 1 March 2022 Maha begun drilling the Glaze 11-5 well in the Illinois Basin. This 4,000' vertical well is located in the heart of the Mississippi Lime play in Illinois Basin targeting several stacked pay layers. Glaze 11-5 well was drilled and completed during the first quarter of 2022 and is now contributing to the daily production volumes in the Illinois Basin. During the first quarter, the Company signed a 463 acre land lease in Indiana, USA. The lease provides Maha the opportunity to drill up to 23 production wells on the leased land. The land is adjacent to land already held by Maha in the area and is a very good extension of the existing production from the Illinois Basin. The lease requires Maha to drill at least one well during the first three years of the lease and then at least one well every year thereafter to retain the land.

Average net production from the Illinois basin during the current quarter was 540 BOPD of oil following the 12 wells drilling program of 2021.

LAK Ranch (LAK)

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 LAK Ranch heavy oil asset was shut in at the beginning of 2020 Covid-19 pandemic. For the time being, minimal work is planned for 2022 including meeting regulatory requirements. To that end, incidental work commenced to restart production from a handful of wells. During the current quarter, 198 barrels of incidental oil was produced while conducting well related work.

Oman

Block 70

On 5 October 2020, the Company entered into an Exploration and Production Sharing Agreement ("EPSA") with the government of the Sultanate of Oman, for Block 70, an onshore block in Oman. The EPSA was subsequently ratified by Royal Decree of His Majesty the Sultan of Oman on 28 October 2020 and Maha became the operator of the block, holding a 100% working interest. The EPSA covers an initial exploration period of three years with an optional extension period of another three years. In case of a commercial oil or gas discovery, the EPSA can be transformed into a fifteen-year production license which can be extended for another five years. The EPSA contains provisions on the parties' entitlement to produced oil, natural gas and condensate.

Block 70 is an onshore block that includes the shallow fully delineated but undeveloped Mafraq oil field. The Mafraq oil field was discovered by Petroleum Development Oman (PDO) in 1988 and was further delineated by four wells and 3D seismic in stages until 2010. Two wells were placed on pump production tests, of which one was placed on a 22-day test and produced a stable and cumulative volume of over 15,700 barrels of 13° API oil before operations were suspended. The Mafraq oil field is estimated by third parties to contain between 185 – 510 million barrels of original oil in place (OOIP). The productive reservoir is shallow, at approximately 430 meters below ground level.

During the first and second quarters, the Company continued to work towards the commencement of its 2022 drilling program, including securing necessary approvals and securing key service providers. In April, the Company signed a drilling rig contract to drill six (6) wells; however, subsequent to the current quarter, the drilling rig contractor notified Maha that the drilling rig GB-1 would be unavailable due to technical deficiencies uncovered during pre-mobilisation inspections. Hence, the drilling program of two (2) appraisal wells followed by four (4) horizontal pilot production wells on the Mafraq structure did not commence as planned. A new drilling rig, Rig 109, provided by Gulf Drilling LLC, a wholly owned subsidiary of MB Petroleum Services Worldwide was subsequently contracted and drilling is now anticipated to commence during the fourth quarter this year. In addition, subsequent to the quarter end the Company entered into an agreement with Mafraq Energy LLC to farmout 35% of working interest in the Block 70 EPSA (See Note 18 for further details).

Information that will be acquired from the two (2) appraisal wells will include but is not limited to: the Oil Water Contact (OWC), petrophysical and structural properties, and identification of possible water injection zones. Two (2) appraisal wells will be drilled along with four (4) horizontal pilot production test wells. These four (4) production test wells will be completed with state-of-the-art PCP pumps from Canada and then placed on an extended production well test to further ascertain oil productivity.

Financial Results Review

Result

The net result for the current quarter amounted to TUSD 8,219 (Q2 2021: TUSD 2,603) representing earnings per share of USD 0.07 (Q2 2021: USD 0.02). The net result increase, as compared to the comparative period, was mainly driven by significantly higher net revenue from higher oil commodity prices, current tax recovery, other income and lower net finance costs which was partly offset by higher operating expenses, depletion, depreciation and amortization costs, and general and administrative costs. The oil commodity prices remained strong during the current quarter due to supply demand imbalance and geopolitical uncertainty.

The net result for the first half of 2022 ("H1 2022") amounted to TUSD 20,249 representing earnings per share of USD 0.17 as compared to the first half of 2021 ("H1 2021") which amounted to TUSD 8,141 representing earnings per share of USD 0.08. Higher net result for the H1 period is mainly due to higher revenue for the period as compared to the comparative period which was offset by higher production expenses and depletion, depreciation and amortization costs. Higher general and administrative costs were slightly offset by higher other income.

The Company also generated higher quarterly earnings before interest, tax, depletion and amortization (EBITDA) for the second quarter of TUSD 14,621 (Q2 2021: TUSD 8,988) and for H1 2022 of TUSD 36,690 (H1 2021: TUSD 19,201) mainly due to the same reasons as above.

Production

					Full Year
	Q2 2022	Q2 2021	H1 2022	H1 2021	2021
Delivered Oil (Barrels)	263,035	257,545	619,121	563,904	1,104,631
Delivered Gas (MSCF)	219,355	149,636	556,133	332,088	790,532
Delivered Oil & Gas (BOE)2	299,594	282,484	711,810	619,252	1,236,386
Daily Volume (BOEPD)	3,292	3,104	3,933	3,421	3,387

Production volumes shown are net working interest volumes before government, gross overriding, and freehold royalties. Approximately 88% (Q2 2021: 91%) of total oil equivalent production was crude oil for Q2 2022.

The average daily production volumes for the current quarter are in line with the comparative quarter as production volumes added from the new Tie-4 well was offset by lower production volumes from other wells of the Tie field, which are scheduled for workover operations to reactivate production during the second half of 2022. The Tie-3 well was converted to an injector well and the Tie-2 well production was lower than prior period due to natural depletion and expected increasing water cuts. In addition, the Tartaruga field production volumes were also lower due to natural declines during the current quarter as compared to Q2 2021. Decrease in production volumes in Brazil was offset by increase in production volumes in the Illinois Basin resulting from the 12 new wells in the Illinois Basin during 2021. Gas volumes also increased as compared to the comparative quarter due to an expected increase in Gas-to-Oil-Ratio ("GOR") in the Tie field, as higher volumes are produced from the field with the addition of new wells and increased gas handling capacity.

Average daily production volumes were higher by 15% for the first half of 2022 as compared to the same period in 2021 due to additional production volumes from the newly added Tie-4 well and 12 new wells in the Illinois Basin during the first half of 2022 as compared to the comparative period. The Company had record production volumes during the first quarter which was partially offset by lower production volumes during the second quarter.

					Full Year
(TUSD, unless otherwise noted)	Q2 2022	Q2 2021	H1 2022	H1 2021	2021
Oil and Gas revenue	24,018	15,178	54,849	30,992	68,306
Sales volume (BOE)	268,943	269,249	657,962	595,590	1,206,332
Oil realized price (USD/BBL)	101.21	61.35	94.20	56.73	62.60
Gas realized price (USD/MSCF)	1.06	0.86	0.95	0.72	0.79
Oil Equivalent realized price (USD/BOE)	89.30	56.37	83.36	52.04	56.62
Reference price – Average Brent (USD/BBL)3	113.54	68.97	106.92	64.94	70.86
Reference price – Average WTI (USD/BBL)	108.72	66.04	101.59	61.90	68.13

Revenue

Revenue for the current quarter amounted to TUSD 24,018 (Q2 2021: TUSD 15,178), representing an increase of 58% as compared to Q2 2021. This increase was mainly driven by higher realized oil price by 65%, in line with the higher average Brent oil price increase of 65%. Oil and gas sales volumes were effectively the same as the comparative quarter mainly due to two months of Tartaruga field current quarter production that was not sold at the end of the quarter. Subsequent to the quarter end, this production was sold.

