Maha Energy AB: Announces Capital Plan in anticipation of Acquisition of Gran Tierra Inc.'s Brazilian Operations
|Maha Energy AB (publ)|
|SE-111 46 Stockholm|
April 18, 2017
This press release is not for release, publication or distribution, directly or indirectly, in or into Australia, Canada, Hong Kong, Japan, New Zealand, Singapore, South Africa, Switzerland or the United States, or in any other jurisdiction where distribution of this press release could be illegal or subject to legal restrictions.
Maha Energy AB Announces Capital Plan in anticipation of Acquisition of Gran Tierra Inc.'s Brazilian Operations
Maha Energy AB (publ) ("Maha" or the "Company") has today released details of the capital plan ("Capital Plan") it would propose to implement in the event it closes the previously announced acquisition of the Brazil business unit of Gran Tierra Energy Inc.
Jonas Lindvall, President and Chief Executive Officer of Maha Energy, commented "2016 was a transformational year for Maha. We secured the Tartaruga Brazilian asset and completed our Initial Public Offering. In 2017 we plan to complete our second high quality Brazil acquisition - Gran Tierra's Brazilian operations which will have obvious synergies with Tartaruga. This new Capital Plan is Maha tooling up to close the acquisition and operate two significant oil fields in Brazil."
Acquisition of Gran Tierra's Brazilian Operations
On February 6, 2017 Maha Energy AB (NASDAQ OMX First North: MAHA A) was pleased to announce that it had entered into an agreement to acquire the Brazil business unit of Gran Tierra Energy Inc. ("Gran Tierra") (NYSE MKT:GTE)(TSX:GTE) through the purchase of all of the shares and outstanding intercompany debt of Gran Tierra Finance (Luxembourg) S.Á.R.L., including assumed liabilities involved with the going-concern operations, for a cash consideration of $35 million, subject to closing adjustments (the "Acquisition"). Upon closing, Maha will own and operate, through a 100%-owned subsidiary, the 100% working interests in six concession agreements located, in the Reconcavo Basin of Brazil comprising 41,606 gross acres with average production expected to be 1,200 - 1,500 boepd in 2017 from the Tie Field. Closing of the Acquisition is subject to receiving the approval of the Acquisition from the Agencia Nacional do Petroleo, Gas Natural e Biocombustiveis of Brazil ("ANP"), completion of a financing by Maha, and other closing conditions standard for similar transactions. The closing of the Acquisition is anticipated to occur in the second half of 2017.
- 10.2 MMboe of 2P Reserves3 associated with the Tie Field, estimated by independent engineers
- Estimated NPV (10%) of 2P reserves: $188 million before tax3
- 91% light oil (38° API)
- 1P reserves of 7.7 MMboe3 represent 75% of 2P Reserves
- Attractive operating netbacks of $22.39 per Boe (2016)7
- Operating expenses of $8.18 per Boe and transportation expenses of $1.65 per Boe (2016)7
- Competitive fiscal regime
- Maha management estimates 2017 average WI production to be 1,200 - 1,500 boepd5
- Upside potential
- 3P working interest Reserves of 14.3 MMboe3,including southern lobe of Tie Field
- 10 prospects totalling gross mean unrisked Prospective Resources of 45 MMboe8
- Operating synergies and administrative savings with existing Brazilian assets of Maha at Tartaruga
Operations in Brazil
As previously announced, Maha became the operator of the Tartaruga field in January 2017. In addition to planning and executing the successful workover of the 107D well, Maha's operations group has been working closely with its Brazilian management team to conduct a top to bottom review of its operations at Tartaruga and the operating environment generally in Brazil.
Maha conducted a detailed technical review of the Tartaruga and the Tie fields which included a recent technical workshop in Denver on April 6, 2017 with all Maha's technical team and advisers. This work was instrumental in creating a comprehensive conceptual development plan for the Tartaruga field. Our senior management team has had recent meetings with our partner in the Tartaruga field, Petrobras, as well numerous commercial meetings with local service providers, other operators, refineries, oil marketers, the ANP, gas-to-wire companies, and gas purchasers. With this level of knowledge, Maha has developed its proposed go-forward Capital Plan for its operations in Wyoming and Brazil in anticipation of its successful completion of the Acquisition. This plan is designed to maximize synergies between the operations at the Tartaruga and the Tie fields.
