CALGARY, Feb. 6, 2013 /CNW Telbec/ - Exall Energy Corporation ("Exall" or the "Company") (TSX:EE and TSX:EE.DB) is pleased to announce the results of its independent third party NI 51-101 compliant reserves assessment and provide an operational update concerning its Marten Mountain, Mitsue operating area. Exall's public filings can all be found at www.exall.com or www.sedar.com.
Highlights:
- January 28 to February 3, 2013 weekly Field Production Average of 1,409 BOEPD
- December 31, 2012 proved plus probable net present value per share of $1.69 (Before Tax, discounted at 10%) based on 66.6 million fully diluted shares
- December 31, 2012 company working interest reserves are 2,569.4 Mboe total proved, a 25% increase from December 31, 2011 (a 38% increase when factoring in the Jayar September 30, 2012 disposition), and 4,629.1 Mboe proved plus probable, a 1% increase from December 31, 2011 (an 8% increase when factoring in the Jayar September 30, 2012 disposition)
- The December 31, 2012 net present value of the proved plus probable reserves decreased 33% from December 31, 2011 to $112.5 million, discounted at 10 percent, forecast prices, before tax. This is reflective of the 35% decrease in the proved plus probable Unit Value received at December 31, 2012 of $36.09 from the December 31, 2011 Unit Value received of $55.21, a direct result of the change in the forecast pricing utilized by Deloitte in the December 31, 2012 reserve report from the December 31, 2011 reserve report.
- Reserve life index of 6.5 years total proved and 11.7 years proved plus probable based on the 2012 annual average production rate and year-end reserves, this represents an increase of 33% in the total proved reserve life index and a 6% increase in the proved plus probable reserve life index from December 31, 2011
- 2013 Capital Budget of $29.4 million
- Exall expects to drill up to 13.0 gross (9.40 net) wells during 2013, with two wells (1.51 net) having been spud so far in 2013
- Exall expects to generate a 2013 Cash Flow of $29.4 million and a 2013 average production rate of 1,500 - 1,700 boepd
Current Production
Production and Waterfloods
Exall's weekly average daily production from January 28th to February 3rd is approximately 1,409 boepd, an increase of 42% over the Q3 2012 production average of 991 boepd and an increase of 27% over the estimated 2012 fourth quarter production average of 1,106 boepd. This does not include production from the most recently drilled well which will be brought on stream towards the end of the first quarter of 2013.
The Company groups the Waterflood Approvals in the Marten Mountain area into three project areas; the South WF, Central WF and North WF. The production issues faced in these three project areas are being successfully addressed, as described below.
Reservoir conformance issues presented challenges in the south waterflood during 2012. Optimization efforts aimed at improving well performance and oil recovery appear to be having a positive effect. Polymer treatments were performed on two injection wells resulting in reduced water cuts in one adjacent well, along with an increase in oil production. Current production from the South WF area is 428 boepd (310 boepd net), an increase of 26% from 340 boepd (243 boepd net) through November, 2012.
The Central WF continues to improve as the result of well optimization and the installation of an Electric Submersible Pump (ESP) into the newest producing well. The new oil well, which was producing 165 boepd, is now producing at 406 boepd (292 boepd net). The Central WF project is currently producing 783 boepd (546 boepd net), an increase of 144% over the Q3 2012 average.
A water source well was drilled, completed and equipped during Q4 2012 and injection of water has begun in the North WF Approval area. Optimization efforts in the North WF and the addition of two producing wells has increased production from 375 boepd (253 boepd net) in August 2012 to an average of 794 boepd (541 boepd net) over the last week, an increase of 112%.
Exall Price Differentials
The Company's Marten Mountain oil production attracts a price based on the average of the daily settlement price of the NYMEX near month Light Sweet Crude Oil contract as it trades, excluding weekends / holidays, for the calendar month of production, plus the weighted average of the Net Energy Index and the NGX index for Light Sweet Crude Oil, plus the one month prior Enbridge Sweet WADF. This pricing is adjusted for battery quality, pipeline and terminaling fees of $5.00/m3, the then current Rainbow loss allowance and a Tunkline Tariff.
As a result, when comparing the Company's oil price received to the posted Edmonton Par Price on the Natural Resources Canada website (http://www.nrcan.gc.ca/energy/sources/petroleum-crude-prices/crude/1632), Exall received an average 2012 price differential of $1.22. Based on the $1.22 differential Exall forecasts that its January 2013 price received was $86.52 per barrel, at the delivery point.
