CALGARY, ALBERTA–(Marketwired – Feb. 3, 2015) – Manitok Energy Inc. (the “Corporation” or “Manitok“) (TSX VENTURE:MEI) is providing an operations and corporate update.
Manitok concluded 2014 by successfully completing the drilling and production test of two Cardium light oil wells. The two wells are 103/13-21-42-15W5 (33% working interest) and 13-11-42-15W5 (30% working interest). This completes a 15 well (6.8 net) drilling program in Cordel-Stolberg for 2014. The 13-11-42-15W5 well which targeted the backlimb of the Cardium structure tested at 333 bbls/d (100 bbls/d net) and 150 mcf/d (45 mcf/d net) over 1.9 days for a combined rate of 358 boe/d (108 boe/d net). The well produces 44° API oil and was tied-in and placed on production on December 23, 2014.
The 103/13-21-42-15W5 well which targeted the forelimb of the Cardium structure tested at 109 bbls/d (36 bbls/d net) and 99 mcf/d (33 mcf/d net) over 2.1 days for a combined rate of 126 boe/d (41 boe/d net). The well produces 52° API oil and was tied-in and placed on production on December 9, 2014.
Manitok also tied-in the 5-14-42-15W5 well (30% working interest) on December 23, 2014, which was drilled and completed during the first week of November 2014. This well tested at 337 boe/d (101 boe/d net) comprised of 313 bbls/d (94 bbls/d net) of 41° API oil and 142 mcf/d (43 mcf/d net) of natural gas over a 12 hour period.
Optimization of the recently added production is anticipated to continue during the first quarter of 2015.
2014 Entice Drilling Program
During 2014, Manitok successfully drilled 14 wells with a 100% working interest, (4 vertical and 10 horizontal) in the Entice area, fulfilling its 2014 capital commitment to PrairieSky Royalty Ltd. Manitok spent approximately $34.1 million on drilling and completions in Entice in 2014 exceeding the 2014 capital commitment by about $12.1 million. The $12.1 million will be carried forward and applied to the 2015 capital commitment of $33.0 million, resulting in a net 2015 drilling commitment of approximately $20.9 million.
Manitok targeted horizontal drilling locations with multi-stage fracturing completions. Manitok successfully drilled, completed and tested four horizontal wells in the Lithic Glauconitic (“Glauc“) formation and five horizontal wells in the Basal Quartz (“BQ“) formation. The tenth well was completed and tested in January 2015. Test results from five of the nine wells drilled, completed and tested in 2014 were previously press released and tested at an aggregate rate of 977 bbls/d of oil and 8.6 Mmcf/d of natural gas for a combined rate of about 2,400 boe/d. The five remaining wells drilled, completed and tested in 2014 are the 14-33-22-25W4, 6-28-22-25W4, 2-9-23-25W4 5-21-25-24W4, and 14-20-25-24W4 wells.
Carseland (South Entice)
The 14-33-22-25W4 well targeted the middle BQ. It offsets the 3-28-22-25W4 middle BQ well which tested at 135 bbls/d of oil and 420 mcf/d of natural gas for a total rate of 205 boe/d as previously press released. The 14-33 well flowed for 3.2 days and averaged 152 bbls/d of 28° API oil and 3.2 Mmcf/d natural gas to total 688 boe/d. As a result of the success of 14-33-22-25W4 and 3-28-22-25W4 middle BQ wells, Manitok has identified an additional 20 middle BQ drilling locations using well control and its seismic interpretation.
The 6-28-22-25W4 Lithic Glauc well was drilled and completed in December 2014. The well was completed with a 15 stage fracture stimulation and swab tested for 3.8 days. The average oil rate was 15 bbls/day of 39.6° API oil and the reservoir quality was poor throughout the wellbore.
During December 2014 Manitok successfully drilled the 2-9-23-25W4 middle BQ well, which offsets the successful 3-9-23-25W5 lower BQ well (tested at 177 bbls/d of oil and 1.14 Mmcf/d natural gas for a combined rate of 367 boe/d). During a 7.8 day production test in January 2015, the 2-9-23-25W4 well averaged 19 bbls/d of 32° API oil and 1.0 Mmcf/d of natural gas for a combined rate of 181 boe/d.
