Sure Energy Announces Year End 2012 Financial and Operating Results

CALGARY, ALBERTA–(Marketwire – March 13, 2013) – Sure Energy Inc. (TSX”SHR) (“Sure Energy” or the “Company”) is pleased to announce results for the year ended December 31, 2012.

The Company’s MD&A, Financial Statements and Notes, and AIF can be viewed or downloaded at www.sureenergyinc.com or www.sedar.com.

During 2012, Sure Energy accomplished the following:

• Increased oil & liquids production from 50 percent of total production in 2011 to 59 percent in 2012
• Funds Flow from Operations in 2012 was $11.74 million ($0.19/share)
• At Hatton, commenced development of heavy oil project with two successful development wells and one water disposal well, commenced 20 square kilometre 3D seismic program and increased 100 percent working interest land base to 12,640 acres.
• Operational initiatives reduced corporate operating costs from $14.26/BOE in the fourth quarter of 2011 to $13.04/BOE in the fourth quarter of 2012.
• Sold lands in Virginia Hills with Beaverhill Lake rights for $9.0 million

RESERVES

The following presentation should be read in conjunction with reserves information contained in Sure Energy’s Annual Information Form (“AIF”) which has been released concurrently. The AIF presents the Company’s reserves according to Canadian Securities Administrators National Instrument 51-101 (“NI 51-101”) along with the related Forms and per the NI 51-101 Companion Policy.

Sure Energy engaged independent petroleum consultants Sproule Associates Limited (“Sproule”) to evaluate reserves for all of Sure Energy’s properties effective December 31, 2012. The Sproule report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101 by Qualified Reserve Evaluators. Sproule has reviewed and consented to the information contained herein.

All evaluations and future net cash flows are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures and abandonment costs for wells to which reserves have been assigned. Values of future net revenues do not represent the fair market value of the reserves.

Reserves and future net revenue have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability to Sure Energy of funding required for that development.

Reserve Life Index

The reserve life index is calculated by dividing gross company reserves as at the effective date of the reports (December 31, 2012) by Sproule’s estimate of average production for the following year. The reserve life index represents a measure of the amount of time production could be sustained at the assumed production rates based on the reserves at the applicable point in time.

Reconciliation

For the year ended December 31, 2012, proved reserves were 3,698.5 MBOE a decrease of 238.6 MBOE, or 6% from prior year end. Sure Energy’s proved plus probable reserves were 4,999.4 MBOE, down 925.3 MBOE or 16%. The disposition of Sure Energy’s Virginia Hills Beaverhill Lake properties resulted in a decrease of reserves attributable to the property of 212.4 MBOE Proved and 913.0 Mbbl Proved plus Probable. Proved plus Probable reserve additions (after revisions) were equivalent to 116 percent of production for the year, despite drilling 10 gross wells at Redwater which had Proved Undeveloped reserves.

UNDEVELOPED LAND

For the year ended December 31, 2012 Sure Energy’s total non-reserve landholdings were 79,294 net acres as determined by Seaton-Jordan & Associates Ltd. The majority of Sure Energy’s undeveloped land is located in the Plains area of Alberta. The Company’s land acquisition strategy focuses primarily on acquiring lands to expand existing project areas and prospect inventory.

NET ASSET VALUE

The following table represents the net asset value (“NAV”) of Sure Energy as at December 31, 2012 based on proved and probable reserves using forecast pricing as evaluated by Sproule, undeveloped land value as determined by Seaton Jordan & Associates Ltd., seismic value as determined by internal estimates, and internal estimates of value for tax pools.