Upon closing the Acquisition, the Company will have a robust portfolio of reserves that can be developed in pace with increasing oil prices. Maha currently operates (and will operate) all its assets which adds to Maha's flexibility and control over the Capital Plan. The Capital Plan details anticipated capital allocations as between the LAK, Tartaruga, and Tie producing fields based on the current development planning and available cash flow and are based on assumed oil prices of the current Brent Strip for 5 years. If prices are higher, certain elements of the Capital Plan may be accelerated. Likewise, any sustained period of prices below the current strip would result in the Company reallocating and/or decelerating capital expenditures to conserve capital as appropriate. The Company will adjust expenditures and planned capital outlays based on changes in local rules, regulations and market requirements, partner approvals, government approvals of well licenses, well drilling results, availability of funds from cash flow, operational results, and new technical information.
The capital outlays, as modelled, will be funded out of Maha's current working capital, the balance of the proceeds from the equity and debt financings currently being undertaken by the Company (see Press Releases dated February 6, 2017 and February 13, 2017), and anticipated cash flows. The Capital Plan has been allocated between the three projects as follows:
A. The Tartaruga Field
The Tartaruga oil field is situated within the Sergipe sedimentary basin in eastern Brazil. The Company is a 75 percent owner of the Tartaruga oil field with the remaining 25 percent interest held by the state oil company Petrobras. The Tartaruga oil field is located in the northern half of the 13,201 acre (53.4 km2) Tartaruga Block and produces 41° API oil from two deviated wells drilled into the early Cretaceous Penedo Formation. The Tartaruga oilfield has produced in excess of 1.0 million barrels of oil up until December 31, 2016.
Net Penedo reservoir pay has been estimated by an independent Geology and Geophysics consulting group to be in excess of 80 m. Further, the Penedo sandstone consists of 27 separate stacked sandstone reservoirs, all of which have been electrically logged and are indicated to contain oil. To date, only 2 of these 27 stacked reservoirs have been produced (Penedo 1 and Penedo 6). The best estimate of the Oil Originally In Place (OOIP) of the Penedo sandstone is 65.4 million barrels, but has been estimated as high as 200 million barrels of oil in place by reputable consultants.
A deeper, regionally producing sandstone, known as the Serraria, has also been mapped but the reservoir content is uncertain at this time. Should the Serraria contain oil, the OOIP estimates range between 6 to 236 million barrels of OOIP, depending on closure and spill-point of the reservoir.
An adjacent structure to Tartaruga has produced oil from the Morro de Chaves Formation which lies above the Penedo formation. The Morro de Chaves Formation has not been tested in the Tartaruga Field and provides further exploration potential on the field.
As previously announced in February this year, the Company completed a workover that turned an intermittently, low producing, free-flowing well (< 10 bopd) on the block to a steady 250 bopd (gross) producer by recompleting the well with a sub-surface jet pump. Both producing wells in the field are now being powered by a single pump and are currently producing in excess of 400 bopd (gross). Work is underway to optimize the pumping system by de-bottlenecking the surface handling system whereby the well production is expected to increase by an additional 10 - 15%. This work is anticipated to be completed by the end of April. These wells are producing positive cash flow to the Company at the current oil prices.
Work is also underway to further delineate and produce the Penedo sandstone. On April 6, 2017, the Company's technical operations team focused on Tartaruga met with external experts to discuss future well placement and conceptual development plans. The current Capital Plan is to use an existing approved well license on the block to drill a combined delineation and production well later in 2018, the exact timing of which will depend on partner approval and equipment availability.
The Reserve Report of Chapman Petroleum Engineering dated December 31, 2016 (see Press Release date March 3, 2017) assumes a number of near vertical wells to be drilled over the next five years. The Company is evaluating several differing completion techniques which could include horizontal completions, directional dual and multiple completions, high angle multiple selective completions, and wellbore stimulation practices. Based on results from desktop studies and the drilling of the 2018 directional well, the Company will refine its development strategy (which could alter the expected production profile). A total of 4 dually completed and directional wells are currently anticipated to be drilled over the next 5 years (one in 2019 and two in 2020) at a cost of approximately $5.6 million per well including related facility upgrades (net to Maha) in addition to the planned directional well in 2018.
