CALGARY, March 6, 2012 /CNW Telbec/ - Exall Energy Corporation ("Exall" or the "Company") (TSX: EE) is pleased to announce the results of its independent third party NI 51-101 compliant reserves assessment and the test production flow rates on a second successful 3D seismic well drilled in its Marten Mountain, Mitsue operating area. Additionally, Exall is pleased to provide a first quarter 2012 operational update. Exall's public filings can all be found at www.exall.com or www.sedar.com.
Highlights:
Effective March 1, 2012, Exall shut in the 12-31 well as it had over produced its allowable production limits during the New Oil Well Production Period ("NOWPP"). On February 29, 2012 the 12-31 well was producing an average of 307 BOEPD (221 BOEPD net) giving Exall a February 29, 2012 current production of 1,425 BOEPD. The over production from this well will be retired by April 1, 2012.
Low reservoir pressure in the eastern extent of the South Marten Mountain waterflood project resulted in reduced production from four wells. An application was submitted for an amended waterflood scheme which included the addition of three producing wells to the scheme and conversion of one well to water injection. Exall has received approval by the ERCB for the amended waterflood scheme and is currently drilling the water source well for the scheme. Water injection in the eastern extent of the South Marten Mountain waterflood project will commence immediately after the water source well is tied in. Once pressure has been re-established, production from the three wells included in the amended application is expected to net Exall approximately 377 BOEPD in the June 2012 timeframe.
Exall expects to have completed the tie-in operations by mid-March 2012.
Production Strategy
Exall's production strategy is to produce all new wells at a rate approximating their productive capacity during the NOWPP, which will usually result in the well over producing its allowable as prescribed by the ERCB. As such, each new well will see an initial period of high productivity, significantly enhancing Exall's production, followed by a period where the well is shut in. During the shut in time frame, Exall will, should the facts warrant, apply for additional waterflood approvals which will require water injection wells. Exall may convert existing producing wells into water injection wells if the result were to be an overall increase to, and or a long term stabilization of production.
Exall's average test rate over the 13 productive wells drilled and brought on production in the area to date is 79 m3 per day (496 bbls per day). However, Exall's production profile is determined by the ERBC rules effective in the Mitsue Alberta area. A vertical oil well in the area has a maximum primary allowable production rate of 10 m3 per day (63 bbls per day). This primary allowable is adjusted for horizontal wells by a formula based on the length of the horizontal leg. Exall's horizontal multipliers to date have averaged 1.7, resulting in an average Gilwood well primary allowable production rate of 17 m3 per day (107 bbls per day). During the NOWPP, the ERCB allows a company to produce at a rate 2 times the primary allowable calculated. In Exall's case, this NOWPP rate averages 34 m3 per day (214 bbls per day). However, during the NOWPP the ERCB does allow a company to over produce the allowable under the stipulation that the well is shut in after the NOWPP, or first 7,949 m3 (49,991 bbls), until the over production is retired at the primary allowable rate.
While producing the wells in this fashion currently does not provide a smooth production curve, nor does it necessarily provide perceived quarter over quarter production growth, Exall's production strategy does result in a 79% increase in the wells cash flow during the NOWPP, usually paying out the wells during this 4 month (or 49,991 Bbls) period. By maximizing production and, by extension, cash flow during the NOWPP, Exall is able to recycle its capital approximately 25% more effectively.
Finally, it should be noted that, no matter how it is produced, a well testing 79 m3 per day (496 bbls per day) with a 1.7 multiplier, cannot produce more than 18 m3 per day on average (115 bbls per day) during its first year. Only after a waterflood scheme has been approved, can the well produce at a rate approximating its productive capacity. Exall's production strategy does, however, maximize both production and cash flow during the NOWPP.
3D Seismic Gilwood "A" Well Test
The second and third Gilwood A Sand wells drilled on an interpreted channel-type anomaly identified on the 2011 3D seismic program are undergoing completion operations. The second well swab tested 356 BOEPD (net 260 BOEPD) of 40° API sweet oil with a small amount of solution gas over an 18 hour production test. The testing was terminated to allow the drilling rig to spud a fourth seismic test well. The service rig has been moved to start the completion of the third Gilwood seismic well.