OPERATIONAL REVIEW

Capital expenditures for the period were as follows:

Drilling activity for the quarter and year is summarized as follows:

Three Months Ended December 31, 2012

Year Ended December 31, 2012

Areas of Activity

Plains (Redwater)

Sure Energy produced 445 BOE/d (89 percent liquids) from its main core area at Redwater in 2012. The Company drilled 11 gross (6.8 net) wells in the area in 2012, all of which were single leg horizontal wells which were fracture stimulated multiple times along their length. The producing zone in the area is the Viking formation which is at approximately 700 metres. The Viking is a regionally extensive oil bearing shoreline sequence in the Redwater area. It produces poorly when drilled vertically but exhibits attractive production rates and economics when drilled horizontally and fracture stimulated. More than 400 horizontal wells have been drilled into the fairway in the past four years. Sure Energy began drilling in the area in the Fall of 2010 and has drilled 24 (17.2 net) wells to date. The Company realized $54.41/BOE netback from the area in 2012, generating $8.9 million net operating income for the year. The high quality 36° API oil produced in the area sells at an Edmonton Mixed Sweet Blend price. The property realized an oil price of $83.57/Bbl for the year which combined with a gas price of $2.60 Mcf netted the Company $76.46/BOE. Operating costs were steady at $14 to $15/BOE ($4/BOE of which is emulsion trucking costs from single well batteries to third party treating facilities).

Sure Energy owns 15,885 net acres of land on the fairway with an average working interest of 91 percent. This equates to 26 net sections of land, less than 25 percent of which (6 net sections) is currently developed. The Company’s reserves engineers recognize 33 gross (24.0 net) proven undeveloped drilling locations (a combination of single leg multi-frac horizontals and multi-leg open hole horizontals) adjacent or proximal to current producing wells. An internal engineering study of the 400 wells on the trend indicates that single leg open-hole fracture stimulated wells (“packers plus” style) will ultimately recover the most oil per horizontal metre. By drilling solely this type of well the Company’s low risk drilling inventory would increase to 69 (58.0 net) single leg horizontal locations. This type of well costs approximately $1.4 million to put on stream.

Hatton (SW Saskatchewan)

Sure Energy produced 68 BOE/d of heavy oil from its Hatton property in 2012 and 125 BOE/d in the fourth quarter. The increased production in the fourth quarter reflects the production optimization of the discovery well which came on production in November 2011 and the start up of a new well drilled in September 2012.

Hatton is a lower Mannville heavy oil pool (12.9° API) in a linear sand bar. The bar is transected by numerous shale filled channels that create traps and subsequent oil pools. Sure Energy is currently exploiting one such pool. The discovery well commenced production in November 2011 at 75 bbls/d. The well produces at a 65 to 80 percent watercut which is typical of analogous heavy oil pools to the north. The well produced approximately 18,100 barrels in its first year of production. A second well was drilled in late summer 2012 and commenced production in mid September. This well has averaged 75 bbls/d to date and has produced approximately 12,500 barrels of oil. It currently has an 80 percent watercut. The Company drilled two additional wells in the fourth quarter of 2012. One well is being converted to a water disposal well as currently the trucking and disposal of the produced water costs in excess of $10/Bbl of oil produced. The second well was drilled into the thickest part of the reservoir and encountered 13 meters of reservoir with no discernible oil/water contact. The well was perforated in two separate intervals. The lower of the perforated intervals tested at a pumping rate of 58 bbls/d with a 78 percent average watercut, for the last 54 hours of an 87 hour production test. The upper interval flowed at an average rate of 90 bbls/d with a 70 percent watercut the last 68 hours of a 98 hour production test. There was no significant production or pressure decline during the test periods. The upper interval also tested gas which declined steadily throughout the test, from 867 Mcf/d to 174 Mcf/d. The well is currently awaiting tie-in to conserve the gas, and dispose of the water. This is preliminary test data and is not necessarily indicative of the long-term performance or ultimate recovery of the zones tested.

The Company receives an oil price at Hatton which is about $3 less than the Western Canadian Select index pricing. In 2012 the price received was C$69.51/Bbl. There are minimal additional costs for diluents or blending. In 2012 the Company received an operating netback in the area of $33.47 per barrel and generated operating cashflow of $0.9 million from an average of 68 bbls/d. A single vertical producer costs approximately $0.9 million to put on stream. Operating costs averaged $21.57/BOE in 2012, much of which was due to trucking and disposal of salt water. The Company believes these costs can be reduced to $7 to $9/Bbl when water disposal is initiated at the battery site; this will significantly impact operating netbacks.