² BOE is Barrels of Oil Equivalent and takes into account gas delivered and sold. 1 bbl = 6,000 SCF of gas

³ Reference price is as per U.S. Energy Information Administration website.

Revenue for the H1 2022 amounted to TUSD 54,849 (H1 2021: TUSD 30,992), representing an increase of 77% as compared to the H1 2021. The increase in revenue is consistent with the higher realized oil price by 66% and higher sales volume by 10%.

Crude oil realized prices in Brazil are based on Brent price less applicable contractual discounts, reviewed annually, as follows:

Tie Field crude oil

Crude oil from the Tie field is mainly sold to a nearby refinery Dax Oil Refino S.A. ("DAX") and Petrobras. For crude oil sold to DAX the discount to Brent oil price is as per the following price-based scale:

BRENT Price (USD/bbl)	Discount (USD/bbl
< \$30	\$5
Between 30.1 and 40	\$6
Between 40.1 to 50	\$7
Between 50.1 to 80	\$8
Over 80.1	10%

Effective 1 April 2022, crude oil sales to Petrobras from the Tie field are sold at a significantly lower discount to Brent oil price of \$5.17/bbl. Previously, discount was \$6.48/bbl for the first 22,680 monthly delivered barrels, and \$5.44/bbl thereafter, plus associated taxes calculated as 5% of the net price after applying the contractual discount which no longer apply under the renewed sales agreement.

Tartaruga Field crude oil

Crude oil from the Tartaruga field is entirely sold to Petrobras. Effective 1 July 2022, crude oil sales to Petrobras from the Tartaruga field are sold at a discount to Brent oil price of \$6.95/bbl. Previously, crude oil sales to Petrobras from the Tartaruga field were sold at a discount to Brent oil price of \$3.40/bbl.

Illinois Basin

Crude oil from the Illinois Basin is sold to a refinery at the benchmark monthly average WTI price minus a discount of approximately \$3/bbl.

More revenue information is detailed in Note 4 to the Condensed Consolidated Financial Statements.

Royalties

					Full Year
(TUSD, unless otherwise noted)	Q2 2022	Q2 2021	H1 2022	H1 2021	2021
Royalties	2,802	2,153	6,769	4,494	9,384
Per unit (USD/BOE)	10.42	8.00	10.29	7.55	7.78
Royalties as a % of revenue	11.7%	14.2%	12.3%	14.5%	13.7%

Royalties are settled in cash and based on realized prices before discounts. Royalty expense increased by 30% for the current quarter and 51% for H1 2022 as compared to the same periods in 2021 which is consistent with higher revenue for the same periods. Effective royalty rate for the current quarter and H1 2022 is lower than the comparative periods of 2021 as a result of the successful obtention of a 2.5% royalty rate reduction in Brazil which came into effect beginning February 2022. Royalty rates for IB remained same as the comparative period.

Production expenses

					Full Year
(TUSD, unless otherwise noted)	Q2 2022	Q2 2021	H1 2022	H1 2021	2021
Operating costs	3,392	3,073	7,086	5,112	11,196
Transportation costs	416	404	1,058	807	1,666
Total Production expenses	3,808	3,477	8,144	5,919	12,862
Per unit (USD/BOE)	14.16	12.91	12.38	9.93	10.66

Production expenses are higher by 10% for the current quarter and amounted to TUSD 3,808 (Q2 2021: TUSD 3,477) and higher by 38% for H1 2022 and amounted to TUSD 8,144 (H1 2021: TUSD 5,919).

Operating costs are higher during the current quarter and H1 2022 as compared to the same periods in 2021 mainly due to higher costs in the Tie field and Illinois Basin. During the quarter due to lower volume of gas production, the Company incurred TUSD 144 in take-or-pay penalties. In addition, the Tie field overall operating costs increased due to additional rental equipment and labour costs required when Tie-4 was placed on production and higher overall costs due to inflationary cost increases. Certain well workovers during H1 2022 also added to the overall operating costs.

In IB, the overall increase in operating costs is in line with the increase in sales volumes by 162% for the current quarter and 111% for H1 2022 from the production additions following the 12 new wells that were drilled during 2021. In addition, inflation and workovers performed to clean out certain wells also added to the overall increase in operating costs of the Illinois Basin.

Maha's production is trucked to the delivery points therefore transportation costs are directly correlated to the sales volumes. Transportation costs for the current quarter are mainly in line with the comparative period as the sales volumes for the current quarter are similar to the comparative period. Transportation costs for H1 2022 is higher by 31% mainly due to higher sales volume by 13% and overall increase in transportation rates due to higher diesel costs.

On a per BOE (or unit) basis, production expenses for the current quarter are USD 14.16 per BOE (Q2 2021: USD 12.91 per BOE) and are higher by 10% as compared to the same period last year mainly due to the same reasons as above. On a per BOE (or unit) basis, production expenses for H1 2022 are USD 12.38 per BOE (H1 2021: USD 9.93 per BOE) and are higher by 25% as compared to the same period last year mainly due to the same reasons as above.

Operating netback

					Full Year
(TUSD, unless otherwise noted)	Q2 2022	Q2 2021	H1 2022	H1 2021	2021
Operating Netback	17,408	9,548	39,936	20,579	46,060
Netback (USD/BOE)	64.72	35.46	60.69	34.56	38.18

Operating netback is a non-GAAP financial metric used in the oil and gas industry to compare performance internally and with industry peers and is calculated as revenue less royalties and production expenses. Operating netback for the current quarter is 82% higher than the comparative period from significantly higher oil realized prices slightly offset by lower sales volumes and higher production costs during the current quarter.

Operating netback for H1 2022 is 94% higher than the comparative period mainly due to significantly higher oil realized price and higher sales volumes slightly offset by higher production costs year to date.

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

					Full Year
(TUSD, unless otherwise noted)	Q2 2022	Q2 2021	H1 2022	H1 2021	2021
DD&A	3,122	1,782	7,388	3,692	8,535
DD&A (USD/BOE)	11.61	6.62	11.23	6.20	7.08

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

DD&A expense for the current quarter is higher and amounted to TUSD 3,122 (at an average depletion rate of USD \$11.61 per BOE) as compared to TUSD 1,782 (at an average depletion rate of USD \$6.62 per BOE) for the comparative period. Depletion expense and depletion rate on a per BOE basis increased because of the higher depletable base for Brazil which was impacted by the increase in the future development capital costs at yearend 2021 and reduction in the year end 2021 Brazil reserves. In addition, higher DD&A expense for the Illinois Basin due to higher depletable base and higher sales volumes added to the depletion expense.

For H1 2022, DD&A expense increased by 100% and amounted to TUSD 7,388 (at an average depletion rate of USD \$11.23 per BOE) as compared to TUSD 3,692 (at an average depletion rate of USD \$6.20 per BOE) for the comparative period. Depletion expense and depletion rate on a per BOE basis increased because of the same reasons as above.

General and Administration ("G&A")

					Full Year
(TUSD, unless otherwise noted)	Q2 2022	Q2 2021	H1 2022	H1 2021	2021
G&A	1,611	1,163	3,063	2,444	5,517
G&A (USD/BOE)	5.99	4.32	4.66	4.10	4.57

G&A amounts are presented net of certain costs allocated to production expenses. G&A expense for the current quarter amounted to TUSD 1,611 (USD 5.99 per BOE) which is 39% higher than the same period in 2021. G&A expenses are higher mainly due to increasing operations in Oman and inflationary increases in majority of the costs.

G&A expense for the H1 2022 amount to TUSD 3,063 (USD 4.66 per BOE) which is higher by 25% from the comparative period of TUSD 2,444 (USD 4.10 per BOE) mainly due to the same reasons described above.