Strathmore (Central Entice)
The 5-21-25-24W4 well targeted the Glauc formation. The well was drilled and completed with a 15 stage fracture stimulation in November 2014. Due to a mechanical problem encountered during the completion, only 5 stages (about 300 metres of reservoir intersection in the wellbore) of the 15 stage fracture stimulation (1,030 metres of reservoir intersection) are contributing to the well’s current production. During a 2.25 day production test, the well averaged 78 bbls/d of 32° API oil and 74 mcf/d natural gas for a combined rate of 90 boe/d with contribution from only 33% of the intersected reservoir within the wellbore, or 5 of the 15 fracture stages contributing to the test. This is consistent with management’s expectations for a commercial Glauc reservoir. This is the second Glauc pool that Manitok has successfully discovered and tested, while the first was discovered over the summer of 2014 at Carseland.
The 14-20-25-24W4 well targeted the upper BQ and is located in the Strathmore field. While drilling the horizontal section, the wellbore began sloughing when it encountered unconsolidated sand. This resulted in only about 125 metres of productive zone in the wellbore. The well was completed with a 5 stage fracture stimulation and swab tested for 2.4 days. The well averaged 28 bbls/d of 26.5° API oil and 101 mcf/d natural gas for a combined rate of 45 boe/d. Considering the typical horizontal well will encounter 600 to 1,000 additional metres of reservoir, or five to eight times greater wellbore exposure to the reservoir, the result is encouraging in regards to the potential production capability of a more typical horizontal well in this reservoir. Based on seismic interpretation and well control, Manitok has identified four additional upper BQ drilling locations in this pool.
The 5-21-25-24W4 well provides further technical support for the potential productivity of the Glauc formation over the Corporation’s large Entice block. With further analysis of its 3D seismic, using the new data from recent drilling, Manitok has been refining its seismic interpretation over its prospective Glauc pools discovered in Carseland and Strathmore, as well as other Glauc pools identified in the Beiseker area (Northern Entice). The Corporation’s work to date has identified 20 Glauc locations in Carseland offsetting the two successful Glauc wells drilled in mid-2014, which tested over 1,500 boe/d (600 bbls/d of oil) combined, an additional six Glauc locations in the Strathmore pool, and potentially two to three new pool tests in the Beiseker area.
The 2014 Entice drilling program was successful in proving the concept that the large oil in place, tight sand reservoirs of the lower Mannville formation are capable of commercial production. Of the 10 horizontal wells, seven wells were successful with test rates that support the potential for commercial production, two wells were hampered with mechanical issues or reservoir sloughing, but were able to establish potential production from those reservoirs and one well was unsuccessful. Manitok discovered five new lower Mannville pools (two Glauc and three BQ) capable of commercial production. Based on Manitok’s seismic interpretation, geological mapping, historic well control, and drilling results to date, the Corporation’s potential horizontal drilling inventory has increased to 26 Glauc locations in two pools and 40 BQ locations in three pools. Manitok has also identified four to five possible new pools (two to three lithic Glauc and two BQ), using the Corporation’s newly refined seismic information and well control, that it will test over 2015 and 2016.
Facility work at the Cordel-Stolberg area is complete. All wells drilled in 2014 were tied-in and placed on production by December 23, 2014.
In Entice, within the Carseland area, Manitok constructed a battery with 2,000 bbls/d of fluid capacity which can be expanded to 5,000 bbls/d with a minimal amount of capital and satellite system centering on section 32-22-25W4. Oil will be treated at the battery and trucked to nearby sales points. The associated natural gas at the battery was tied into a third party processing facility in late December 2014. One satellite has been tied into the main battery. A second satellite is awaiting final pipeline approval and is anticipated to be tied-in shortly after such approval is received. The battery is located on the same lease as its two most prolific wells 15-32-22-25W4 and 16-32-22-25W4. The two wells have been on production since late December 2014 producing at rates up to 1,100 boe/d (410 bbls/d of light oil) while being severely restricted using downhole chokes. The two wells have averaged about 600 boe/d (240 bbls/d light oil and condensate) during January 2015, which is well below their productive capability, due to a liquids processing issue at the third party gas plant. As production volumes were increased, the high liquids levels in the associated gas (about 20 bbls/Mmcf of condensate alone) from the two wells overwhelmed the third party’s facility, which was designed for about 5 bbls/Mmcf of condensate. Both the operator of the third party gas plant and Manitok are working on a solution to handle the significant level of condensate produced by the two wells. Manitok is reviewing several alternatives to extract a greater amount of the condensate at the Corporation’s main battery while working with the third party operator to increase their liquids handling capability at the gas plant. The third party operator has been very cooperative in discussing solutions and Manitok anticipates the implementation of these solutions later in the first quarter of 2015.