The Tararuga Field consists of two producing wells, a complete hydraulic jet pumping system, storage tanks, loading facilities, a heater treater, separator, flare system, and an office with accommodation buildings. The current production facilities have sufficient capacity for production levels up to 1,600 barrels of fluid per day at which point they are constrained by the heater treater unit.
Oil produced from onshore fields in Brazil is generally sold and marketed to local receiving facilities and refineries. In Sergipe Province, where the Tataruga Field is located, operators are able to sell oil at a current price of Brent less $0.51 per barrel. In Bahia Province, where the Tie Field is located (see below), the price received by operators is lower due to insufficient capacity at local receiving facilities. Historically this discount has been as high as $15.00 per barrel but more recently slightly less than $9.00 per barrel is common. Upon the completion of the Acquisition, as part of the anticipated synergies Maha plans to truck incremental Tie Field production above 1,100 bopd to Aracaju, Sergipe facilities where the expected price is Brent minus $4.00 - 6.00 per barrel. Trucking costs are under $2.00 per bbl for operators within the Bahia and Sergipe area. Trucking crude from Bahia to Sergipe is expected to be about $4.00 per bbl.
Based upon the above Capital Plan, Maha conservatively estimates average annual net production from Tartaruga of 320 bopd in 2017, 440 bopd in 2018, 620 bopd in 2019, 720 bopd in 2020, and 880 bopd in 2021.
B. The Tie Field
The Tiê Field is located in the Block REC-T-155 in the Recôncavo Basin in eastern Brazil. As mentioned above, upon completion of the Acquisition Maha will operate with a 100 percent working interest in the field.
The Tiê Field was discovered in 2009 with the drilling of well 1-ALV-2-BA ("ALV-2") and delineated with wells 3-GTE-3D-BA ("GTE-3") and 3-GTE-4DPA-BA ("GTE-4") in 2011 and 2012. In September 2012, Gran Tierra received declaration of commerciality from the government of Brazil. A three dimensional ("3D") seismic survey was acquired in 2010 and re-processed in 2013. The ALV-2 well produced from the Sergi Formation until it was shut-in in July 2014. This well is planned to be converted to a water injection well during 2017. GTE-3 initially produced solely from the Sergi Formation while GTE-4 produced solely from the Agua Grande Formation until both wells were successfully dual completed in 2014.
Oil is currently trucked 35 kilometres to a Petrobras oil terminal where up to 1,100 bopd is sold. A water injection pressure maintenance project is almost completed. Current management estimates 2017 production will average 1,200 - 1,500 boepd.
The field has two structural highs and the saddle area between these highs is a few metres above the interpreted oil water contact. The southern lobe (high) has been classified as possible reserves as there is good evidence it could be a separate accumulation.
As of December 31, 2016, the reserves estimates are publicly available and were prepared by McDaniel Associates as follows:
|Reserve Category (Oil)|| Tiê Field |
| Tiê Field |
| Tiê Field |
| Tiê Field |
|Proved Developed Producing||2 366||2 047||1 686||1 458|
|Proved Undeveloped||4 631||4 006||2 460||2 128|
|Total Proved "1P"||6 997||6 053||4 146||3 586|
|Probable (Producing and Undeveloped)||2 262||1 956||1 317||1 139|
|Total Proved plus Probable "2P"||9 259||8 009||5 463||4 725|
|Possible (Producing and Undeveloped)||3 763||3 255||2 224||1 923|
|Total Proved plus Probable plus Possible "3P"||13 022||11 264||7 687||6 648|
Production from the existing wells drilled on the Tie structure has been curtailed for two reasons: (a) there has been no outlet for excess associated natural gas, and (b) receiving facilities were constrained in receiving tank volumes to a maximum of 1,100 bopd. The current operator recently completed its gas commercialization project whereby excess associated gas is now compressed and sold in the local market.
Work by Maha is now underway to secure additional product sales volumes by trucking the produced crude oil to other receiving terminals. As indicated above (see Tartaruga Field), Maha has developed a plan with another purchaser that has expressed interest in purchasing the incremental Tie volumes that may be trucked from Bahia to Sergipe. It is expected that the trucking of incremental production will commence during the first half of 2018.