On a per BOE basis, G&A for the current quarter is higher by 39% than the comparative period mainly due to the same reasons as above. For H1 2022, G&A on a per BOE basis is higher by 14% mainly due to higher G&A amounts offset by higher sales volumes in the current period.

Exploration and business development costs

Exploration and business development costs amounted to TUSD 104 for the current quarter and H1 2022 as compared to TUSD -44 and TUSD 6 respectively for the comparative periods in 2021. Exploration and business development costs are related to costs incurred for the maintenance of the exploration blocks in Brazil and Maha's pre-exploration study of new areas or new ventures, including business development efforts.

Foreign currency exchange gain or loss

The net foreign currency exchange gain for the current quarter amount to TUSD 176 (Q2 2021: TUSD 858 loss) and for H1 2022 amount to gain of TUSD 100 (H1 2021: TUSD 782 loss). Foreign exchange movements occur on settlement of transactions denominated in foreign currencies. Foreign exchange loss was significant for the comparative periods of 2021 due to the Company's increased exposure to US dollars with the addition of the US dollars debt financing in the parent Company that had Swedish Krona as its functional currency. As of 1 July 2021, the Company converted the parent company's functional currency to US Dollars.

Other income and expenses

Other expense for the current quarter amounted to TUSD 894 (Q2 2021: 665 income). During the current quarter, the Company revised previously recognized tax credits in Brazil known as Imposto sobre Circulação de Mercadorias e Serviços ("ICMS") to reflect its recognition in income only when these tax credits are utilized. ICMS is a tax on the circulation of goods and transportation and communication services, a state sales tax. These tax credits can be applied to importation related duties of the Company, or it can be sold to external parties for their utilization. For H1 2022, the Company recognized TUSD 245 of other income mainly related to ICMS credits that the Company would be able to fully utilize or sell in the due course of business.

Net finance costs

Net finance costs for the current quarter amounted to TUSD 2,098 (Q2 2021: TUSD 2,306) and for H1 2022 amounted to TUSD 4,506 (H1 2021: TUSD 3,728) and are detailed in Note 5. Net finance costsfor the current quarter are lower by 9% than the comparative quarter mainly due to high interest income from term deposits and expected interest on tax credits, whereas Q2 2021 included interest related to BTG financing and one month's interest of the Bonds which were fully redeemed in May 2021. Net finance costs for H1 2022 are higher by 21% than the comparative period mainly due to higher interest related to BTG financing as compared to the Bonds interest which were fully redeemed in May 2021.

Income Taxes

The Company recorded a current tax recovery of TUSD 1,989 for the current quarter and a recovery of TUSD 2,194 for H1 2022 as compared to current tax expense of TUSD 708 and TUSD 1,333, respectively, for the same comparative periods. During the current year, the Company adopted accelerated amortization tax deductions available in Brazil. The Company applied the accelerated amortization tax deductions for the fiscal year 2021 and retroactively to prior years 2018 through 2020 and refiled the tax returns for these years which resulted in tax recoveries of approximately USD 3.0 million to be applied as a tax credit against taxes payable. During the first quarter the Company had applied accelerated amortization tax deduction to the 2021 tax year filings and recorded a recovery of 0.8 million.

Included in the accounts receivable and other credits of USD 8.4 million is the tax recovery of USD 3.2 million and other tax credits.

Taxation of corporate profits in Brazil is a combined 34% rate (25% corporate income tax and 9% Social contribution); however, Maha Energy Brazil Ltda. has secured certain tax incentives (SUDENE) in both of its fields until fiscal year 2029 allowing for the reduction of 75% of the corporate income tax from 25% to 6.25%, bringing the combined net tax rate to 15.25%.

Deferred tax expense for the current quarter amounted to TUSD 3,347 and TUSD 6,841 for H1 2022 as compared to deferred tax expense of TUSD 731 and TUSD 1,525 respectively, for the comparative periods. Deferred tax expense increased during the current quarter significantly mainly due to the accelerated amortization deduction in Brazil which reduced the available deferred tax asset balance to nil and resulted in a deferred tax liability balance of TUSD 2,317, as the available tax pools for future utilization become lower than the book values. A deferred tax asset or a deferred tax liability results from temporary differences between the tax and accounting treatment of the amortization of long-term assets, tax-losses carry-forwards and certain provisions.

The Company operates in various countries and fiscal regimes where corporate income tax rates are different from those in Sweden. Corporate income tax rates for the Company can vary between 15 and 28 percent however the majority of it relates to Brazil where the resulting income tax rate for Maha, following approved incentives, is 15.25% The effective tax rate for the reporting period is affected by several items which do not receive a full tax credit.

Exchange differences on translation of foreign operations

The functional currency of Company's subsidiary in Brazil is Brazilian Reals; however, for the presentation purpose all assets and liabilities are translated at the period end exchange rate and the Statement of Operations is translated at the average exchange rate of the period.

The exchange differences on translation of foreign operations presented in Statement of Comprehensive Earnings amounted to TUSD -14,632 (Q2 2021: TUSD 10,879) for the current quarter mainly due to the US Dollar exchange rate at 30 June 2022 strengthened against Brazilian Real by 11% as compared to 31 March 2022 exchange rate.

The exchange differences on translation of foreign operations presented in Statement of Comprehensive Earnings amounted to TUSD 6,092 (H1 2022: TUSD 5,503) for H1 2022 mainly due to the US Dollar exchange rate weakened against Brazilian Real by 6% since 31 December 2021. Volatility in the exchange rate between the Brazilian Real and the US Dollar exchange rate has been high as the US Dollar weakened during the period ended 31 March 2022 and regained strength during the period ended 30 June 2022.

Liquidity and capital resources

The Company manages its capital structure to support the Company's strategic growth. The Company's objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company's financial obligations as they come due. The Company actively manages its liquidity through cash and debt management strategies. The Company considers its capital structure to include shareholders' equity of USD 118.1 million (31 December 2021: USD 91.4 million) plus net debt of USD 28.8 million (31 December 2021: USD 29.9 million). At 30 June 2022, the Company's working capital surplus was USD 1.6 million (31 December 2021: USD 5.8 million), which includes USD 23.9 million of cash (31 December 2021: USD 25.5 million).

On 30 March 2021, the Company entered into a credit agreement for a senior secured term loan of USD 60 million (the "Term Loan"), maturing 31 March 2025. The proceeds were used to redeem the outstanding SEK 300 million bond and to fund the Company's oil and gas production expansion program. As part of the closing of the financing transaction, Maha also received an equity contribution of USD 10 million through the Private Placement issuance of 7,470,491 new sharesto the same bank. The Company began paying down the Term Loan during the current quarter.

The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. 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 market and industry conditions. The annual budget and subsequent updates are approved by the Board of Directors.

Share Data

Shares outstanding	A	B	Total
31 December 2021	119,715,696	-	119,715,696
31 June 2022	119,715,696	-	119,715,696

No shares were issued during the current quarter or H1 2022.

Risks and Uncertainties

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 the mitigation of those risks through risk management is described in Maha Energy's 2021 Annual Report (page 39 – Page 42).

In addition, the COVID-19 pandemic could have negative impacts on the Company's financial condition, results of operations, and cash flows. Despite successful vaccine rollouts in many jurisdictions, the risk of a resurgence or additional variant strains remains high and could result in continued fluctuations in the price of oil and conventional natural gas products. The extent to which such events impact the Company's business, financial condition and results of operations will depend on future developments, which are highly uncertain and cannot be predicted with any degree of confidence.