The satellite that is tied-in includes two BQ wells and one Glauc well, which tested at a combined total of 900 boe/d (302 bbls/d oil). Manitok will bring these wells on production in early February 2015 and move production up to the level that the third party facilities can handle. Manitok anticipates that the associated gas from the BQ oil will have less condensate and therefore may produce greater volumes before the same condensate issues arise. Manitok anticipates being able to produce between 500 boe/d (185 bbls/d oil) and 750 boe/d (275 bbls/d oil) while the liquids handling issue is being resolved. Once resolved, the third party gas plant has about 7 Mmcf/d (1,162 boe/d of gas only) of capacity which will allow Manitok to produce the five wells from the two leases at or near their initial capabilities. Once production naturally declines, the second satellite is anticipated to be tied-in and the remaining two BQ wells, with combined test rates of about 545 boe/d (196 bbls/d of oil), to be brought on production in the second quarter of 2015.
Based on field estimates, December 2014 production averaged 4,235 boe/d (56% oil) and production averaged 4,610 boe/d in the first three weeks of January 2015 hitting a peak weekly rate of 4,855 boe/d (54% oil) before being notified in mid-January 2015 of a TransCanada Pipeline restriction of 250 boe/d of natural gas in the Stolberg area, due to total system volume reductions associated with required repairs on its system. TransCanada Pipeline has advised Manitok that the restriction could be in place for up to three months. The 4,855 boe/d weekly production rate was achieved with a contribution of only 580 boe/d (215 bbls/d oil) from the two Glauc wells at Entice severely restricted as a result of the high condensate content in the natural gas and the remaining Entice wells awaiting tie-in. Manitok is working diligently to maximize Entice production levels given the short term restrictions. Manitok anticipates resolving the issue with a longer term solution late in the first quarter of 2015.
Facilities Agreement and Debt
On December 30, 2014, Manitok entered into a facilities agreement (the “Facilities Agreement“) with an arm’s length third party under which Manitok received $15.0 million, before transaction costs, in exchange for beneficial ownership in oil batteries and associated facilities in both the Stolberg and Entice areas. Pursuant to the Facilities Agreement, Manitok has been contracted by the arm’s length third party to operate the facilities over an eight year term and will continue to process its oil at the facilities over the same term. Under the terms of the Facilities Agreement, Manitok will pay an annual facility fee of approximately $2.2 million, which equates to an additional operating cost of about $1.30/boe based on current production volumes. The arm’s length third party has granted Manitok an option to acquire the facilities during, and at the end of the eight year term.
The net proceeds from the transaction under the Facilities Agreement were used to reduce Manitok’s short term net debt to about $77.5 million on December 31, 2014. In connection with Manitok entering into the Facilities Agreement, Manitok’s bank reviewed its credit facility with Manitok and left it unchanged at $105.0 million. The next scheduled review is in May 2015.
The majority of the anticipated capital required for the battery facility and pipeline tie-in to the third party gas plant in Entice were incurred in the fourth quarter of 2014. Manitok utilized its credit facilities to drill a sufficient number of horizontal wells at Entice in advance of spring break-up 2015 in order to maximize its production and funds from operations in the first two quarters of 2015, and to better evaluate the production from both the Glauc and BQ formations at the southern end of Manitok’s Entice area.
Due to the current low commodity price environment, Manitok will not drill any wells in Entice or Stolberg during the first half of 2015. Manitok anticipates about $3.0 to $4.0 million of capital expenditures in the first half of 2015 that would include completions and facilities capital required on wells already drilled. Approximately 75% to 80% of cash flow will be applied towards debt reduction in the first half of 2015. Manitok will evaluate its production and the level of commodity prices in the second quarter of 2015 before planning and executing the bulk of its 2015 capital expenditure program in the second half of the year.
As a result of the oil price hedging in place for all of 2015, and the mitigating impact of a lower Canadian dollar on realized oil and natural gas prices, Manitok is well insulated to the volatility of commodity prices in late 2014 and 2015. Manitok had 1,800 bbls/d of oil hedged in the fourth quarter of 2014 at CDN$97.48 WTI that represents about 100% of fourth quarter oil production net of royalties. Manitok has 1,500 bbls/d of oil hedged for the remainder of 2015 at CDN$93.67 WTI oil, which represents about 80% of anticipated 2015 oil production net of royalties. The oil price hedges in place for 2014 and 2015 have mitigated a large portion of the recent oil price weakness in the fourth quarter and anticipated weakness in 2015. The level of hedging combined with the anticipated added production from Manitok’s successful drilling results over the last two quarters, will allow Manitok to execute its plan to reduce its debt over the first half of 2015 with relatively low risk while waiting on production results to determine the level of capital spending in the second half of 2015.