With work underway to increase export capacity, the Capital Plan is to complete the water injection program this year, install artificial lift systems on the two existing wells by 2018, and drill an additional production well by 2020. Additional work will include the upgrade of the production facility, currently capable of handling production up to 2,000 bopd, to handle more than 3,000 bopd and associated fluids. Details of the proposed capital to attain the 3,000 bopd target is anticipated to be $2.6 million for the remainder of 2017 (assuming the Acquisition closes on August 31, 2017), $18.1 million in 2018, and $13.9 million in 2019.
According to the McDaniels Associates Reserves Report, production volumes are expected to increase from an average of 1,100 bopd in 2017 to 1,350 bopd in 2018, 2,500 bopd in 2019, 3,000 bopd in 2020, and 3,000 bopd in 2021.
C. The LAK Ranch Project
The LAK Ranch heavy oil field is situated on the eastern edge of the prolific Powder River Basin in Wyoming, USA. The Company is the 99 percent owner and operator of the LAK Ranch heavy oil field. The remaining 1 percent interest in the LAK Ranch Field is entitled to 1 percent of revenues after paying production taxes without obligation to pay capital or operating costs and is therefore accounted for as a royalty holder. The LAK Ranch property has 6,475 gross acres and produces 19° API oil from six deviated wells located in the northern section of the license area. Maha (Canada) acquired the asset in 2013 and has since embarked on a very detailed production optimization appraisal program of the field. Independent reservoir engineering appraiser RPS Energy completed a static reservoir model using Petrel software that calculated the best estimated Original Oil In Place (OOIP9) to be 62 million barrels at the end of 2014. The Petrel static reservoir model that uses accepted industry parameters was based on fifteen existing representative wellbores to estimate the oil initially in place. Parameters used in defining the OOIP rely on direct measurements from petrophysical information as well as core data which in turn provide evidence as to the rock's porosity, oil saturation, and permeability. The static geo-model is based on the latest acquired 3D seismic to define the areal extent of the reservoir. As a result of the work completed in 2014, further production optimization work continued in 2015 culminating in a revised development plan based upon historical field production results. Because of the viscous nature of the 19° API oil, the addition of heat in the form of heated water is modelled to generate a 21 percent recovery factor. The recovery factor is estimated using the CMG STARS reservoir simulation software which predicts fluid movements through the Petrel static geomodel. The Recovery Factor is defined as the percentage of producible oil compared to the oil originally in place. Factors influencing the Recovery Factor include reservoir and fluid characteristics (porosity, permeability, pressure, viscosity, temperature, and saturations). The LAK Ranch heavy oil field is currently producing a stable 33 bopd from 6 wells, driven by a pilot hot water flood that is shaping up to be a reliable enhanced oil recovery (EOR) method for further development.
As at December 31, 2016, the LAK Ranch asset is considered to be in the pre-production stage and is currently undergoing delineation and pre-development work. As such, operating costs net of revenues since the commencement of operations have been capitalized as part of exploration and evaluation costs.
The LAK Field was shut in from April 2016 until August 2016, primarily due to low oil prices and the requirement for reservoir pressure maintenance. During the shut-in period, the Company completed a capital investment to allow for produced water recycling, which is critical for handling of produced water and re-injection of water for pressure maintenance. The project was completed in August and production from a limited number of wells was re-established by the end of August 2016.
Technical work completed during 2015 and 2016 has laid the groundwork for the full field development plan. The full field development plan contemplates hot water injection, rather than steam playing a more significant role than originally anticipated. The extra cost of hot water injector wells is more than offset by the elimination of steam requirements.
Production results have indicated near wellbore damage and in March 2017 the Company completed a clean-out program of three producing wells with varying results. Significant fine migration sand was flushed out of one well, whilst a second well had its production successfully restored to pre-wellbore damage levels and the third well saw no improvement. Simultaneous to the clean-out operations, the hot water injection scheme referred to above was providing encouraging results to allow for a wider expansion of the hot water flood pattern. The current hot water flood pattern involves more than doubling the number of injection wells and it is expected that injection efficiency will aid in increasing production volumes at LAK Ranch. Once the current hot water flood pattern is completed and injection has stabilized, there are no further wells to convert and therefore additional drilling is required to increase production. Until results of the current expanded hot water flood are fully analyzed, the LAK Field will continue to be considered in the 'pre-production' stage and costs will be capitalized. Further development of the field is therefore dependent on results from the hot water flood.