Further, in February 2022, Russian military forces invaded Ukraine and the market faces a highly uncertain future as the Russia-Ukraine conflict develops. We expect the general outlook for oil and gas prices will be volatile and impacted by the duration and severity of the conflict, the extent to which Russian exports are reduced by sanctions, the timing and ability of producers and governments to replace reduced supply, and OPEC+ policy. The long-term impacts of the conflict and the sanctions imposed on Russia remain uncertain and the Company continues to monitor the evolving situation.

Legal matters

The Company has several ongoing legal matters concerning labor, regulatory and operations. All of these are considered routine and consistent with doing business in Brazil. Provisions for lawsuits are estimated in consultation with the Company's Brazilian legal counsel and have been recorded under non-current liabilities and provisions.

Environment, Social, and Governance (ESG)

Through responsible operations and strategic planning, Maha seeks to create long-term value for all of its stakeholders. Thereby, Maha conducts its operations in a manner respects its workforce, neighboring communities, and the environment. Part of contributing to society and being a good global citizen is to not only to adhere to laws and regulations, but to integrate stakeholder interests into its Corporate Strategy. Part of Maha's business and operational development is engaging with stakeholders as their interests play an important role in the Company's business activities and success. The Company defines stakeholders as individuals, communities, and organizations that are and may be affected by Maha's operations; or whose actions can reasonably be expected to affect the ability of the Company to successfully implement its strategies and achieve its objectives. Stakeholder engagement is the process whereby information and perspectives in relation to Maha's activities are exchanged. For more information on Maha's ESG initiatives, please review Maha's Sustainability Report on the website (www.mahaenergy.ca).

Environment

Respecting and minimizing impacts to the environment is a key component in Maha's development plans and operations. Thereby, Maha incorporates environmental management strategies into operational planning, execution, and is considered throughout all stages of Maha's business activities. Company operations are conducted in a manner that respects the environment and is, at minimum, in compliance with the applicable environmental laws and regulations. A key component in Maha's environmental management is the notion of being proactive rather than reactive. Proactively identifying, anticipating, planning, and preventing costly and impactful scope changes in development plans and operational activities help Maha minimize, if not eliminate, environmental and social impacts prior to them possibly occurring. Proactive management can also address potential irreversible impacts and allows for decisions to be made on strategy and management, rather than responding out of necessity to a situation. This allows Maha to plan to fully utilize its resources, minimize waste, as well as minimize potential environmental and social impacts. For example, Maha recycle or reinject produced water at the facilities, which not only reduces having to find water from another source, but also reduces waste water treatment requirements. In Brazil, Maha is reducing the release of natural gas by using the waste gas from oil production to generate electricity.

Social

Maha values the relationship with its employees, community members, and other stakeholders. Therefore, efforts are made to engage with its employees and local communities in a transparent and respectful manner. One example of promoting two-way communication is the implementation of the MahaConnect program. This Program is a twoway communication channel that allow local stakeholders to formally connect with Maha. MahaConnect helps Maha understand local questions, concerns and inquiries as well as allow for the opportunity to address them. To ensure stakeholders have the available tools to connect with Maha, the MahaConnect program allows for three different communication channels to be utilized: 1) Email, 2) Physical mail, and 3) Community meetings. The information about the program has been distributed to local communities through the educational pamphlet and community meetings, and can be found on Maha's website. All inquiries may be submitted anonymously, but Maha encourage all individuals to identify themselves to facilitate a proper two-way transparent conversation.

Additionally, Maha seeks to ensure local communities benefit from its operations, both directly and indirectly. Direct hiring and encouraging subcontractors to hire local suppliers wherever possible is a way for Maha to contribute to the local communities and economy. Maha has also connected with Local Community Associations to maintain an open and transparent dialogue with the communities near its operations and to promote local hiring wherever possible.

Governance

Corporate Governance is an integral part of the company's foundation that guides Maha's corporate culture, business objectives, and helps accommodate stakeholder interests. Maha is committed to conducting business honestly, safely, ethically, and with integrity in full compliance with laws, rules, and regulations applicable to the business in the countries in which it operates. Personal and business ethics are taken seriously at Maha and underlie all the regulations in Corporate Governance. All employees must at all times comply with applicable laws, rules, and regulations, as well as adhere to internal policies and procedures. All employees must avoid any situation that could be perceived as improper, unethical, or indicate a casual attitude towards compliance with such laws, rules and regulations. Employees must not contribute to any violations that might be committed by other parties in Maha's business relationships or other stakeholders. Part of Maha's Corporate Governance is that Maha does not tolerate any form of corrupt practices and has in place Corporate Governance Policies that clearly define how business must be conducted. 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 to adhere to. In addition to Corporate policies review sessions, all of Maha's Corporate Governance policies, procedures and guidelines are acknowledged and readily available to employees.

Subsequent Event

Subsequent to the quarter end, the Company entered into a farmout agreement with Mafraq Energy LLC granting this strategic partner a 35% working interest in the onshore oil-bearing Block 70 in Oman in exchange for Mafraq Energy LLC reimbursing Maha for their prorated share of all past costs including the signature bonus. Mafraq Energy LLC will also be required to pay their share of all future expenditures on Block 70. Mafraq Energy LLC brings important technical expertise as well as strategic partnership in Oman for future growth.

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 net result for the Parent Company for Q2 2022 amounted to TSEK -11,796 (Q2 2021: TSEK -22,189) which is higher than the comparative period mainly due to unrealized foreign currency exchange gain of TSEK 5,636 (Q2 2021: TSEK 8,856 loss) due to US dollar denominated Term loan. This was slightly offset by higher net finance costs of TSEK 14,738 (Q2 2021: TSEK 10,658) due to higher interest expense on the Term loan. General and administrative costs of TSEK 2,694 (Q2 2021: TSEK 2,675) for the current quarter was in line with the comparative period.

The net result for the Parent Company for H1 2022 amounted to TSEK -25,627 (H1 2021: TSEK -21,630) which is lower than the comparative period mainly due higher net finance costs of TSEK 26,202 (H1 2021: TSEK 13,903) due to higher interest expense on the Term loan. This was offset by lower general and administrative costs of TSEK 4,414 (H1 2021: TSEK 5,003) and unrealized foreign currency exchange gain of TSEK 4,989 (H1 2021: TSEK 2,724 loss) due to US dollar denominated Term loan.

Financial Statements

Condensed Consolidated Statement of Operations

(TUSD) except per share amounts	Note	Q2 2022	Q2 2021	H1 2022	H1 2021
Revenue
Oil and gas sales	4	24,018	15,178	54,849	30,992
Royalties		(2,802)	(2,153)	(6,769)	(4,494)
Net Revenue		21,216	13,025	48,080	26,498
Cost of sales
Production expense		(3,808)	(3,477)	(8,144)	(5,919)
Depletion, depreciation and amortization	6	(3,122)	(1,782)	(7,388)	(3,692)
Gross profit		14,286	7,766	32,548	16,887
General and administration		(1,611)	(1,163)	(3,063)	(2,444)
Stock-based compensation	11	(178)	(106)	(324)	(106)
Exploration and business development costs		(104)	44	(104)	(6)
Foreign currency exchange gain (loss)		176	(858)	100	(782)
Other income (loss)		(894)	665	245	1,178
Operating result		11,675	6,348	29,402	14,727
Net finance costs	5	(2,098)	(2,306)	(4,506)	(3,728)
Result before tax		9,577	4,042	24,896	10,999
Current tax recovery (expense)		1,989	(708)	2,194	(1,333)
Deferred tax recovery (expense)		(3,347)	(731)	(6,841)	(1,525)
Net result for the period		8,219	2,603	20,249	8,141
Earnings per share basic		0.07	0.02	0.17	0.08
Earnings per share diluted		0.07	0.02	0.17	0.08
Weighted average number of shares:
Before dilution		119,715,696	110,116,842	119,715,696	106,028,049
After dilution		120,452,364	110,294,944	120,231,090	106,290,184