Early in 2013 the Company completed a 20.0 square kilometer 3D seismic program at Hatton. From the 3D interpretation the Company has identified 13 development locations (based on one well per legal subdivision) and 3 potential satellite pools on its 100 percent lands. Sure Energy owns 19.75 sections on the sand bar fairway, of which only 4.5 sections were covered by the 3D seismic. The geological model and comparison to analogous pools suggests there is a strong possibility of additional pools on the unevaluated lands.

SE Saskatchewan

Sure Energy produced 146 BOE/d from Queensdale in the fourth quarter of 2012 and averaged 128 BOE/d for the year. One horizontal well and one water disposal well were drilled by the Company in this area in 2012. This is a mature fully developed project with water disposal and gas tie-in at the battery site. In 2012 the Company realized a $54.31/BOE operating netback at the property and generated $2.5 million of net operating income.

The Company has proprietary 3D seismic that covers the current pool and Sure Energy’s additional 100 percent lands. The Company has identified the potential for a pool of similar size to the existing pool using the 3D and adjacent well data. This prospect can be evaluated by a single vertical exploration well which would cost approximately $0.5 million.

Virginia Hills

The Company produced 185 BOE/d at Virginia Hills in 2012. During the year Sure Energy disposed of its Beaverhill Lake assets in the area for $9 million. The Company established a position in the area in early 2011 to evaluate the potential of the regional Viking which is analogous to and on depositional strike with the Company’s Redwater assets. The regional Viking at Virginia Hills is oil bearing but has never been exploited horizontally. At 1,500 meters depth the horizontal wells will cost approximately $2.5 to $2.8 million. The Company owns 9.5 sections of approximately 50 percent working interest land and three sections of 100 percent land in the core area of the play.

Other Properties

The Company produced 408 BOE/d in 2012 from its properties in the Peace River Arch, Southern Plains (Chinook), Tweedie and West Central Alberta. Most of this production is gas.

Production

Production for the period by major property is as follows:

The Company averaged 1,201 BOE/d of sales in the fourth quarter of 2012. The Company experienced 7.5 percent of unscheduled downtime in the quarter so the quarterly production number is approximately 100 BOE/d below total capability. Hatton was 12 BOE/d below its production allowable due to the two producing wells being shut-in for safety reasons during the drilling and testing of an additional well drilled from the production pad. Queensdale was 14 BOE/d below capability because of mechanical issues that affected the largest producing well in late November and December. The properties on the Peace River Arch were approximately 35 BOE/d below capability because of high line pressures in the main gas sales lines in late November and all of December. Tweedie was 13 BOE/d below capacity because of a suspected hole in the tubing of the highest volume producing well, which caused it to be shut-in from mid November to the present. Virginia Hills was down 20 BOE/d because of compressor failure issues at a third party gas facility on two occasions in the quarter.

The Company averaged 1,234 BOE/d for 2012 (59 percent oil and liquids). On a BOE basis this is essentially flat to 2011 but this represents a 20% increase in oil and liquids from 2011, reflecting the continuing focus of the Company to switch from a predominantly gas producing Company to an oil and liquids producer. The 41 percent gas production generated 11.5 percent of the total revenue although this improved to 15.6 percent in the fourth quarter when gas prices showed modest improvement.

OUTLOOK

The Company will utilize a cashflow driven capital budget for 2013. The Board of Directors has approved an interim capital budget of $5 million for the first half of the year. At the May 2013 Board meeting the Company will have a better idea of the impact of production levels, commodity prices and differentials on its cashflows. The Company has approximately $30 million of unutilized credit facilities.