The capital plan for LAK Ranch assumes a positive result from the current expanded hot water flood and contemplates the drilling of 6 additional vertical injectors and horizontal producers starting in 2018. Thereafter, additional injection and production patterns will be drilled annually with 9 wells being drilled in 2019 and 2020. 10 wells will be drilled in 2021 and production facilities will be expanded at a cost of $1.0 million to handle the additional production. Because the LAK reservoir is very shallow in depth, each well is expected to cost $550,000 to drill, complete, and hook up. Further, and because of low decline rates expected with the water flood, average annual production volumes are expected to grow from 250 bopd in 2018 to 870 bopd in 2019, 1,100 bopd in 2020, and over 1,200 bopd in 2021.
It is the current strategy of the Company to bring LAK Ranch up to a break-even economic position as soon as possible and thereafter grow production from LAK Ranch through a capital program funded by the LAK property cash flow, reserve-based lending, or through corporate capital allocations.
FNCA Sweden AB is the Company's Certified Adviser.
For more information, please contact:
Jonas Lindvall (CEO)
Tel: +1 403 454 7560
Ron Panchuk (COO)
Tel: +1 403 454 7560
This information is published in accordance with the EU Market Abuse Regulation and/or the Swedish Financial Instruments Trading Act. The information was submitted for publication through the agency of the contact persons set out above on April 18, 2017, at 5:31 p.m. CET.
Maha in Brief
Maha Energy AB is a Swedish public limited liability company. FNCA Sweden AB has been engaged as Certified Adviser. The Company's auditors are Deloitte. The Company's predecessor Maha Energy Inc was founded in 2013 in Calgary, Canada, by Jonas Lindvall and Ron Panchuk. In May 2016, the new group was formed with Maha Energy AB as parent company for purposes completing an initial public offering on the Nasdaq First North Sweden stock exchange. Jonas Lindvall, CEO and Managing Director, has 26 years of international experience in the oil and gas industry, starting his career with Lundin Oil during the early days of E&P growth. After 6 years at Shell and Talisman, Jonas joined, and helped secure the success of, Tethys Oil AB. Maha's strategy is to target and develop underperforming hydrocarbon assets on global basis. The Company operates two oil fields, Tartaruga in Brazil and LAK Ranch, in Wyoming, U.S. For more information, please visit our website www.mahaenergy.ca.
This press release does not contain or constitute an invitation or an offer to acquire, subscribe for or otherwise trade in shares, subscription rights or other securities in Maha Energy AB (publ). Any invitation to the persons concerned to subscribe for shares in Maha Energy AB (publ) will only be made through the prospectus that Maha Energy AB (publ) intends to publish. Publication or distribution, directly or indirectly, of this press release could in some jurisdictions be subject to restrictions according to law and recipients of this press release, or part of it, are required to inform themselves of, and comply with, such legal restrictions. This press release is not for release, publication or distribution, directly or indirectly, in or into Australia, Canada, Hong Kong, Japan, New Zealand, Singapore, South Africa, Switzerland or the United States, or in any other jurisdiction where distribution of this press release could be illegal or subject to legal restrictions. Copies of this press release are not being made and may not be distributed or sent, in whole, or part, directly or indirectly, in violation of such restrictions. Failure to comply with such restrictions may constitute a criminal act under the United States Securities Act of 1933 (as amended) ("Securities Act") or applicable laws in other jurisdictions.
 Normal course debt owed to affiliate of vendor is being acquired
 All dollar amounts are in United States dollars unless otherwise indicated
 The Brazilian operations of Gran Tierra currently comprise seven concession agreements. One concession is in the process of being relinquished which is expected to be completed before the closing date
 Gran Tierra estimate from Press Release dated December 19, 2016
 Based on Gran Tierra June 2016 investor presentation
7 United States Securities And Exchange Commission Washington, D.C. 20549
FORM 10-K dated March 1, 2017
8 Maha Management estimates
9 Original oil in place is an estimate of the total volume of oil originally in the reservoir measured in barrels. The estimated OOIP is calculated by making assumptions about the rock porosity, quantity of reservoir rock, water saturation among many other variables