Condensed Consolidated Statement of Comprehensive Earnings

(TUSD)	Note	Q2 2022	Q2 2021	H1 2022	H1 2021
Net Result for the period		8,219	2,603	20,249	8,141
Items that may be reclassified to profit or loss:
Exchange differences on translation of
foreign operations		(14,632)	10,879	6,092	5,503
Comprehensive result for the period		(6,413)	13,482	26,341	13,644
Attributable to: Shareholders of the Parent Company		(6,413)	13,482	26,341	13,644

Condensed Consolidated Statement of Financial Position

(TUSD)	Note	30 June 2022	31 December 2021
ASSETS
Non-current assets
Property, plant and equipment	6	143,314	117,411
Exploration and evaluation assets	7	16,590	13,660
Deferred tax assets		-	3,583
Other long-term assets		506	491
Total non-current assets		160,410	135,145
Current assets
Prepaid expenses and deposits		1,417	1,239
Crude oil inventory		1,082	247
Accounts receivable and other credits		8,389	5,948
Cash and cash equivalents		23,863	25,535
Total current assets		34,751	32,969
TOTAL ASSETS		195,161	168,114
EQUITY AND LIABILITIES
Equity
Shareholder's equity		118,089	91,425
Liabilities
Non-current liabilities
Bank debt	8	36,206	44,234
Decommissioning provision	9	2,478	2,264
Deferred tax liabilities		2,317	-
Lease liabilities	10	2,180	2,385
Other long-term liabilities and provisions		694	651
Total non-current liabilities		43,875	49,534
Current liabilities
Bank debt	8	16,500	11,250
Accounts payable		6,205	9,644
Accrued liabilities and provisions		9,328	5,189
Current portion of lease liabilities	10	1,164	1,072
Total current liabilities		33,197	27,155
TOTAL LIABILITIES		77,072	76,689
TOTAL EQUITY AND LIABILITIES		195,161	168,114

Condensed Consolidated Statement of Cash Flows

(TUSD)	Note	Q2 2022	Q2 2021	H1 2022	H1 2021
Operating Activities
Net result		8,219	2,603	20,249	8,141
Depletion, depreciation, and amortization	6	3,122	1,782	7,388	3,692
Stock based compensation	11	178	106	324	106
Accretion of decommissioning provision	5,9	38	35	70	63
Accretion of bond payable		-	199	-	497
Amortization of deferred financing fees	8	477	242	954	242
Interest expense		2,021	1,846	4,011	2,953
Income tax expense		(1,989)	708	(2,194)	1,333
Deferred tax expense		3,347	731	6,841	1,525
Unrealized foreign exchange amounts		127	(266)	(265)	513
Interest received		27	20	107	30
Interest paid		(2,001)	(3,313)	(3,914)	(3,313)
Tax paid		(460)	(702)	(2,338)	(1,226)
Changes in working capital	15	3,108	(1,311)	(314)	(2,182)
Cash from operating activities		16,214	2,680	30,919	12,374
Investing activities Capital expenditures - property, plant, and equipment	6	(13,811)	(10,970)	(24,762)	(21,060)
Capital expenditures - exploration and evaluation assets	7		(464)		(673)
		(2,121)		(2,931)
Cash used in investment activities		(15,932)	(11,434)	(27,693)	(21,733)
Financing activities
Lease payments	10	(342)	(289)	(671)	(622)
Repayment of bonds payable		-	(35,919)	-	(35,919)
Bank debt borrowing	8	-	60,000	-	60,000
Repayment of bank debt	8	(3,750)	-	(3,750)	-
Paid financing fees		-	(6,012)	-	(6,012)
Shares subscription (net of issue costs)	11	-	9,990	-	9,990
Exercise of warrants (net of issue costs)	11	-	9,078	-	9,218
Cash from (used in) financing activities		(4,092)	36,848	(4,421)	36,655
Change in cash and cash equivalents Cash and cash equivalents at the beginning		(3,810)	28,094	(1,195)	27,296
of the period		29,416	5,698	25,535	6,681
Currency exchange differences in cash and
cash equivalents		(1,743)	347	(477)	162
Cash and cash equivalents at the end of the period		23,863	34,139	23,863	34,139

Condensed Consolidated Statement of Changes in Equity

				Retained	Total
		Contributed	Other	(Deficit)	Shareholders'
(TUSD)	Share Capital	Surplus	Reserves	Earnings	Equity
Balance on 1 January 2021	122	66,120	(34,096)	23,410	55,556
Comprehensive result
Result for the period	-	-	-	8,141	8,141
Currency translation difference	-	-	5,503	-	5,503
Total comprehensive result	-	-	5,503	8,141	13,644
Transactions with owners
Stock based compensation	-	106	-	-	106
Share issuance (net of issue costs)	10	9,981	-	-	9,991
Exercise of warrants (net of issue costs)	14	9,205	-	-	9,219
Total transactions with owners	24	19,292	-	-	19,316
Balance on 30 June 2021	146	85,412	(28,593)	31,551	88,516
Comprehensive result
Result for the period	-	-	-	13,446	13,446
Currency translation difference	-	-	(11,417)	-	(11,417)
Total comprehensive result	-	-	(11,417)	13,446	2,029
Transactions with owners
Stock based compensation	-	313	-	-	313
Share issuance (net of issue costs)	-	512	-	-	512
Exercise of warrants (net of issue costs)	-	55	-	-	55
Total transactions with owners	-	880	-	-	880
Balance on 31 December 2021	146	86,292	(40,010)	44,997	91,425
Comprehensive result
Result for the period	-	-	-	20,249	20,249
Currency translation difference	-	-	6,092	-	6,092
Total comprehensive result	-	-	6,092	20,249	26,341
Transactions with owners
Stock based compensation (net of issue costs)	-	323	-	-	323
Balance on 30 June 2022	146	86,615	(33,918)	65,246	118,089

Parent Company Statement of Operations

(Expressed in thousands of Swedish Krona)		Q2 2022	Q2 2021	H1 2022	H1 2021
Revenue		-	-	-	-
Expenses
General and administrative		(2,694)	(2,675)	(4,414)	(5,003)
Foreign currency exchange (loss) gain		5,636	(8,856)	4,989	(2,724)
Operating result		2,942	(11,531)	575	(7,727)
Net finance costs		(14,738)	(10,658)	(26,202)	(13,903)
Result before tax		(11,796)	(22,189)	(25,627)	(21,630)
Income tax		-	-	-	-
Net and comprehensive result for the period		(11,796)	(22,189)	(25,627)	(21,630)
Parent Company Balance Sheet
(Expressed in thousands of Swedish Krona)	Note		30 June 2022		31 December 2021
Assets
Non-current assets
Investment in subsidiaries			11,114		8,003
Loans to subsidiaries			674,142		644,044
			685,256		652,047
Current assets
Accounts receivable and other			133		-
Restricted cash			50		50
Cash and cash equivalents			66,781		88,170
			66,964		88,220
Total Assets			752,220		740,267
Equity and Liabilities
Restricted equity
Share capital			1,316		1,316
Unrestricted equity
Contributed surplus			689,506		686,398
Retained earnings			(489,522)		(463,895)
Total unrestricted equity			199,984		222,503
Total equity			201,300		223,819
Non-current liabilities
Bank debt	8		380,501		412,964
Current liabilities
Accounts payable and accrued liabilities			1,459		1,406
Bank debt	8		168,960		102,078
			170,419		103,484
Total liabilities			550,920		516,448
Total Equity and Liabilities			752,220		740,267

Parent Company Statement of Changes in Equity

Restricted
equity	Unrestricted equity
	Contributed	Retained
			Total Equity
1,117	516,500	(337,434)	180,183
-	-	(21,630)	(21,630)
			893
82	83,883	-	83,965
116	77,361	-	77,477
198	162,137	-	162,335
1,315	678,637	(359,064)	320,888
-	-	(104,831)	(104,831)
			2,734
			4,295
			733
			7,762
1,316	686,398	(463,895)	223,819
			(25,627)
-	3,108	-	3,108
			201,300
	Share capital - - - 1 1 - 1,316	surplus 893 2,734 4,295 732 7,761 - 689,506	Earnings - - - - - (25,627) (489,522)

Notes to the Condensed Consolidated Financial Statements

1. Corporate information

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

The Company has operations in Brazil, Oman 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 in Calgary, Canada. The Company has an office in Rio de Janeiro, Brazil and operations offices in Grayville, IL and Newcastle, WY, USA and Muscat, Oman.