These wells are located on a portion of the 196,040 gross acres (78,416 gross hectares) and 142,943 net acres (27,177 net hectares) of undeveloped land the Company holds in the Greater Mitsue area.
Drilling Activities
To date during the first quarter of 2012, Exall has drilled 2.0 gross wells (1.47 net wells), and completed the drilling of 2.0 gross (1.32 net wells) wells spud in December, 2011. Of the four wells rig released during the first quarter of 2012, one has been completed and producing and three are in various stages of completion.
Two wells (1.45 net) have been spud and are currently drilling ahead. One well will be a water source well for the amended South Water Flood; the other well is the fourth well on the seismically defined channel.
3D Seismic Activities
During the fourth quarter of 2011, Exall permitted a 244 square kilometer (86 section) 3D Seismic program to be shot during winter months only. The program was officially kicked off mid-December 2011. Currently, it is anticipated that 51 of the 86 sections of the 3D Seismic Program will be shot before spring break-up 2012, with the remaining 35 sections to be completed in 2013.
The full 2012 - 2013 3D Seismic Program is approximately 12 times the size of the 3D Seismic Program shot in the winter of 2011. The 2011 3D Seismic Program yielded 10 locations of which the first well drilled into a seismic anomaly yielded a 5 day test rate of 777 BOEPD. A second lower quality channel anomaly was tested in Q1 with a well that discovered a thin, non-reservoir quality B sand.
It is anticipated that the 2012 - 2013 3D Seismic Program could yield a substantially larger drilling inventory over the lands acquired by Exall during the third quarter of 2011. Processing and interpretation of the 2012 3D Seismic Program should be complete by June 2012.
Pipeline Activities
As at March 06, 2012 Exall has completed the laying of the pipeline to the 3-25 pad site from which the 10-24 3D Seismic Test well yielding a 5 day test rate of 777 BOEPD was drilled. Remaining to be completed is the riser and the satellite at the pad site, expected to be completed by the 12th of March.
2012 Reserve Report
Exall retained AJM / Deloitte Petroleum Consultants ("AJM") to conduct an independent evaluation of Exall's oil and gas reserves effective February 29, 2012, which was provided to Exall in an Evaluation Report dated February 29, 2012 (herein referred to as the "AJM Evaluation"). The oil and gas reserves and income projections were estimated by AJM in accordance with the Canadian Oil and Gas Handbook ("COGEH") and National Instrument 51-101 ("NI 51-101").
Summary of Reserve Value - Forecast Pricing
The following tables, extracted from the AJM Evaluation, summarize the Corporation's total reserves and net present values of future net reserves based on forecast pricing and costs as at December 31, 2011. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the Company's properties. There is no assurance that such price and cost assumptions will be attained and variances, both positive and negative, could be material.