2012 Reserve Report
Exall retained AJM / Deloitte Petroleum Consultants ("Deloitte") to conduct an independent evaluation of Exall's oil and gas reserves effective December 31, 2012, which was provided to Exall in an Evaluation Report dated February 05, 2013 (herein referred to as the "Deloitte Evaluation"). The oil and gas reserves and income projections were estimated by Deloitte 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 Deloitte 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, 2012. 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)
as at December 31, 2012 |
Light &
medium oil
(Mbbl) |
Natural
gas
(MMcf) |
NGL
(Mbbl) |
Total
(Mboe) |
| |
|
|
|
|
| Proved developed producing |
1,599.9 |
335.0 |
14.9 |
1,670.6 |
| Proved developed non-producing |
270.6 |
44.3 |
2.0 |
279.9 |
| Proved undeveloped |
595.0 |
112.8 |
5.0 |
618.8 |
| Total proved |
2,465.4 |
492.1 |
21.9 |
2,569.4 |
| Probable |
1,999.1 |
286.7 |
12.8 |
2,059.7 |
| Total proved plus probable |
4,464.5 |
778.8 |
34.7 |
4,629.1 |
| (1) Columns and rows may not add due to rounding |
| |
|
|
Before Income Tax
$000s, discounted at |
Forecast Net Revenue(1)
as at December 31, 2012 |
0% |
5% |
10% |
15% |
| |
|
|
|
|
| Proved developed producing |
64,531.8 |
57,599.4 |
52,154.9 |
47,782.1 |
| Proved developed non-producing |
7,094.6 |
5,721.0 |
4,681.1 |
3,876.4 |
| Proved undeveloped |
20,987.9 |
17,084.3 |
14,109.6 |
11,790.4 |
| Total proved |
92,614.3 |
80,404.7 |
70,945.7 |
63,448.9 |
| Probable |
71,555.2 |
53,701.8 |
41,588.0 |
32,977.3 |
| Total proved plus probable |
164,169.5 |
134,106.5 |
112,533.7 |
96,466.2 |
| (1) Columns and rows may not add due to rounding |
Summary of Unit Value Received
The Unit Value before income tax (discounted at 10%) is calculated by dividing the Net Present Value of Future Net Revenue before income tax (discounted at 10%) by the Working Interest After Royalty Reserves. For the December 31, 2012 Reserves Exall's Unit Value on total proved basis is $41.29, while the total proved plus probable Unit Value is $36.09. The represents a total proved Unit Value decrease of 26.75% from the December 31, 2011 total proved Unit Value of $56.37 and a proved plus probable Unit Value decrease of 34.63% from the December 31, 2011 proved plus probable Unit Value of $55.21.
This decrease is reflective of the change in the forecast pricing utilized by Deloitte in the December 31, 2012 reserve report from the December 31, 2011 reserve report.
Summary of Forecast Pricing
Future prices used in the forecast of net revenue are based on those estimated by Deloitte as at December 31, 2012. The following table sets forth the relevant portions of Deloitte's forecast of commodity prices and costs used in the Deloitte Evaluation:
| |
|
|
|
Natural Gas Liquids |
|
|
|
| Year |
WTI
Crude Oil
($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
(%) |
| 2013 |
$90.00 |
$85.00 |
$3.20 |
$46.75 |
$72.25 |
$89.25 |
1.00 |
0.0 |
0.0 |
| 2014 |
$89.75 |
$84.70 |
$3.75 |
$46.60 |
$72.00 |
$88.95 |
1.00 |
2.0 |
2.0 |
| 2015 |
$91.55 |
$89.45 |
$4.05 |
$49.20 |
$76.05 |
$93.90 |
1.00 |
2.0 |
2.0 |
| 2016 |
$93.40 |
$91.20 |
$4.35 |
$50.15 |
$77.50 |
$95.75 |
1.00 |
2.0 |
2.0 |
| 2017 |
$92.00 |
$89.80 |
$4.65 |
$49.40 |
$76.35 |
$94.30 |
1.00 |
2.0 |
2.0 |
| 2018 |
$93.85 |
$91.60 |
$5.10 |
$50.40 |
$77.85 |
$96.20 |
1.00 |