2. Basis of presentation

The unaudited interim condensed consolidated financial statements have been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"), and the Swedish Annual Accounts Act.

The unaudited interim condensed consolidated financial statements are stated in thousands of United States Dollars (TUSD), unless otherwise noted, which is the Company's presentation and functional currency. These unaudited interim consolidated financial statements 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 2021 have been used in the preparation of this report. 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 unaudited interim condensed consolidated financial statements should be read in conjunction with the annual consolidated financial statements for the year ended 31 December 2021.

The financial reporting of the Parent Company (Maha Energy AB) has been prepared in accordance with accounting principles generally accepted in Sweden, applying RFR 2 Reporting for legal entities, issued by the Swedish Financial Reporting Board and the Annual Accounts Act.

Under Swedish company regulations it is not allowed to report the Parent Company results in any other currency than Swedish Krona or Euro and consequently the Parent Company's financial information is reported in Swedish Krona and not the Group's presentation currency of US Dollar.

Changes in Accounting Policies

During the current quarter 2022, the Company did not adopt any new standards and interpretations or amendments thereto applicable for financial periods beginning on or after 1 January 2022.

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. The Company manages its capital structure to support the Company's strategic growth and has positive cash flow from operations.

3. Segment Information

Operating segments are based on a geographic perspective and reported in a manner consistent with the internal reporting provided to the executive management as follows:

• Brazil: Includes all oil and gas activities of exploration and production in Tie field and Tartaruga field.

• United States of America (USA): Includes all oil and gas activities in the Illinois Basin and LAK field.

• Corporate: The Corporate segment aggregates costs incurred at the Company's corporate office in Sweden and the technical and support office in Canada as well as initial costs related to activities in Oman. These operating segments have similar economic characteristics as they do not currently generate revenue.

"Adjustments" segment primarily includes consolidation adjustments and eliminations between segments.

The following tables present the operating result for each segment. Revenue and income relate to external (nonintra group) transactions.

TUSD	Brazil	USA	Corporate	Consolidated
Q2 2022
Revenue	19,965	4,053	-	24,018
Royalties	(1,821)	(981)	-	(2,802)
Production and operating	(2,954)	(854)	-	(3,808)
Depletion, depreciation, and
amortization	(2,436)	(668)	(18)	(3,122)
General and administration	(316)	(96)	(1,199)	(1,611)
Stock-based compensation	-	-	(178)	(178)
Exploration and business
development cost	-	-	(104)	(104)
Foreign currency exchange loss	226	-	(50)	176
Other income	(894)	-	-	(894)
Operating results	11,770	1,454	(1,549)	11,675
Net finance costs	(100)	(7)	(1,991)	(2,098)
Current tax recovery	1,989	-	-	1,989
Deferred tax expense	(3,347)	-	-	(3,347)
Net results	10,312	1,447	(3,540)	8,219

TUSD	Brazil	USA	Corporate	Adjustments	Consolidated
Q2 2021
Revenue	14,179	999	-	-	15,178
Royalties	(1,908)	(245)	-	-	(2,153)
Production and operating	(3,062)	(415)	-	-	(3,477)
Depletion, depreciation, and
amortization	(1,523)	(242)	(17)	-	(1,782)
General and administration	(246)	(27)	(890)	-	(1,163)
Stock-based compensation	-	-	(106)	-	(106)
Exploration and business
development cost	-	-	44	-	44
Foreign currency exchange loss	1	76	2,377	(3,312)	(858)
Other income	665	-	-	-	665
Operating results	8,106	146	1,408	(3,312)	6,348
Net finance costs	(624)	(5)	(1,677)	-	(2,306)
Current tax recovery	(708)	-	-	-	(708)
Deferred tax expense	(731)	-	-	-	(731)
Net results	6,043	141	(269)	(3,312)	2,603

TUSD	Brazil	USA	Corporate	Consolidated
H1 2022
Revenue	47,080	7,769	-	54,849
Royalties	(4,891)	(1,878)	-	(6,769)
Production and operating	(6,394)	(1,750)	-	(8,144)
Depletion, depreciation, and
amortization	(5,984)	(1,369)	(35)	(7,388)
General and administration	(544)	(141)	(2,378)	(3,063)
Stock-based compensation	-	-	(324)	(324)
Exploration and business
development cost	-	-	(104)	(104)
Foreign currency exchange loss	161	-	(61)	100
Other income	245	-	-	245
Operating results	29,673	2,631	(2,902)	29,402
Net finance costs	(584)	(13)	(3,909)	(4,506)
Current tax recovery	2,194	-	-	2,194
Deferred tax expense	(6,841)	-	-	(6,841)
Net results	24,442	2,618	(6,811)	20,249

TUSD	Brazil	USA	Corporate	Adjustments	Consolidated
H1 2021
Revenue	28,819	2,173	-	-	30,992
Royalties	(3,959)	(535)	-	-	(4,494)
Production and operating	(5,160)	(759)	-	-	(5,919)
Depletion, depreciation and
amortization	(3,100)	(560)	(32)	-	(3,692)
General and administration	(405)	(43)	(1,996)	-	(2,444)
Stock-based compensation	-	-	(106)		(106)
Exploration and business
development cost	-	-	(6)	-	(6)
Foreign currency exchange (loss)gain	8	76	249	(1,115)	(782)
Other income	1,178	-	-	-	1,178
Operating results	17,381	352	(1,891)	(1,115)	14,727
Net finance costs	(1,234)	(9)	(2,485)	-	(3,728)
Current tax expense	(1,333)	-	-	-	(1,333)
Deferred tax expense	(1,525)	-	-	-	(1,525)
Net results	13,289	343	(4,376)	(1,115)	8,141

4. Revenue

The Company derives revenue from the transfer of goods at a point in time in the following major commodities from oil and gas production in the geographic regions of Brazil and the USA:

TUSD	Q2 2022	Q2 2021	H1 2022	H1 2021
Brazil
Crude oil	19,750	14,057	46,622	28,589
Natural gas	216	122	458	230
Brazil oil and gas sales	19,966	14,179	47,080	28,819
United States oil sales	4,052	999	7,769	2,173
Total revenue from contracts with customers	24,018	15,178	54,849	30,992

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 at the delivery point agreed with the customer and the customer obtains legal title.

The Company had two main customers during Q2 2022 (Q2 2021: one) and three main customers during H1 2022 (H1 2021: one) that individually accounted for more than 10 percent of the Company's consolidated gross sales. Total sales to these customers for the current quarter were approximately USD \$20.9 million (Q2 2021: USD \$13.0 million) and for H1 2022 approximately USD \$50.5 million (H1 2021: USD \$24.3 million). There were no intercompany sales or purchases of oil and gas during the period.

The Company had no contract asset or liability balances during the period presented. As at 30 June 2022, accounts receivable and other credits included \$3.0 million of sales revenue which related to the current quarter's production.

