Surge Energy Inc. - Excellent Drilling Efficiencies; Current Production Exceeds 2016 Exit Rate; Bank Line Confirmed

CALGARY, July 21, 2016 /CNW/ - Surge Energy Inc. ("Surge" or the "Company") (TSX: SGY) announces excellent development drilling results in each of the Company's three core areas at Shaunavon, Valhalla, and Eyehill (Sparky).  This 14 well drilling program has added production of more than 2,000 boepd (85 percent oil; IP/180 day), at an "all-in" on-stream cost1 of $19.75 million - providing a production efficiency of less than $9,875 per flowing boepd.

Spring 2016 weather conditions in Surge's three operating areas were extremely dry. Accordingly, Surge was able to initiate the Company's second half 2016 drilling program approximately six weeks early – beginning in mid-May.

As a result of these accelerated drilling results, together with continued successful waterflood results at Shaunavon, Eyehill, Nipisi, Silver and Doe, Surge's current production has now exceeded the Company's previously announced 2016 production exit rate target of 13,000 boepd.

OPERATIONAL UPDATE – EXCELLENT DRILLING RESULTS IN ALL CORE AREAS

Shaunavon

At Shaunavon, Surge drilled eight consecutive wells driving the cost of drilling, completing, and tying-in a well down to an average of less than $1.25 million – which is down 43 percent from the cost of $2.2 million per well 20 months ago. The final two wells of the program were successfully drilled utilizing a monobore configuration, realizing a further capital reduction of approximately $100,000 per well.

Sustainable primary production added from this eight well program is more than 1,200 bopd (IP/180 day). Operating costs at Shaunavon are now below $7.75 per barrel, and this high quality, operated, sandstone reservoir has netbacks2 of over $30 per barrel at July strip crude oil pricing. Primary recovery from this drilling program is estimated to be 1.2 million barrels of oil3, providing an "all-in" finding cost4 of $8.33 per barrel.

The Company's Upper Shaunavon waterflood project is delivering excellent, measurable results. The current 200 meter in-fill well, which offsets a recent injector, has shown stabilized production significantly above the primary production type curve5, at more than 100 bopd after 10 months. On this basis, Surge will be immediately converting two additional wells to injection in the waterflooded area, increasing total injection to four wells (two initial pilot wells were converted in September of 2015). The Company now anticipates booking up to 300,000 barrels of oil for wells receiving waterflood support in this large, 54 (net) section oil pool.

Surge has over 200 Upper Shaunavon drilling locations in inventory. Type-curve wells for this 250 million barrel, internally-generated, original oil in place ("OOIP") pool generate a 74 percent risked rate of return (for primary production only) at July strip oil prices.6

The Upper Shaunavon formation on Surge lands has a cumulative recovery factor of less than one percent to date, and is currently booked at less than a four percent recovery factor in Surge's year-end 2015 external engineering report. Similar Upper Shaunavon waterflood analogues immediately offsetting Surge's land at Rapdan and Dollard, which have shown recoveries of 22 percent and 56 percent, respectively7. Surge expects to ultimately realize a recovery factor of more than 20 percent at Shaunavon based on risked development drilling and waterflood activities.

Valhalla

As previously disclosed, at Valhalla, Surge has completed the Company's strategic infrastructure project, tying in approximately 12 MMcfd of Surge's associated gas to nearby sweet gas processing plants. Compression added this spring has now significantly dropped pressures in the field, and processing fees have dropped from $1.25 per Mcf to $0.45 per Mcf. Run times for the Valhalla field are now close to 100 percent (compared with historical run times of 80-85 percent).

On May 25, 2016 Surge brought onstream the Company's latest development well at Valhalla which is performing at Surge's type curve of 550 boepd (IP/180 day). The all-in on-stream cost of the latest well was $3.6 million, and Surge anticipates recovering over 450,000 boe8 for this high quality, light oil well. Valhalla netbacks are approximately $25 per boe at July strip prices.

Type curve wells at Valhalla generate over 150 percent risked rate of return at strip pricing.6 Based on the large 140 million barrels of net OOIP, combined with excellent reservoir pressure data from the 30 meter thick Doig sandstone reservoir, Surge now sees over 50 drilling locations at Valhalla, up from management's previous estimate of 37 locations.