2.0 |
2.0 |
| 2019 |
$95.70 |
$93.40 |
$5.40 |
$51.35 |
$79.40 |
$98.05 |
1.00 |
2.0 |
2.0 |
| 2020 |
$97.65 |
$95.30 |
$5.75 |
$52.40 |
$81.00 |
$100.05 |
1.00 |
2.0 |
2.0 |
| 2021 |
$99.60 |
$97.20 |
$6.10 |
$53.45 |
$82.60 |
$102.05 |
1.00 |
2.0 |
2.0 |
| 2022 |
$101.60 |
$99.15 |
$6.45 |
$54.55 |
$84.30 |
$104.10 |
1.00 |
2.0 |
2.0 |
| 2023 |
$103.60 |
$101.10 |
$6.95 |
$55.60 |
$85.95 |
$106.15 |
1.00 |
2.0 |
2.0 |
| 2024 |
$105.70 |
$103.15 |
$7.10 |
$56.75 |
$87.70 |
$108.30 |
1.00 |
2.0 |
2.0 |
| 2025 |
$107.80 |
$105.20 |
$7.25 |
$57.85 |
$89.40 |
$110.45 |
1.00 |
2.0 |
2.0 |
| 2026 |
$109.95 |
$107.30 |
$7.35 |
$59.00 |
$91.20 |
$112.65 |
1.00 |
2.0 |
2.0 |
| 2027 |
$112.15 |
$109.45 |
$7.50 |
$60.20 |
$93.05 |
$114.90 |
1.00 |
2.0 |
2.0 |
| 2028 |
$114.40 |
$111.65 |
$7.65 |
$61.40 |
$94.90 |
$117.25 |
1.00 |
2.0 |
2.0 |
| 2029 |
$116.70 |
$113.85 |
$7.80 |
$62.60 |
$96.75 |
$119.55 |
1.00 |
2.0 |
2.0 |
| 2030 |
$119.00 |
$116.15 |
$8.00 |
$63.90 |
$98.75 |
$121.95 |
1.00 |
2.0 |
2.0 |
| 2031 |
$121.40 |
$118.45 |
$8.15 |
$65.15 |
$100.70 |
$124.35 |
1.00 |
2.0 |
2.0 |
| 2032 |
$123.85 |
$120.85 |
$8.30 |
$66.45 |
$102.70 |
$126.90 |
1.00 |
2.0 |
2.0 |
2033
+ |
2.0 %
escalated |
2.0 %
escalated |
2.0 %
escalated |
2.0 %
escalated |
2.0 %
escalated |
2.0%
escalated |
1.00 |
2.0 |
2.0 |
Reserve Reconciliation
| |
|
|
|
|
Reserve Reconciliation(1)
(Company Working Interest) |
Light &
medium oil
(Mstb) |
Natural
gas
(MMcf) |
NGL
(Mstb) |
Total
(Mboe) |
| |
|
|
|
|
| Proved |
|
|
|
|
| |
December 31, 2011 |
1,818.8 |
1,194.6 |
30.3 |
2,048.3 |
| |
Extensions & improved recovery |
1,500.1 |
230.7 |
10.3 |
1,548.8 |
| |
Technical revisions |
(475.9) |
(49.6) |
5.1 |
(479.1) |
| |
Economic Factors |
0.1 |
(18.6) |
(0.5) |
(3.5) |
| |
Acquisitions |
0.0 |
0.0 |
0.0 |
0.0 |
| |
Dispositions |
(34.1) |
(802.5) |
(20.5) |
(188.3) |
| |
Production |
(343.6) |
(62.5) |
(2.8) |
(356.8) |
| |
December 31, 2012 |
2,465.4 |
492.1 |
21.9 |
2,569.4 |
| |
|
|
|
|
| Probable |
|
|
|
|
| |
December 31, 2011 |
2,390.6 |
705.9 |
17.9 |
2,526.2 |
| |
Extensions & improved recovery |
463.4 |
1.6 |
0.1 |
463.8 |
| |
Technical revisions |
(832.8) |
23.0 |
6.1 |
(822.9) |
| |
Economic Factors |
(1.1) |
(16.9) |
(0.4) |
(4.3) |
| |
Acquisitions |
0.0 |
0.0 |
0.0 |
0.0 |
| |
Dispositions |
(21.0) |
(426.9) |
(10.9) |
(103.1) |
| |
Production |
0.0 |
0.0 |
0.0 |
0.0 |
| |
December 31, 2012 |
1,999.1 |
286.7 |
12.8 |
2,059.7 |
| |
|
|
|
|
| Proved plus Probable |
|
|
|
|
| |
December 31, 2011 |
4,209.5 |
1,900.6 |
48.2 |
4,574.5 |
| |
Extensions & improved recovery |
1,963.5 |
232.3 |
10.4 |
2,012.6 |
| |
Technical revisions |
(1,308.8) |
(26.6) |
11.3 |
(1,302.0) |
| |
Economic Factors |
(1.0) |
(35.6) |
(0.9) |
(7.8) |
| |
Acquisitions |
0.0 |
0.0 |
0.0 |
0.0 |
| |
Dispositions |
(55.1) |
(1,229.4) |
(31.5) |
(291.4) |
| |
Production |
(343.6) |
(62.5) |
(2.8) |
(356.8) |
| |
December 31, 2012 |
4,464.5 |
778.8 |
34.7 |
4,629.1 |
| (1) Columns and rows may not add due to rounding |
2013 Capital Program
The Company's Board of Directors has approved an exploration and development expenditures program of $29.4 million for 2013 (the "2013 Capital Budget"). The 2013 Capital Budget is expected to be self-financed by funds from operations and will be adjusted from time to time to reflect production and cash flow achievements.