5. Finance Costs

TUSD	Q2 2022	Q2 2021	H1 2022	H1 2021
Interest on bond payable	-	391	-	1,464
Accretion of bond payable	-	199	-	497
Accretion of decommissioning provision (Note 9)	38	35	70	63
Amortisation of deferred financing fees (Note 8)	477	242	954	242
Interest expense (Note 8)	2,003	1,455	3,993	1,489
Interest income and credits	(420)	(16)	(511)	(27)
	2,098	2,306	4,506	3,728

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

	Oil and gas	Equipment and	Right-of-use
TUSD	properties	Other	assets	Total
Cost
31 December 2020	96,746	2,157	6,018	104,921
Additions	41,161	214	-	41,375
Disposition	-	-	(30)	(30)
Change in decommissioning cost	(360)	-	-	(360)
Currency translation adjustment	(7,000)	(190)	(14)	(7,204)
31 December 2021	130,547	2,181	5,974	138,702
Additions	26,617	274	469	27,360
Change in decommissioning cost	124	-	-	124
Currency translation adjustment	6,738	36	49	6,823
30 June 2022	164,026	2,491	6,492	173,009
Accumulated depletion, depreciation and amortization
31 December 2020	(12,513)	(751)	(612)	(13,876)
DD&A	(7,000)	(142)	(1,267)	(8,409)
Currency translation adjustment	951	19	24	994
31 December 2021	(18,562)	(874)	(1,855)	(21,291)
DD&A	(6,674)	(44)	(688)	(7,406)
Currency translation adjustment	(983)	(30)	15	(998)
30 June 2022	(26,219)	(948)	(2,528)	(29,695)
Carrying amount
31 December 2021	111,985	1,307	4,119	117,411
30 June 2022	137,807	1,543	3,964	143,314

7. Exploration and Evaluation Assets (E&E)

	TUSD
31 December 2020	11,014
Additions in the period	2,646
31 December 2021	13,660
Additions in the period	2,930
30 June 2022	16,590

Additions during the current quarter are mainly related to Oman Block 70.

8. Bank debt

	TUSD	TSEK
Bank debt	60,000	504,276
Currency translation adjustment	-	43,524
Deferred financing costs	(4,516)	(32,758)
31 December 2021	55,484	515,042
Loan repayment	(3,750)	(38,700)
Deferred financing costs	972	9,572
Currency translation adjustment	-	63,547
30 June 2022	52,706	549,461
Less: Current portion	16,500	168,960
Non current	36,206	380,501

On 30 March 2021, the Company entered into a credit agreement for a senior secured term loan of USD 60 million (the "Term Loan"), maturing 31 March 2025. The proceeds were used to redeem the outstanding SEK 300 million bond and to fund the Company's oil and gas production expansion program.

The Term Loan bears interest at a step-rate increasing from 12.75% to 13.5% as nearing maturity time, payable quarterly in arrears and secured by substantially all the assets and shares of Maha Energy and its subsidiaries. The principal amount is to be repaid in quarterly instalments over the four (4) year period, commencing 15 months from the credit agreement date. From the date of the credit agreement and up to disbursement on 23 April 2021 a commitment fee equal to an annual rate of 12.60% was payable. Following disbursement, the Company redeemed the Senior Secured Bond on 5 May 2021 for a total amount of SEK 315.6 million, including accrued interest.

The Term Loan requires the Company to maintain certain covenants including a Net interest-bearing debt to trailing twelve months EBITDA ratio of greater than 3.0 at the end of each quarter. Under the terms of the loan, the Company is subject to certain restrictions in its ability to make certain payments and distributions to persons outside of the Maha Group, as well as other customary provisions applicable for similar credit agreements.

As part of the closing of the financing transaction, Maha also received an equity contribution of USD 10 million through the Private Placement issuance of 7,470,491 new shares to the same bank, at a price of SEK 11.59 per share, representing a 10% discount to the last 15 days volume weighted average share price prior to the closing. This discount amounted to USD \$1.1 million and was proportionately allocated to deferred financing cost and equity issuance cost.

The Company recorded directly attributable transaction costs of USD 5.2 million as deferred financing costs which also includes part of the 10% discount on the Private Placement of Maha shares. Deferred financing costs will be amortized over the life of the Term loan. Other transactions costs of USD 0.5 million incurred as a result of the refinancing activities and which were not directly attributable to the actual financing that took place have been expensed.

9. Decommissioning Provision

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

	TUSD
31 December 2020	2,597
Accretion expense	122
Additions	251
Change in estimate	(611)
Foreign exchange movement	(95)
31 December 2021	2,264
Accretion expense	70
Additions	125
Liability settled	(28)
Foreign exchange movement	47

10. Lease Liability

(TUSD)
31 December 2020	4,693
Additions	-
Interest expense	122
Lease payments	(1,236)
Foreign currency translation	(122)
31 December 2021	3,457
Additions	481
Interest expense	78
Lease payments	(670)
Foreign currency translation	(2)
30 June 2022	3,344
Less current portion	1,164
Lease liability – non current	2,180

11. Share Capital

Shares outstanding	A	B	Total
31 December 2020	101,146,685	483,366	101,630,051
Exercise of bond warrants	10,134,916	-	10,134,916
Exercise of incentive warrants	480,238	-	480,238
Share subscription	7,470,491	-	7,470,791
Conversion of convertible B shares	483,366	(483,366)	-
31 December 2021	119,715,696	-	119,715,696
30 June 2022	119,715,696	-	119,715,696

Warrant Incentive Program

The Company has a long-term incentive program ("LTIP") as part of the remuneration package for management and employees. Following incentive warrants were outstanding at 30 June 2022:

Warrants		Exercise				Expired or
incentive		price,		Issued	Exercised	Cancelled	30 June
programme	Exercise period	SEK	1 Jan 2022	2022	2022	2022	2022
2019	1 September 2022 –
(LTIP-3)	28 February 2023	28.10	500,000	-	-	-	500,000
2020	1 September 2023 –
(LTIP-4)	29 February 2024	10.90	460,000	-	-	-	460,000
2021	1 June 2021 –
(LTIP-5)	28 February 2025	12.40	1,048,286	-	-	-	1,048,286
2021	1 June 2023 –
(LTIP-6)	29 February 2024	12.40	524,143	-	-	-	524,143
2022	1 June 2025 – 28
(LTIP-7)	February 2030	20.65	-	1,197,157	-	-	1,197,157
Total			2,532,429	1,197,157	-	-	3,729,586

Each warrant shall entitle the warrant holder to subscribe for one new Share in the Company at the subscription price per share. The fair value of the warrants granted under the warrant incentive program has been estimated on the grant date using the Black & Scholes model.

Weighted average assumptions and fair value are as follows:

	2022
	incentive
	programme
Risk free interest rate (%)	1.55
Average Expected term (years)	8.0
Expected volatility (%)	55
Forfeiture rate (%)	10.0
Weighted average fair value (SEK)	11.02

Total share-based compensation expense for Q2 2022 was TUSD 178 (Q2 2021: 106) and for H1 2022 was TUSD 324 (H1 2021: 106).

12. 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 bank debt is carried at amortized cost and which approximates the fair value.

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. 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 2021 Annual Report.

14. Management of Capital

The Company manages its capital structure to support the Company's strategic growth. The Company's objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets, ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the ability to meet the Company's financial obligations as they come due. The Company considers its capital structure to include shareholders' equity of USD 118.1 million (31 December 2021: USD 91.4 million) plus net debt of USD 28.8 million (31 December 2021: 29.9 million). At the end of the quarter, the Company's working capital surplus was USD 1.6 million (31 December 2021: USD 5.8 million), which includes USD 23.9 million of cash (31 December 2021: USD 25.5 million). The Company started repaying the term loan during the quarter.

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. 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.