The re-determination of the applicable Crown royalty pursuant to the recent Alberta royalty review is expected to increase Surge's net present value for each un-drilled Valhalla well by more than 20 percent, effective January 1st, 20179.

Sparky; Eyehill

At Surge's Sparky core area, the Company is presently drilling five consecutive wells at Eyehill to add more than 500 boepd of risked production (IP/180 day), at an "all-in" on-stream cost of less than $5.8 million (i.e. $1.15 million per well). Surge anticipates recovering 140,000 boe10 for each Eyehill development well. Eyehill netbacks are over $23 per boe utilizing July strip pricing. These wells are being drilled as monobores, which will result in further operational improvements and capital reductions. Internally generated Eyehill type curve wells generate a risked rate of return of 43 percent at strip crude oil pricing11  (for primary production).

The Eyehill waterflood project is also delivering excellent, measurable results with two recent producing oil wells (offsetting Surge's latest injector) now stabilizing at approximately 100 boepd after nine months.

This high quality, operated reservoir has over 90 million barrels of OOIP net to Surge. Cumulative recovery factors to date at Eyehill are less than one percent, and Surge has currently booked less than four percent of the Sparky OOIP in the Company's year-end 2015 external engineering report. Surge expects to ultimately realize a recovery factor of over 20 percent at Eyehill based on risked development drilling and waterflood activities.

Surge has over 150 low risk, development drilling locations in the Company's greater Sparky core area.

Through two recent Crown purchases in the Sparky area, Surge has acquired nine contiguous sections of 100 percent working interest land (with prior vertical Sparky well control) prospective for Sparky production. The acquired lands have an estimated OOIP of more than 65 million barrels. Surge will be drilling this exciting new Sparky reservoir (utilizing modern horizontal and completion technology) in 2017.

Current Production Exceeds 2016 Exit Rate

As a result of Surge's excellent development drilling results discussed above, together with continued successful waterflood results at Shaunavon, Eyehill, Nipisi, Silver, and Doe, Surge's current production has now exceeded the Company's previously announced 2016 production exit rate target of 13,000 boepd.  This spot rate reflects a portion of flush production, but only partial contribution from the recent 14 well drilling program. 

Management now believe the Company is well positioned to exceed Surge's 13,000 boepd exit rate target for 2016. 

BANK LINE REDETERMINATION

Surge has completed its semi-annual borrowing base review with the Company's syndicated group of lenders. As expected, the Company's borrowing base has now been renewed at $250 million. The revolving period on Surge's entire credit facility expires on May 29, 2017, and the Company's bank line has no non-conforming portion. 

Based on preliminary estimated net debt at June 30, 2016 of less than $135 million, Surge is approximately 54 percent drawn on the renewed credit facility, providing the Company with sufficient liquidity and financial flexibility to execute on its business plan.

As a result of carrying less unutilized credit capability on the Company's bank line, Surge will be saving approximately $1.0 million per year in standby charges.

OUTLOOK – POSITIONING FOR SOLID PER SHARE GROWTH

For more than 85 weeks during the downturn in world crude oil prices, Surge management has strategically positioned the Company for the inevitable turnaround in oil prices.

During this period, Surge created over $750 million of liquidity for its shareholders - without issuing a single common share from treasury. Importantly, this has preserved the Company's ability to grow its reserves, production, and cash flow, on a per share basis, as crude oil prices recover. The strategic capital allocation decisions undertaken by management have also preserved Surge's conservative, independently engineered net asset value of $4.79 per share for shareholders.

Furthermore, rigorous cost cutting initiatives at Surge (opex, G&A and interest expense) have created over $8 per boe of additional netback for the Company.

Operationally, over the last 21 months, management have highgraded Surge's asset base into three, operated core areas, with a deep inventory of low risk, development drilling locations. These locations generate excellent rates of return at strip crude oil prices, and have very low cost production efficiencies. Accordingly, today Surge has a 12-14 year, 750 well development drilling inventory in the Company's large OOIP, waterflooded, light and medium gravity crude oil pools. 