| Company Gross Reserves(1) |
Light & medium oil |
Natural gas |
NGL | Total | ||||
| as at February 29, 2012 | (Mbbl) | (MMcf) | (Mbbl) | (Mboe) | ||||
| Proved developed producing | 1930.9 | 861.3 | 21.8 | 2,096.3 | ||||
| Proved developed non-producing | 177.8 | 50.3 | 1.3 | 187.5 | ||||
| Proved undeveloped | 18.8 | 224.4 | 5.7 | 62.0 | ||||
| Total proved | 2,127.6 | 1,136.0 | 28.8 | 2,345.7 | ||||
| Probable | 2,020.6 | 688.5 | 17.4 | 2,152.8 | ||||
| Total proved plus probable | 4,148.2 | 1,824.5 | 46.3 | 4,498.5 | ||||
| (1) Columns and rows may not add due to rounding | ||||||||
| Before Income Tax | ||||||||
| Forecast Net Revenue(1) | $000s, discounted at | |||||||
| as at February 29, 2012 | 0% | 5% | 10% | 15% | ||||
| Proved developed producing | 98,811.7 | 88,534.7 | 80,476.4 | 74,005.6 | ||||
| Proved developed non-producing | 10923.7 | 10,082.8 | 9,379.9 | 8,782.2 | ||||
| Proved undeveloped | 2,292.5 | 1,455.2 | 987.6 | 701.8 | ||||
| Total proved | 112,027.9 | 100,072.7 | 90,843.9 | 83,489.7 | ||||
| Probable | 109,292.7 | 90,177.3 | 76,725.7 | 66,752.8 | ||||
| Total proved plus probable | 221,230.6 | 190,250.1 | 167,569.6 | 150,242.5 | ||||
| (1) Columns and rows may not add due to rounding | ||||||||
In analyzing the February 29, 2012 AJM Report it should be noted that:
Summary of Forecast Pricing
Future prices used in the forecast of net revenue are based on those estimated by AJM as at December 31, 2011. The following table sets forth the relevant portions of AJM's forecast of commodity prices and costs used in the AJM Evaluation:
| Natural Gas Liquids | ||||||||||||||||||
| Year | WTI Crude Oil ($US/BBL) |
Edmonton City Gate ($CDN/BBL) |
Natural Gas at AECO ($CDN/MCF) |
Edm. Propane ($CDN/BBL) |
Edm. Butane ($CDN/BBL) |
Edm. C5+ ($CDN/BBL) |
Currency Exchange Rate ($US/CDN) |
Price Inflation Rate (%) |
Cost Inflation Rate (%) |
|||||||||
| 2012 | 100.00 | 98.00 | 3.50 | 53.90 | 83.30 | 102.90 | 1.00 | 0.0 | 0.0 | |||||||||
| 2013 | 102.00 | 100.00 | 4.10 | 55.00 | 85.00 | 105.00 | 1.00 | 2.0 | 2.0 | |||||||||
| 2014 | 104.05 | 102.00 | 4.70 | 56.10 | 86.70 | 107.10 | 1.00 | 2.0 | 2.0 | |||||||||
| 2015 | 106.10 | 104.00 | 5.15 | 57.20 | 88.40 | 109.20 | 1.00 | 2.0 | 2.0 | |||||||||
| 2016 | 108.25 | 106.10 | 5.55 | 58.35 | 90.20 | 111.40 | 1.00 | 2.0 | 2.0 | |||||||||
| 2017 | 110.40 | 108.20 | 6.00 | 59.50 | 91.95 | 113.60 | 1.00 | 2.0 | 2.0 | |||||||||
| 2018 | 112.60 | 110.35 | 6.40 | 60.70 | 93.80 | 115.85 | 1.00 | 2.0 | 2.0 | |||||||||
| 2019 | 114.85 | 112.55 | 6.90 | 61.90 | 95.65 | 118.20 | 1.00 | 2.0 | 2.0 | |||||||||
| 2020 | 117.15 | 114.80 | 7.40 | 63.15 | 97.60 | 120.55 | 1.00 | 2.0 | 2.0 | |||||||||
| 2021 | 119.50 | 117.10 | 7.75 | 64.40 | 99.55 | 122.95 | 1.00 | 2.0 | 2.0 | |||||||||
| 2022 | 121.90 | 119.45 | 7.90 | 65.70 | 101.55 | 125.40 | 1.00 | 2.0 | 2.0 | |||||||||
| 2023 | 124.35 | 121.85 | 8.10 | 67.00 | 103.55 | 127.95 | 1.00 | 2.0 | 2.0 | |||||||||
| 2024 | 126.80 | 124.30 | 8.25 | 68.35 | 105.65 | 130.50 | 1.00 | 2.0 | 2.0 | |||||||||
| 2025 | 129.35 | 126.75 | 8.40 | 69.70 | 107.75 | 133.10 | 1.00 | 2.0 | 2.0 | |||||||||
| 2026 | 131.95 | 129.30 | 8.60 | 71.10 | 109.90 | 135.75 | 1.00 | 2.0 | 2.0 | |||||||||
| 2027 | 134.60 | 131.90 | 8.75 | 72.55 | 112.10 | 138.50 | 1.00 | 2.0 | 2.0 | |||||||||
| 2028 | 137.30 | 134.55 | 8.90 | 74.00 | 114.35 | 141.30 | 1.00 | 2.0 | 2.0 | |||||||||
| 2029 | 140.00 | 137.20 | 9.10 | 75.45 | 116.60 | 144.05 | 1.00 | 2.0 | 2.0 | |||||||||
| 2030 | 142.80 | 139.95 | 9.30 | 76.95 | 118.95 | 146.95 | 1.00 | 2.0 | 2.0 | |||||||||
| 2031 | 145.70 | 142.75 | 9.45 | 78.50 | 121.35 | 149.90 | 1.00 | 2.0 | 2.0 | |||||||||
| 2032 + |
2.0 % escalated |
2.0 % escalated |
2.0 % escalated |
2.0 % escalated |
2.0 % escalated |
2.0% escalated |
1.00 | 2.0 | 2.0 |
|||||||||
2012 Outlook
During calendar 2012 Exall intends to drill 18 wells, driving a capital budget of approximately $48.6 million, including $7.9 million for 51 sections of the permitted 86 section 3D Seismic program in the first quarter.