Manitok is a public oil and gas exploration and development company focusing on conventional oil and gas reservoirs in the Canadian foothills and southeast Alberta. The Corporation will utilize its experience to develop the untapped conventional oil and liquids-rich natural gas pools in both the foothills and southeast Alberta areas of the Western Canadian Sedimentary Basin.
For further information view our website at www.manitokenergy.com.
This press release contains forward-looking statements. More particularly, this press release contains statements concerning the Corporation’s planned strategy in terms of hedging, expected production volumes, planned capital expenditures and source(s) of funding, the intention to drill and complete future wells, planned exploration and development activities, the development and growth potential of Manitok’s properties, the timing of certain wells being placed on production and optimization of recent wells placed on production, the timing of tie-in of certain satellite(s) to a third party processing facility, the anticipated reduction of Manitok’s debt over the first half of 2015, the timing of incurring certain anticipated capital required for Manitok’s battery facility and the anticipated timing of reaching an alternative solution(s) in order to extract greater amount of condensate at the Corporation’s main battery and the timing of finishing the Corporation’s work with a third party operator to increase its liquids handling capability at its gas plant.
While the Corporation anticipates remaining disciplined with its 2015 capital program, readers are cautioned that the Corporation may make adjustments to its 2015 capital program, depending on business conditions and commodity prices throughout the fiscal year. Actual spending may vary due to a variety of factors, including changes to certain key expectations and assumptions set out below.
The forward-looking statements in this press release are based on certain key expectations and assumptions made by Manitok, including expectations and assumptions concerning the success of future drilling and development activities, the performance of existing wells, the performance of new wells, the successful application of technology, prevailing weather conditions, commodity prices, royalty regimes and exchange rates and the availability of capital, labour and services.
Although Manitok believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Manitok can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserves estimates; the uncertainty of estimates and projections relating to production, costs and expenses; and health, safety and environmental risks), uncertainty as to the availability of labour and services, commodity price and exchange rate fluctuations, unexpected adverse weather conditions, general business, economic, competitive, political and social uncertainties, capital market conditions and market prices for securities and changes to existing laws and regulations. Certain of these risks are set out in more detail in Manitok’s current Annual Information Form, which is available on Manitok’s SEDAR profile at www.sedar.com.
Forward-looking statements are based on estimates and opinions of management of Manitok at the time the statements are presented. Manitok may, as considered necessary in the circumstances, update or revise such forward-looking statements, whether as a result of new information, future events or otherwise, but Manitok undertakes no obligation to update or revise any forward-looking statements, except as required by applicable securities laws.
Test Results and Initial Production Rates
Any references in this press release to initial and/or final raw test or production rates and/or “flush” production rates are useful in confirming the presence of hydrocarbons, however, such rates are not necessarily determinative of the rates at which such wells will commence production and decline thereafter. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Corporation. The initial production rate may be estimated based on other third party estimates or limited data available at this time. In all cases in this press release, initial production or test are not necessarily indicative of long-term performance of the relevant well or fields or of ultimate recovery of hydrocarbons.
Non-GAAP Financial Measures
This press release contains references to measures used in the oil and natural gas industry such as “funds from operations” and “net debt”. These measures do not have standardized meanings prescribed by GAAP and therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures are used they should be given careful consideration by the reader. These measures have been described and presented in this press release in order to provide shareholders and potential investors with additional information regarding the Corporation’s liquidity and its ability to generate funds to finance its operations.
Funds from operations should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with GAAP, as an indicator of Manitok’s performance or liquidity. Funds from operations is used by Manitok to evaluate operating results and Manitok’s ability to generate cash flow to fund capital expenditures and repay indebtedness. Funds from operations denotes cash flow from operating activities as it appears on the Corporation’s Statement of Cash Flows before decommissioning expenditures and changes in non-cash operating working capital. Funds from operations is also derived from net income (loss) plus non-cash items including deferred income tax expense, depletion and depreciation expense, exploration and evaluation expense, impairment expense, stock-based compensation expense, accretion expense, unrealized gains or losses on financial instruments and gains or losses on asset divestitures. Net debt includes current assets less current liabilities excluding the current portion of the fair value of financial instruments and the deferred premium on financial instruments.
Barrels of Oil Equivalent
The term barrels of oil equivalent (“boe“) may be misleading, particularly if used in isolation. Per boe amounts have been calculated using a conversion ratio of six thousand cubic feet (6 mcf) of natural gas to one barrel (1 bbl) of crude oil. The boe conversion ratio of 6 mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.
Manitok Energy Inc.
Massimo M. Geremia
President & Chief Executive Officer