In addition, during the downturn Surge further delineated the Company's high quality, large OOIP crude oil reservoirs at Shaunavon, Valhalla, and Eyehill with excellent development drilling results. Successful waterfloods were also initiated and optimized at Shaunavon, Eyehill, Nipisi, Silver, Wainwright, and Doe. Infrastructure solutions were identified and implemented at Valhalla, Eyehill, Provost, Nipisi, and Wainwright.

Consequently, as a result of management's strategic capital allocation decisions, rigorous cost cutting initiatives, and operational successes, Surge is now 100 percent sustainable at US$47.75 WTI crude oil prices, based on management's $55 million 2016 capital expenditure program. This price is less than forward strip prices for crude oil.

Surge management have also preserved significant per share growth potential for shareholders. This ensures that the Company will be one of the few in its peer group who will be able to add a substantial production per share growth component back into management's business model – as crude oil prices sustainably firm up above US$50 WTI per barrel.

FINANCIAL STATEMENTS AND ACCOMPANYING MDA:

Surge has filed with Canadian securities regulatory authorities its financial statements and accompanying MD&A for the three months ended March 31st, 2016. These filings are available for review at www.sedar.com or www.surgeenergy.ca.

FORWARD LOOKING STATEMENTS:

This press release contains forward-looking statements.  The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe" and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements.

More particularly, this press release contains statements concerning: (i) Surge's drilling and development plans and enhance recovery projects and the timing and results to be expected thereof; (ii) estimated sizes, characteristics, efficiencies, rates of return, netbacks, pool recovery factors and risk levels of plays and the number of associated drilling locations, as applicable; (iii) management's expectations with respect to the Company's waterflood program, results therefrom and quantity of producing assets that will be placed under waterflood; (iv) expectations with respect to the Company's ability to operate and succeed in the current commodity price environment; (v) the Company's declared focus and primary goals; (vi) the availability of Surge's bank line to fund provide the Company with sufficient liquidity and financial flexibility; (vii) management's estimates and expectations regarding production efficiencies, drilling upside, operating costs, capital expenditures and reductions; growth opportunities, reserves, recovery factors, rates of return; net present value of the Company's assets and sustainability; (viii) the impact of cost savings initiatives; (ix) drilling inventories and locations; * production and production  per share growth; (xii) management's expectations regarding net debt levels; (xii) anticipated commodity prices.

The forward-looking statements are based on certain key expectations and assumptions made by Surge, including expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expenses, cash flow and capital expenditures, the application of regulatory and royalty regimes, prevailing commodity prices and economic conditions, development and completion activities, the performance of new wells, the successful implementation of waterflood programs, the availability of and performance of facilities and pipelines, the geological characteristics of Surge's properties, the successful application of drilling, completion and seismic technology, the determination of decommissioning liabilities, prevailing weather conditions, exchange rates, licensing requirements, the impact of completed facilities on operating costs and the availability, costs of capital, labour and services, and the creditworthiness of industry partners on the Company's bank line.

Although Surge 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 Surge 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 reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and constraint in the availability of services, adverse weather or break-up conditions, uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures or failure to obtain the continued support of the lenders under Surge's bank line. Certain of these risks are set out in more detail in Surge's Annual Information Form dated March 16, 2016 and in Surge's MD&A for the period ended March 31, 2016, both of which have been filed on SEDAR and can be accessed at www.sedar.com.

The forward-looking statements contained in this press release are made as of the date hereof and Surge undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Reserves Data

Boe means barrel of oil equivalent on the basis of 1 boe to 6,000 cubic feet of natural gas. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe for 6,000 cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boe/d and boepd means barrel of oil equivalent per day. Original Oil in Place (OOIP) is the equivalent to Discovered Petroleum Initially In Place (DPIIP) for the purposes of this press release.  DPIIP is defined as quantity of hydrocarbons that are estimated to be in place within a known accumulation. There is no certainty that it will be commercially viable to produce any portion of the resources. A recovery project cannot be defined for this volume of DPIIP at this time, and as such it cannot be further sub-categorized. IP180 means rate at which a well produces during its first 180 days of production.  Bbl means barrel of oil. Mbbl means thousand barrels.  Bbl/d means barrels of oil per day.  NGLs means natural gas liquids.