Exall anticipates that this program will add approximately 1,000 BOEPD, resulting in an annual production average of 2,000 BOEPD depending on operational timing, an 83% increase from Exall's 2011 annual average rate of 1,094 BOEPD.
Exall anticipates that this program will drive a cash flow from operations of approximately $36.5 million. This cash flow forecast is based upon realizing an average of $90.33 Cdn for Exall's oil and $4.01 for its gas. Royalties are expected to be in the range of 25.4% or $21.60 Cdn while operating costs are anticipated to be in the $10.00 per boe range giving Exall an anticipated Field Netback of $55.00 for fiscal 2012.
About Exall
Exall is a junior oil and gas company active in its business of oil and gas exploration, development and production from its properties in Alberta. Exall Energy is currently developing the new Mitsue area Marten Mountain discovery in north-central Alberta.
Exall Energy currently has 62,263,854 common shares outstanding. The Company's common shares are listed on the Toronto Stock Exchange under the trading symbol EE.
Reader Advisory
This news release contains forward-looking statements, which are subject to certain risks, uncertainties and assumptions, including those relating to results of operations and financial condition, capital spending, financing sources, commodity prices and costs of production. By their nature, forward-looking statements are subject to numerous risks and uncertainties that could significantly affect anticipated results in the future and, accordingly, actual results may differ materially from those predicted. A number of factors could cause actual results to differ materially from the results discussed in such statements, and there is no assurance that actual results will be consistent with them. Such factors include fluctuating commodity prices, capital spending and costs of production, and other factors described in the Company's most recent Annual Information Form under the heading "Risk Factors" which has been filed electronically by means of the System for Electronic Document Analysis and Retrieval ("SEDAR") located at www.sedar.com. Such forward-looking statements are made as at the date of this news release, and the Company assumes no obligation to update or revise them, either publicly or otherwise, to reflect new events, information or circumstances, except as may be required under applicable securities law.
For the purposes of calculating unit costs, natural gas has been converted to a barrel of oil equivalent (boe) using 6,000 cubic feet equal to one barrel (6:1), unless otherwise stated. The boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore boe may be misleading if used in isolation. This conversion conforms to the Canadian Securities Regulators' National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities.
PDF with caption: "Exall Energy Corporation announces February 29, 2012 third party reserves assessment and provides operational update ". PDF available at: http://stream1.newswire.ca/media/2012/03/06/20120306_C9960_DOC_EN_10772.pdf
Exall Energy Corporation
Frank S. Rebeyka
Vice Chairman
Tel: 403-815-6637
Roger N. Dueck
President & CEO
Tel: 403-237-7820 x 223
[email protected]
Warren F.E. Coles
VP - Finance & CFO
Tel: 403-237-7820 x 224
Please visit Exall Energy's website at: www.exall.com
Renmark Financial Communications Inc.
Maurice Dagenais: [email protected]
Florence Liberski : [email protected]
Tel.: (514) 939-3989 or (416) 644-2020
www.renmarkfinancial.com
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