The initial 2013 Capital Budget will encompass the continued, focused development of Exall's 66 - 73.5%-owned, Gilwood light sweet crude oil play. At Marten Mountain in Mitsue, Alberta, the Company plans to drill 13 gross (9.40 net) wells with 3.0 gross (2.16 net) exploration wells and 10 gross (7.24 net) development wells being drilled on the North 3D Seismic channel. The drilling and completion expenditure component of Exall's 2013 Capital Budget is projected to approximate $25.7 million, with remaining budgeted funds of approximately $3.75 million allocated towards investments in well-site equipment, field facilities, and gathering lines.
"I am very excited about the coming year. All the work we have focused on over the last half of 2012 has positioned us to make significant gains in 2013 through 2015," said Roger Dueck, President and Chief Executive Officer. "Exall's 2013 capital budget focuses investment on those projects which are expected to generate the highest returns and lead to near-term production and cash flow gains. Accelerating production and cash flows will further improve the company's financial strength to support our significant growth plans," said Dueck.
"Our production target for 2013 is approximately 45 percent above estimated 2012 volumes and we expect further increases that will double current rates in 2014″ said Dueck. "At the same time that we are driving towards higher production, efficiency improvements are expected to reduce operating costs to $10 to $12 per barrel in 2013 from our 2012 rates of $13.50 per barrel."
Based on the budgeted capital expenditures anticipated within the 2013 Capital Budget, average daily production for fiscal 2013 is projected to range between 1,500 - 1,700 boepd, weighted approximately 97% light sweet crude oil and NGLs and 3% natural gas. This forecasted production range represents a 39 - 57% increase over the Company's 2012 average daily production estimate.
Assuming the median of the forecasted average daily production range and utilizing 2013 pricing assumptions of US$85.00 per bbl for Edmonton Par oil, and AECO gas price of C$3.39 per gigajoule, the Company's funds from operations for 2013 is estimated at $0.44 per basic share or approximately $29.4 million in aggregate, which represents a significant increase of 78%, over projected 2012 funds from operations. Field operating netbacks for 2013 are forecasted at approximately $57 - $62/boe, as compared to the estimated $52.50/boe netback for 2012, reflecting the Company's successful ongoing development of its light sweet crude oil play at Mitsue, Alberta.
Based on the 2013 Capital Budget and projected funds from operations, Exall's year-end 2013 net debt is estimated at $59 million ($36.0 Million in Bank Debt plus $23.0 Million in Convertible Debentures due March 31, 2017) or approximately 2.0 times forecasted 2013 funds from operations.
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 66,634,854 common shares outstanding. The Company's common shares are listed on the Toronto Stock Exchange under the trading symbol EE. The Company's convertible debentures are listed on the Toronto Stock Exchange under the trading symbol EE.DB.
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 available at: http://stream1.newswire.ca/media/2013/02/06/20130206_C3384_DOC_EN_23351.pdf
PDF available at: http://stream1.newswire.ca/media/2013/02/06/20130206_C3384_DOC_EN_23353.pdf
SOURCE: EXALL ENERGY CORPORATION
For further information:
Exall Energy Corporation
Frank S. Rebeyka
Vice Chairman
Tel: 403-815-6637
Roger N. Dueck
President & CEO
Tel: 403-237-7820 x 223
info@exall.com
Please visit Exall Energy's website at: www.exall.com
Renmark Financial Communications Inc.
Maurice Dagenais: mdagenais@renmarkfinancial.com
Nadia Marks : nmarks@renmarkfinancial.com
Tel.: (416) 644-2020 or (514) 939-3989
www.renmarkfinancial.com