Financial Outlooks

The estimate of June 30, 2016 net debt contained in this press release is a financial outlook within the meaning of applicable securities laws. This financial outlook has been prepared by management of Surge to provide an outlook of Surge's anticipated net debt as at June 30, 2016 based on management's expectations and assumptions as to a number of factors, including but not limited to commodity pricing, production, operating expenses and royalties. Readers are cautioned that this information may not be appropriate for any other purpose. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such results will be achieved. The actual results of Surge will likely vary from the amounts set forth in the financial outlook and such variation may be material. Surge and its management believe that the financial outlook has been prepared on a reasonable basis, reflecting the best estimates and judgments, and represent, to the best of management's knowledge and opinion, Surge's expected expenditures and results of operations. However, because this information is highly subjective and subject to numerous risks, including the risks discussed under the note regarding Forward Looking Statements, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, Surge undertakes no obligation to update this information.

Drilling Locations

This press release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations, which are sometimes collectively referred to as "booked locations", are derived from the Company's most recent independent reserves evaluation as of December 31, 2015 and account for drilling locations that have associated proved or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Of the more than 700 net drilling locations identified herein 527 are unbooked locations. Unbooked locations have specifically been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves data on prospective acreage and geologic formations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors. Type curve economics were calculated using strip oil forecast as of July 4, 2016 strip price forecast (first year WTI: US$51.24/Bbl; Henry Hub: US$3.17/MMbtu; a 1.5 percent per year inflation rate was applied from end of strip forecast (2024) to 2064. An inflating CAD/USD exchange rate of $0.78 (to a max of $0.90 by 2055) was assumed.

Non-IFRS Measures

This press release contains the terms "net asset value", "net debt" and "netback", which do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable with the calculation of similar measures by other companies. Management uses funds generated by operations to analyze operating performance and leverage. Management believes "net debt" is a useful supplemental measure of the total amount of current and long-term debt of the Company. Mark-to-market risk management contracts are excluded from the net debt calculation. Management believes "netbacks" are a useful supplemental measures of the amount of revenues received after royalties and operating and transportation costs and secondly, the amount of revenues received after the royalties, operating, transportation costs, general and administrative costs, financial charges and asset retirement obligations. Additional information relating to these non-IFRS measures can be found in the Company's most recent management's discussion and analysis MD&A, which may be accessed through the SEDAR website (www.sedar.com).

Neither the TSX nor its Regulation Services Provider (as that term is defined in the policies of the TSX) accepts responsibility for the adequacy or accuracy of this release.

_______________________
1 On-stream cost is defined as drilling, completion, equipping and tie-in costs ("DCET").
2 Netbacks are defined as revenue, less royalties, operating, and transportation expenses.
3 Based on internally generated Estimated Ultimate Recoveries ("EUR").
4 Finding cost is defined as DCET capital, divided by internally generated EUR.
5 Type curve is defined as internally generated estimates of well performance, based on analogue well datasets. 
6 July 4, 2016 strip price forecast (first year WTI: US$51.24/Bbl; Henry Hub: US$3.17/MMbtu; a 1.5 percent per year inflation rate was applied from end of strip forecast (2024) to 2064. An inflating CAD/USD exchange rate of $0.78 (to a max of $0.90 by 2055) was assumed.
7 Based on publically available estimates of OOIP and cumulative recovery to date. 
8 Based on internally generated Estimated Ultimate Recoveries ("EUR").
9 Using the strip pricing in footnote 6, generated using the most recent publically available estimates of the Alberta Modern Royalty Framework and applied to internally generated type curves.
10 Based on internally generated Estimated Ultimate Recoveries ("EUR").
11 July 4, 2016 strip price forecast (first year WTI: US$51.24/Bbl; Henry Hub: US$3.17/MMbtu; a 1.5 percent per year inflation rate was applied from end of strip forecast (2024) to 2064. An inflating CAD/USD exchange rate of $0.78 (to a max of $0.90 by 2055) was assumed.

 

SOURCE Surge Energy Inc.



For further information: Paul Colborne, President & CEO, Surge Energy Inc., Phone: (403) 930-1507, Fax: (403) 930-1011, Email: pcolborne@surgeenergy.com; Paul Ferguson, CFO, Surge Energy Inc., Phone: (403) 930-1021, Fax: (403) 930-1011, Email: pferguson@surgeenergy.ca


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890