The Company will focus its first quarter capital program at Hatton where it intends to upgrade the battery to include a free water knock-out treater and a water disposal well. The latest well will also be tied in to the facility and the gas from the facility will be tied into the local gathering system. These upgrades are expected to significantly reduce operating costs, thereby increasing operating netbacks. Although it is tempting to accelerate production volumes at Hatton the Company does not intend to sell extra volumes in the first quarter at low prices due to over expanded differentials and high operating costs. The Company anticipates that operating costs will improve to approximately $8/bbl from $17.35/bbl experienced in the fourth quarter of 2012 at Hatton, and heavy oil differentials have already started to rebound from historic lows in January and February. Once the facilities are upgraded the Company plans to commence a five well drilling program (likely after break-up) consisting of four development wells and one step-out exploration well. These wells will all be drilled into the thickest part of the reservoir and two will be drilled from existing pads. The cost of a vertical well tied-in to the central facility is approximately $875,000 but the Company anticipates that by drilling a program these costs could be reduced by a further 10 percent. This type of program coupled with significant reserves per well and the low decline rates observed in the wells to date will allow the Company to show both production and reserves growth with accompanying cashflow growth while restricting capital spending to cashflow. This growth will not be apparent in the first half of 2013 because of the focus on building facilities but should be apparent from mid year on. The Company has an inventory of 13 development wells on the current pool at Hatton and has identified three potential satellite pools.

The Company has an extensive inventory of low risk horizontal drilling locations at Redwater but management believes that it is not good business to drill a well or two in the first quarter to meet production targets because services are always more expensive in the first quarter and wells are cheaper when drilled in multi-well programs. The Company will determine how many wells to drill at Redwater at its May Board meeting when cashflows are more certain. In order to protect some of its cashflow the Company has hedged 200 barrels of oil per day at around $98 Cdn for the remainder of 2013.

The Company has $60 million of credit facilities available to it, a $40 million revolving line with National Bank and a $20 million note term facility with Deans Knight. These facilities are both approximately 50 percent utilized. The Deans Knight facility matures in January 2014 but is renewable at the Company’s option at an increased interest rate for an additional eleven months.

The Company would like to sincerely thank W. Peter Comber, who resigned from the Board of Directors for personal reasons, for his efforts and advice from the inception of the Company. The Company would also like to welcome Dan Kolibar onto the Board of Directors.

The Company has a low risk inventory of 71 development locations and a minimum of 8 exploration locations in its core areas. It is therefore able to allocate capital to adding production and cashflow or to adding new reserves. The Company calculates its Proved plus Probable Net Asset Value (10%) per share to be $1.12 and its Proved Net Asset Value (10%) per share to be $0.71 so it is currently trading at a significant discount in the market.

ADVISORIES

Forward-looking Information

Certain statements contained in this release constitute forward-looking information. These statements relate to future events or Sure Energy’s future performance. The use of any of the words “could”, “expect”, “believe”, “will”, “projected”, “estimated” and similar expressions and statements relating to matters that are not historical facts are intended to identify forward-looking information and are based on Sure Energy’s current belief or assumptions as to the outcome and timing of such future events. Actual future results may differ materially. In particular, Sure Energy’s belief that it can reduce operating costs at its Hatton property; its belief that additional oil pools exist on the unevaluated lands at Hatton; the Company’s identification of the potential for an oil pool of a similar size to its existing pool at Queensdale; the approximate cost to drill wells at Redwater, Hatton and Virginia Hills and statements under “Outlook” pertaining to the 2013 budget and development intentions, expected operating costs and growth expectations at Hatton, contain forward looking information. Sure Energy’s Annual Information Form and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com) describe the risks, material assumptions and other factors that could influence actual results and which are incorporated herein by reference. Sure disclaims any intention or obligation to publicly update or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as may be expressly required by applicable securities laws.

Use of BOEs

In this press release the calculation of barrels of oil equivalent (BOE) is calculated at a conversion rate of 6,000 cubic feet (Mcf) of natural gas for one barrel (bbl) of oil based on an energy equivalency conversion method. BOEs may be misleading particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 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.
For further information, please visit our website at www.sureenergyinc.com.

Sure Energy Inc.
Mr. Jeff Boyce
Chairman and CEO
(403) 410-3100

Sure Energy Inc.
Mr. Chris Baker
President and COO
(403) 410-3100

Sure Energy Inc.
Mr. Lance Wirth
Vice President, Finance and CFO
(403) 410-3111
(403) 410-3100
info@sureenergyinc.com
www.sureenergyinc.com