(TUSD)	30 June 2022	30 June 2021
Change in:
Accounts receivable	(2,549)	(2,329)
Inventory	(663)	(294)
Prepaid expenses and deposits	(178)	307
Accounts payable and accrued liabilities	3,076	134
Total	(314)	(2,182)

15. Changes in non-cash Working Capital

16. Pledged Assets

As at 30 June 2022, the Company has pledged assets in relation to the security of the Term Loan whereby the Parent Company has pledged shares of all its subsidiaries and concessions rights and other assets in Brazil with a book value for the Group of USD 75.7 million and MSEK 11.1 for the parent company, including adjustments for the consolidation purposes.

The Company also has financial guarantees in relation to its work commitments in Brazil and has contractual commitments in the USA and Oman (See Note 17).

17. Commitments and Contingencies

The Company has 7 concession agreements with the National Agency of Petroleum, Natural Gas and Biofuels in Brazil ("ANP"). Certain of these blocks are subject to work and abandonment commitments in relation to these exploration blocks which are guaranteed with certain credit instruments. These commitments are in the normal course of the Company's exploration business and the Company plans to fund any related work or penalty, if necessary, with existing cash balances, cash flow from operations and available financing sources.

During the fourth quarter 2021, the Company was granted a full waiver on the related work commitments on Block 224 minimum work and was granted extensions until November 2024 on its minimum work commitments for Blocks 117 and 118. The Company is working towards a waiver application for the minimum work obligations related to these blocks.

In the Illinois Basin, as part of the recent land acquisition the Company has committed to drill at least one well on this new lease during the first three years and then at least one well every year thereafter to retain the lease. For the existing leases, the Company drilled one operated and one non operated commitment wells during Q1 2022. There are no further commitments remaining for the current year. Over the next five years, the Company has commitments to drill during 2023 and 2024 four (4) operated and one (1) net (0.5) non operated well per year and has commitment to drill during 2025 to 2027 to drill three (3) operated and one (1) net (0.5) non operated well per year.

Further, a contingent consideration of USD 3.0 million is possible if certain oil prices and production level milestones are met before 2023. Maha and its subsidiaries are under no obligation to reach the production level set out for the production milestone. The company had not recorded this contingent consideration.

With the acquisition of the Block 70 in Oman, the Company will undertake minimum work obligations during the initial exploration period of three years which include interpretation and reprocessing of 3D seismic and drilling 10 (ten) shallow wells. Costs for these activities are estimated at gross USD 20.0 million (Net to Maha USD 13.0 million).

18. Subsequent Event

Subsequent to the quarter end, the Company entered into a farmout agreement with Mafraq Energy LLC granting this strategic partner a 35% working interest in the onshore oil-bearing Block 70 in Oman in exchange for Mafraq Energy LLC reimbursing Maha for their prorated share of all past costs including the signature bonus. Mafraq Energy LLC will also be required to pay their share of all future expenditures on Block 70. Mafraq Energy LLC brings important technical expertise as well as strategic partnership in Oman for future growth.

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
TUSD	Q2 2022	Q2 2021	H1 2022	H1 2021
Revenue	24,018	15,178	54,849	30,992
Operating netback	17,408	9,548	39,936	20,579
EBITDA	14,621	8,988	36,690	19,201
Net result	8,219	2,603	20,249	8,141
Cash flow from operations	16,214	2,680	30,919	12,374
Free cash Flow	282	(8,754)	3,226	(9,359)
Net debt	28,848	20,483	28,848	20,483
Key ratios
	Q2 2022	Q2 2021	H1 2022	H1 2021
Return on equity (%)	7	3	17	9
Equity ratio (%)	61	52	61	52
NIBD/EBITDA	.44	0.75	.44	0.75
TIBD/EBITDA	.81	1.99	.81	1.99
Data per share
	Q2 2022	Q2 2021	H1 2022	H1 2021
Weighted number of shares (before
dilution)	119,715,696	110,116,842	119,715,696	106,028,049
Weighted number of shares (after
dilution)	120,452,364	110,294,944	120,231,090	106,290,184
Earnings per share before dilution,
USD	0.07	0.02	0.17	0.08
Earnings per share after dilution, USD	0.07	0.02	0.17	0.08
Dividends paid per share	n/a	n/a	n/a	n/a
Relevant reconciliation of Alternative Performance Measures:

Operating Netback
(TUSD)	Q2 2022	Q2 2021	H1 2022	H1 2021
Revenue	24,018	15,178	54,849	30,992
Royalties	(2,802)	(2,153)	(6,769)	(4,494)
Operating Expenses	(3,808)	(3,477)	(8,144)	(5,919)
Operating netback	17,408	9,548	39,936	20,579

EBITDA
(TUSD)	Q2 2022	Q2 2021	H1 2022	H1 2021
Operating results	11,675	6,348	29,402	14,727
Depletion, depreciation and amortization	3,122	1,782	7,388	3,692
Foreign currency exchange loss / (gain)	(176)	858	(100)	782
EBITDA	14,621	8,988	36,690	19,201

Free cash flow
(TUSD)	Q2 2022	Q2 2021	H1 2022	H1 2021
Cash flow from operating activities	16,214	2,680	30,919	12,374
Less: cash used in investing activities	(15,932)	(11,434)	(27,693)	(21,733)
Free cash flow	282	(8,754)	3,226	(9,359)
Net debt
(TUSD)	Q2 2022	Q2 2021	H1 2022	H1 2021
Bank debt	52,706	54,622	52,706	54,622
Less: cash and cash equivalents	(23,863)	(34,139)	(23,863)	(34,139)
Net debt	28,843	20,483	28,843	20,483

Key Ratio Definition

Cash flow from operations: Cash flow from operating activities in accordance with the consolidated statement of cash flow.

EBITDA (Earnings before interest, taxes, depreciation, and amortization and impairment): Operating profit before depletion of oil and gas properties, depreciation of tangible assets, impairment, foreign currency exchange adjustments, interest and taxes.

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.

Equity ratio: Total equity divided by the balance sheet total assets.

Free cash flow: Cash flow from operating activities less cash flow from investing activities in accordance with the consolidated statement of cash flow.

Net debt: Interest bearing debt, excluding leases, less cash and cash equivalents.

Net debt to EBITDA ratio (NIBD/EBITDA): Net interest-bearing debt divided by trailing 4 quarters EBITDA.

Operating netback: Operating netback is defined as revenue less royalties and operating expenses.

Return on equity: Net result divided by ending equity balance

Total debt to EBITDA ratio (TIBD/EBITDA): Total interest-bearing debt divided by trailing 4 quarters EBITDA.

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.

Board Assurance

The Managing Director and the Chairman of the Board certify that the interim report for the period ended 30 June 2022 gives a fair view of the performance of the business, position, and income statements of Maha Energy AB (publ.) and Maha Energy Group and describes the principal risks and uncertainties to which the Company and the Group are exposed.

Approved by the Board

Stockholm, 15 August 2022

_Jonas Lindvall____________________ Jonas Lindvall, Director

_Harald Pousette____________________ Harald Pousette, Chairman

Financial calendar

15 August 2022
14 November 2022
28 February 2023
15 May 2023

Contact information

For further information please contact:

Jonas Lindvall (CEO) Tel: +46 8 611 05 11 Email: jonas@mahaenergy.ca

Andres Modarelli (CFO)

Tel: +46 8 611 05 11 Email: andres@mahaenergy.ca

Victoria Berg (Investor Relations) Tel: +46 8 611 05 11 Email: victoria@mahaenergy.ca

Maha Energy AB Head Office Strandvägen 5A

SE-114 51 Stockholm, Sweden +46 8 611 05 11

Technical Office Suite 240, 23 Sunpark Drive SE Calgary, Alberta T2X 3V1 +1-403-454-7560

Email: info@mahaenergy.ca